Piedmont Natural Gas (PNY) 10-K 23 Dec 14 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Oct. 31, 2014	Dec. 12, 2014	Apr. 30, 2014
Document And Entity Information [Abstract]
Entity Registrant Name	PIEDMONT NATURAL GAS CO INC
Entity Central Index Key	78460
Current Fiscal Year End Date	-21
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	31-Oct-14
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		78,638,925
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$2,764,512,081
Trading Symbol	PNY

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Oct. 31, 2014	Oct. 31, 2013
In Thousands, unless otherwise specified
Utility Plant:
Utility plant in service	$5,011,497	$4,421,937
Less accumulated depreciation	1,166,922	1,088,331
Utility plant in service, net	3,844,575	3,333,606
Construction work in progress	141,693	297,717
Plant held for future use	3,155	3,155
Total utility plant, net	3,989,423	3,634,478
Other Physical Property, at cost (net of accumulated depreciation of $904 in 2014 and $876 in 2013)	355	382
Current Assets:
Cash and cash equivalents	9,643	8,063
Trade accounts receivable (less allowance for doubtful accounts of $2,152 in 2014 and $1,604 in 2013)	65,260	79,210
Income taxes receivable	36,100	31,065
Other receivables	3,361	1,988
Unbilled utility revenues	21,093	24,967
Inventories:
Gas in storage	84,081	73,929
Materials, supplies and merchandise	1,652	1,725
Gas purchase derivative assets, at fair value	4,898	1,834
Regulatory assets	29,088	77,204
Prepayments	39,030	35,038
Deferred income taxes	53,418	12,695
Other current assets	326	338
Total current assets	347,950	348,056
Noncurrent Assets:
Equity method investments in non-utility activities	170,171	128,469
Goodwill	48,852	48,852
Regulatory assets	184,779	169,102
Marketable securities, at fair value	3,727	2,995
Overfunded postretirement asset	33,757	28,258
Other noncurrent assets	5,239	8,017
Total noncurrent assets	446,525	385,693
Total	4,784,253	4,368,609
Stockholders’ equity:
Cumulative preferred stock - no par value - 175 shares authorized	0	0
Common stock – no par value – shares authorized: 200,000; shares outstanding: 78,531 in 2014 and 76,099 in 2013	636,835	561,644
Retained earnings	672,004	627,236
Accumulated other comprehensive loss	-237	-284
Total stockholders’ equity	1,308,602	1,188,596
Long-term debt	1,424,430	1,174,857
Total capitalization	2,733,032	2,363,453
Current Liabilities:
Current maturities of long-term debt	0	100,000
Short-term debt	355,000	400,000
Trade accounts payable	85,299	96,281
Other accounts payable	54,349	43,855
Accrued interest	27,982	28,205
Customers’ deposits	19,994	19,831
General taxes accrued	23,828	21,454
Regulatory liabilities	46,231	0
Other current liabilities	9,303	7,024
Total current liabilities	621,986	716,650
Noncurrent Liabilities:
Deferred income taxes	809,467	681,369
Unamortized federal investment tax credits	1,193	1,402
Accumulated provision for postretirement benefits	15,471	12,042
Regulatory liabilities	558,598	541,897
Conditional cost of removal obligations	14,647	27,016
Other noncurrent liabilities	29,859	24,780
Total noncurrent liabilities	1,429,235	1,288,506
Commitments and Contingencies
Total	$4,784,253	$4,368,609

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parentheticals) (USD $)	Oct. 31, 2014	Oct. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Other Physical Property accumulated depreciation	$904	$876
Trade Accounts Receivable, allowance for doubtful accounts	$2,152	$1,604
Preferred Stock, No Par Value	$0	$0
Preferred Stock, Shares Authorized	175,000	175,000
Common Stock, No Par Value	$0	$0
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Outstanding	78,531,000	76,099,000

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Statement of Comprehensive Income [Abstract]
Operating Revenues	$1,469,988	$1,278,229	$1,122,780
Cost of Gas	779,780	656,739	547,334
Margin	690,208	621,490	575,446
Operating Expenses:
Operations and maintenance	270,877	253,120	242,599
Depreciation	118,996	112,207	103,192
General taxes	37,294	34,635	34,831
Utility income taxes	83,176	77,334	69,101
Total operating expenses	510,343	477,296	449,723
Operating Income	179,865	144,194	125,723
Other Income (Expense):
Income from equity method investments	32,753	26,056	23,904
Non-operating income	1,842	2,839	1,288
Non-operating expense	-4,331	-5,122	-1,855
Income taxes	-11,642	-8,612	-9,116
Total other income (expense)	18,622	15,161	14,221
Utility Interest Charges:
Interest on long-term debt	61,562	54,158	41,412
Allowance for borrowed funds used during construction	-16,427	-30,975	-25,211
Other	9,551	1,755	3,896
Total utility interest charges	54,686	24,938	20,097
Net Income	143,801	134,417	119,847
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $225, ($69) and ($530) for the years ended October 31, 2014, 2013 and 2012, respectively	355	-109	-826
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($177), $85 and $621 for the years ended October 31, 2014, 2013 and 2012, respectively	-284	130	973
Net current period benefit activities of equity method investments, net of tax of ($16) for the year ended October 31, 2014	-24
Total other comprehensive income	47	21	147
Comprehensive Income	$143,848	$134,438	$119,994
Average Shares of Common Stock:
Basic (in shares)	77,883	74,884	71,977
Diluted (in shares)	78,193	75,333	72,278
Earnings Per Share of Common Stock:
Basic (usd per share)	$1.85	$1.80	$1.67
Diluted (usd per share)	$1.84	$1.78	$1.66

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Parentheticals) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Statement of Comprehensive Income [Abstract]
Unrealized gain (loss) from hedging activities of equity method investments arising during period tax	$225	($69)	($530)
Reclassification adjustment of realized gain (loss) from hedging activities of equity investments included in net income, tax	-177	85	621
Net current period benefit activities of equity method investments, tax	($16)

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Cash Flows from Operating Activities:
Net income	$143,801	$134,417	$119,847
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	129,343	120,797	109,230
Allowance for doubtful accounts	548	25	232
Impairment loss on investment	2,000	0	0
Net gain on sale of property	-817	-349	0
Income from equity method investments	-32,753	-26,056	-23,904
Distributions of earnings from equity method investments	24,843	22,139	19,590
Deferred income taxes, net	87,136	57,637	99,159
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	-3,064	1,319	-381
Receivables	16,196	-23,327	5,403
Inventories	-10,079	-2,059	18,897
Settlement of legal asset retirement obligations	-3,575	-2,389	-2,038
Regulatory assets	20,297	43,338	-93,268
Other assets	-2,829	4,629	-2,314
Accounts payable	18	2,381	4,283
Provision for postretirement benefits, net	-2,070	-53,515	45,507
Regulatory liabilities	49,468	23,429	-2,990
Other liabilities	12,149	10,831	7,262
Net cash provided by operating activities	430,612	313,247	304,515
Cash Flows from Investing Activities:
Utility capital expenditures	-460,444	-599,999	-529,576
Allowance for borrowed funds used during construction	-16,427	-30,975	-25,211
Contributions to equity method investments	-37,642	-41,348	-3,566
Distributions of capital from equity method investments	3,929	4,700	5,372
Proceeds from sale of property	1,883	1,951	1,250
Investments in marketable securities	-454	-414	-606
Other	4,708	2,609	3,044
Net cash used in investing activities	-504,447	-663,476	-549,293
Cash Flows from Financing Activities:
Borrowings under credit facility	0	10,000	350,000
Repayments under credit facility	0	-10,000	-681,000
Net (repayments) borrowings - commercial paper	-45,000	35,000	365,000
Proceeds from issuance of long-term debt, net of discount	249,565	299,856	300,000
Repayment of long-term debt	-100,000	0	0
Expenses related to issuance of debt	-2,871	-3,250	-3,908
Proceeds from issuance of common stock, net of expenses	47,290	92,271	0
Issuance of common stock through dividend reinvestment and employee stock plans	25,556	24,610	22,123
Repurchases of common stock	0	0	-26,528
Dividends paid	-99,151	-92,146	-85,693
Other	26	-8	-34
Net cash provided by financing activities	75,415	356,333	239,960
Net Increase (Decrease) in Cash and Cash Equivalents	1,580	6,104	-4,818
Cash and Cash Equivalents at Beginning of Year	8,063	1,959	6,777
Cash and Cash Equivalents at End of Year	9,643	8,063	1,959
Cash Paid During the Year for:
Interest	64,276	50,275	44,571
Income Taxes:
Income taxes paid	10,840	5,760	4,770
Income taxes refunded	30	169	8,437
Income taxes, net	10,810	5,591	-3,667
Noncash Investing and Financing Activities:
Accrued construction expenditures	$38,869	$39,389	$43,643

Consolidated_Statements_Of_Sto

Consolidated Statements Of Stockholders' Equity (USD $)	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
In Thousands, unless otherwise specified
Stockholders' Equity, beginning balance at Oct. 31, 2011	$996,923	$446,791	$550,584	($452)
Comprehensive Income:
Net income	119,847		119,847
Other comprehensive income	147			147
Comprehensive Income	119,994
Common Stock Issued	22,198	22,198
Common Stock Repurchased	-26,528	-26,528
Tax Benefit from Dividends Paid on ESOP Shares	110		110
Dividends Declared	-85,693		-85,693
Stockholders' Equity, ending balance at Oct. 31, 2012	1,027,004	442,461	584,848	-305
Comprehensive Income:
Net income	134,417		134,417
Other comprehensive income	21			21
Comprehensive Income	134,438
Common Stock Issued	119,552	119,552
Expenses from Issuance of Common Stock	-369	-369
Tax Benefit from Dividends Paid on ESOP Shares	117		117
Dividends Declared	-92,146		-92,146
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	-284
Stockholders' Equity, ending balance at Oct. 31, 2013	1,188,596	561,644	627,236	-284
Comprehensive Income:
Net income	143,801		143,801
Other comprehensive income	47			47
Comprehensive Income	143,848
Common Stock Issued	75,203	75,203
Expenses from Issuance of Common Stock	-12	-12
Tax Benefit from Dividends Paid on ESOP Shares	118		118
Dividends Declared	-99,151		-99,151
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	-213
Benefit activities of equity method investments	-24
Stockholders' Equity, ending balance at Oct. 31, 2014	$1,308,602	$636,835	$672,004	($237)

Recovered_Sheet1

Consolidated Statements of Stockholders Equity (Parentheticals) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$1.27	$1.23	$1.19

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Oct. 31, 2014
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Summary of Significant Accounting Policies
	Nature of Operations and Basis of Consolidation
	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, regulated interstate natural gas transportation and storage and regulated 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. 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. For further information on equity method investments and related party transactions, see Note 12 to the consolidated financial statements.
	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.
	Use of Estimates
	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, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.
	Segment Reporting
	Our segments are based on the components of the Company for which we produce separate financial information internally that is used 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 (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from and our cash flows in the ventures.
	Beginning with the fourth quarter of 2014, we have three reportable business segments, regulated utility, regulated non-utility activities and unregulated 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 service agreements, with activities conducted by the utility. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included. See Note 14 to the consolidated financial statements for further discussion of segments.
	Rate-Regulated Basis of Accounting
	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. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.
	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 or accumulated other comprehensive income (OCI). 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, 2014 and 2013 are as follows.
	In thousands	2014			2013
	Regulatory Assets:
	Current:
	Unamortized debt expense	$	1,490		$	1,274
	Amounts due from customers	16,108			66,321
	Environmental costs	1,568			1,480
	Deferred operations and maintenance expenses	916			739
	Deferred pipeline integrity expenses	3,470			3,149
	Deferred pension and other retirement benefits costs	2,769			2,768
	Robeson liquefied natural gas (LNG) development costs	917			382
	Other	1,850			1,091
	Total current	29,088			77,204
	Noncurrent:
	Unamortized debt expense	15,402			14,149
	Environmental costs	6,470			7,936
	Deferred operations and maintenance expenses	4,721			5,637
	Deferred pipeline integrity expenses	24,694			16,300
	Deferred pension and other retirement benefits costs	18,799			17,968
	Amounts not yet recognized as a component of pension and other retirement benefit costs	94,265			80,604
	Regulatory cost of removal asset	18,275			22,974
	Robeson LNG development costs	509			1,426
	Other	1,644			2,108
	Total noncurrent	184,779			169,102
	Total	$	213,867		$	246,306
	Regulatory Liabilities:
	Current:
	Amounts due to customers	$	46,231		$	—
	Noncurrent:
	Regulatory cost of removal obligations	506,574			493,111
	Deferred income taxes	51,930			48,647
	Amounts not yet recognized as a component of pension and other retirement costs	94			139
	Total noncurrent	558,598			541,897
	Total	$	604,829		$	541,897
	As of October 31, 2014, we have $18.3 million of asset retirement obligations (AROs) and $98.1 million of other regulatory assets 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 and Depreciation
	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, 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 costs 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, 2014 and 2013 is presented below.
	In thousands	2014			2013
	Intangible plant	$	3,374		$	3,374
	Other storage plant	180,058			171,349
	Transmission plant	1,787,990			1,403,829
	Distribution plant	2,623,560			2,505,160
	General plant	421,763			335,847
	Asset retirement cost	11			7,565
	Contributions in aid of construction	(5,259		)	(5,187		)
	Total utility plant in service	5,011,497			4,421,937
	Less accumulated depreciation	(1,166,922		)	(1,088,331		)
	Total utility plant in service, net	3,844,575			3,333,606
	Construction work in progress	141,693			297,717
	Plant held for future use	3,155			3,155
Total utility plant, net	$	3,989,423		$	3,634,478
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, 2014, 2013 and 2012, all of our AFUDC was attributable to borrowed funds.
AFUDC for the years ended October 31, 2014, 2013 and 2012 is presented below.
In thousands	2014			2013			2012
AFUDC	$	16,427		$	30,975		$	25,211
In accordance with utility accounting practice, we classified real estate and development costs associated with a LNG peak storage facility in the eastern part of North Carolina as “Plant held for future use” in the Consolidated Balance Sheets, due to construction being suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 38 months beginning January 1, 2014 through February 2017. Under the settlement of our June 2014 rate stabilization adjustment (RSA) filing with the Public Service Commission of South Carolina (PSCSC) that was approved in October 2014, we agreed to the amortization and collection of $.5 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 12 months beginning November 1, 2014. We recorded cumulative amortization of $1.8 million of non-real estate costs in fiscal year 2013 that is included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on the 2013 general rate proceeding settlement of these costs for North Carolina or the 2014 RSA filing for South Carolina, see Note 2 to the consolidated financial statements.
We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted-average depreciation rates were 2.54% for 2014, 2.77% for 2013 and 2.94% for 2012.
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, March 1, 2012 for Tennessee and January 1, 2014 for North Carolina.
As authorized by our regulatory commissions, 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 collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in this Note 1. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.
Cash and Cash Equivalents
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, 2014 and 2013.
Trade Accounts Receivable and Allowance for Doubtful Accounts
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 NCUC, the 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 buy and 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 policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, 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. In order to minimize our exposure, 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, 2014 and 2013, our trade accounts receivable consisted of the following.
In thousands	2014			2013
Gas receivables	$	64,400		$	78,540
Non-regulated merchandise and service work receivables	3,012			2,274
Allowance for doubtful accounts	(2,152		)	(1,604		)
Trade accounts receivable	$	65,260		$	79,210
A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2014, 2013 and 2012 is presented below.
In thousands	2014			2013			2012
Balance at beginning of year	$	1,604		$	1,579		$	1,347
Additions charged to uncollectibles expense	6,959			5,314			4,584
Accounts written off, net of recoveries	(6,411		)	(5,289		)	(4,352		)
Balance at end of year	$	2,152		$	1,604		$	1,579
Inventories
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 enter into service contracts, or asset management arrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we may assign the gas supply and/or storage inventory and release the transportation capacity and storage capacity to the asset manager for the term of the agreement. The inventory is assigned at no cost, and the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in the inventories section as “Gas in storage.” From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,” and the inventory that is available for our use remains in “Gas in storage.”
At October 31, 2014 and 2013, such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of $35 million and $31.5 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The AMAs expire at various times through March 31, 2017. 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.
Fair Value Measurements
We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that 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 that is significant to the fair value measurement, in its entirety, in 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 marketplace. 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, common trust funds, 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 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, Equity Method Investments and Long-Lived Assets
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, 2014, and we determined that there was no impairment to the carrying value of our goodwill. No impairment was recognized during the years ended October 31, 2014, 2013 and 2012. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.
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. In April 2014, we recorded a $2 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Non-operating expense" in the Consolidated Statements of Comprehensive Income. There were no events or circumstances during the years ended October 31, 2013 and 2012 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.
Marketable Securities
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 deemed 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, 2014 and 2013 is as follows.
	2014						2013
In thousands	Cost			Fair Value			Cost			Fair Value
Current trading securities:
Money markets	$	22		$	22		$	—		$	—
Mutual funds	106			192			134			199
Total current trading securities	128			214			134			199
Noncurrent trading securities:
Money markets	447			447			380			380
Mutual funds	2,598			3,280			1,995			2,615
Total noncurrent trading securities	3,045			3,727			2,375			2,995
Total trading securities	$	3,173		$	3,941		$	2,509		$	3,194
Unamortized Debt Expense
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 with 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 it 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.
Issuances and Repurchases of Common Stock
As discussed in Note 6 to the consolidated financial statements, from time to time we may repurchase shares on the open market and such shares are then canceled 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.
Asset Retirement Obligations
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 conditional AROs exist for our underground mains and services.
We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. 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. For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation” in this Note 1.
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 of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory 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 4.40% to 5.15% with a weighted average of 5.09% for the twelve months ended October 31, 2014. 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, 2014 and 2013 are presented below.
In thousands	2014			2013
Regulatory non-legal AROs	$	506,574		$	493,111
Conditional AROs	14,647			27,016
Total cost of removal obligations	$	521,221		$	520,127
A reconciliation of the changes in conditional AROs for the year ended October 31, 2014 and 2013 is presented below.
In thousands	2014			2013
Beginning of period	$	27,016		$	28,629
Liabilities incurred during the period	2,108			2,052
Liabilities settled during the period	(3,576		)	(2,389		)
Accretion	1,548			1,641
Adjustment to estimated cash flows	(12,449		)	(2,917		)
End of period	$	14,647		$	27,016
Revenue Recognition
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 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 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 weather and consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, a RSA tariff mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. 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, and in Tennessee, the months of April and October. The WNA mechanisms are designed to partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism.
We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was approved in December 2013 in the settlement of our 2013 general rate case. Under the North Carolina IMR tariff, we will make annual filings by November 30 of each year for costs closed to plant through October with revised rates effective the following February 1. The Tennessee IMR tariff was approved in December 2013 with the settlement of our August 2013 IMR filing. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. For further discussion of the IMRs, see Note 2 to the consolidated financial statements.
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.
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.
Cost of Gas and Deferred Purchased Gas Adjustments
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 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, such that no operating margin is recognized related to these costs, are deferred and included in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. 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.
Taxes
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.
Consolidated Statements of Cash Flows
With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.
Recently Issued Accounting Guidance
In July 2013, the Financial Accounting Standards Board (FASB) issued accounting guidance on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist. The guidance was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2013, with early adoption permitted. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.
In May 2014, the FASB and the International Accounting Standards Board issued converged accounting guidance on the recognition of revenue from contracts with customers. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those periods, which for us is our fiscal year 2018.
An accounting utility subgroup has identified five issues (scope for cost-of-service-tariff sales, contract modifications, variable consideration, multiple element arrangements and sales of real estate) that are not clear within the standard and require revenue implementation guidance. The revenue implementation guide is expected to be published prior to the standard becoming effective in 2017; however, no date has been set.
We are currently evaluating the effect on our financial position, results of operations and cash flows. The evaluation includes identifying revenues streams by like contracts to allow for ease of implementation once the utility sub-group has issued the revenue implementation guide.
In June 2014, the FASB amended accounting guidance to eliminate certain financial reporting requirements for development stage entities, including an amendment to variable interest entity (VIE) guidance. The modification to the guidance may change the consolidation analysis, consolidation decision and disclosure requirements for a reporting entity that has an interest in an entity in the development stage. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2015, with early adoption permitted. We will consider this guidance regarding our current joint venture investments where the investment infrastructure is under development and any future investments that are development stage projects, particularly any disclosures about risks and uncertainties of the development of the project and our equity method investment.
In August 2014, the FASB issued accounting guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity must provide certain disclosures if there is a "substantial doubt about the entity's ability to continue as a going concern." The standard is effective for annual periods ending after December 15, 2016, and interim periods thereafter; early adoption is permitted. The adoption of this assessment will have no impact on our financial position, results of operations or cash flows.
Reclassifications and Changes in Presentation
Reclassifications have been made to certain prior year financial statements to conform with the current year presentation. Within “Cash Flows From Operating Activities” in the Consolidated Statements of Cash Flows, we have changed the presentation of cash flows from regulatory assets and liabilities, previously included within the line items “Other assets” and “Other liabilities,” respectively, to provide additional detail and to present such information within separate line items, “Regulatory assets” and “Regulatory liabilities.”  The 2013 and 2012 presentation has been changed to conform to the current year presentation. The reclassifications had no effect on previously reported amounts for net cash flows from operating, investing or financing activities.

Regulatory_Matters

Regulatory Matters	12 Months Ended
	Oct. 31, 2014
Public Utilities, Rate Matters [Abstract]
Public Utilities Disclosure [Text Block]	Regulatory Matters
	Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.
	The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.
	North Carolina
	The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.
	The NCUC had allowed EasternNC to defer its O&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9 million at October 31, 2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 6.55% per annum with amortization beginning January 1, 2014 over an 82-month period ending October 31, 2020. As of October 31, 2014 and 2013, we had unamortized balances, including accrued interest, of $5.6 million and $6.4 million, respectively.
	We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to certain incremental pipeline integrity external expenditures beginning November 1, 2004. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding discussed below was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2014 and 2013, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $28.2 million and $19.4 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs will continue until another recovery mechanism is established in a future rate proceeding.
	With the approval of the settlement of the 2013 NCUC general rate proceeding discussed below, future capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR. The settlement also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018.
	In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Our gas costs have never been disallowed on the basis of prudence.
	In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the NCUC Public Staff’s audit of the 2011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
	In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
	In November 2013, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2013. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
	In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
	Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued January 2012, November 2012, November 2013 and November 2014 found our hedging activities during the review periods to be reasonable and prudent.
	In October 2012, we filed a petition with the NCUC seeking authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In April 2013, we withdrew the petition, citing our intent to address the matter in a general rate application. The appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.
	In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:
	•	Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10% and an overall rate of return of 7.51%.
	•	Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.
	•	Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.
	•	Implementation of lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.
	•	Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.
	•	Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.
	•	Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.
	•	Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.
	In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provides for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. On February 5, 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.
	In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014, the NCUC issued an order rejecting the joint stipulation of settlement, finding that we must bill our customers for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further requires us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.
	In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. For further information on this shelf registration statement, see Note 4 to the consolidated financial statements.
	South Carolina
	We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.
	In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012.
	In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2012 order. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.
	In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2013 order. In October 2014, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina as discussed above, both with amortization periods of one year beginning November 2014 and ending October 2015.
	In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.
	The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates. In an August 2011 order, the PSCSC approved a stipulation that our hedging program should no longer have a required minimum volume of hedging.
	In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.
	In August 2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2013.
	In August 2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2014.
	In July 2014, we filed a petition with the PSCSC requesting a limited waiver of certain billing provisions of our tariff related to emergency service for customers in January 2014. In August 2014, the PSCSC granted our request and ordered us to continue to collaborate with the ORS to revise our tariff to address the situation that led to this petition.
	Tennessee
	In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in O&M expenses. The written order was issued by the TRA in June 2012.
	In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.
	In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.
	In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.
	In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA approved the TIP account balances. The TRA issued its written order approving our TIP account balances in March 2013.
	In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2013, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in March 2013.
	In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.
	In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under the TIP. In February 2014, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.
	In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. We are waiting on a ruling from the TRA at this time.
	In August 2013, we filed an ACA petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the ACA annual report filed in December 2014 for the twelve-month period ended June 30, 2013, as described above.
	In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, proposed to be effective March 1, 2012. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. In December 2011, we and the CAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA’s written order was issued in April 2012.
	As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for deferred accounting treatment in October 2010. These deferred expenses are being amortized over eight years beginning March 1, 2012 through February 2020.
	In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the CAD filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the TRA at this time.
	In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waiting on a ruling from the TRA at this time.
	In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015. A hearing on this matter has been scheduled for January 12, 2015.
	All States
	Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. In all three jurisdictions for the twelve months ended October 31, 2014, we generated $97.6 million of margin from secondary market activity, $72.2 million of which is allocated to customers as gas cost reductions and $25.4 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2013, we generated $35.9 million of margin from secondary market activity, $26.9 million of which is allocated to customers as gas cost reductions and $9 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us.
	We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Oct. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Share [Text Block]	Earnings Per Share
	We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.
	A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands, except per share amounts	2014		2013		2012
	Net Income	$	143,801	$	134,417	$	119,847
	Average shares of common stock outstanding for basic earnings per share	77,883		74,884		71,977
	Contingently issuable shares under incentive compensation plans	310		289		301
	Contingently issuable shares under forward sale agreements	—		160		—
	Average shares of dilutive stock	78,193		75,333		72,278
	Earnings Per Share of Common Stock:
	Basic	$	1.85	$	1.8	$	1.67
	Diluted	$	1.84	$	1.78	$	1.66

Long_Term_Debt

Long Term Debt	12 Months Ended
	Oct. 31, 2014
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	Long-Term Debt
	Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2014 and 2013 is as follows.
	In thousands		2014		2013
	Senior Notes:
	2.92%, due June 6, 2016		$	40,000	$	40,000
	8.51%, due September 30, 2017		35,000		35,000
	4.24%, due June 6, 2021		160,000		160,000
	3.47%, due July 16, 2027		100,000		100,000
	3.57%, due July 16, 2027		200,000		200,000
	4.10%, due September 18, 2034		250,000		—
	4.65%, due August 1, 2043		300,000		300,000
	Medium-Term Notes:
	5.00%, due December 19, 2013		—		100,000
	6.87%, due October 6, 2023		45,000		45,000
	8.45%, due September 19, 2024		40,000		40,000
	7.40%, due October 3, 2025		55,000		55,000
	7.50%, due October 9, 2026		40,000		40,000
	7.95%, due September 14, 2029		60,000		60,000
	6.00%, due December 19, 2033		100,000		100,000
	Total		1,425,000		1,275,000
	Less current maturities		—		100,000
	Less discount on issuance of notes *		570		143
	Total		$	1,424,430	$	1,174,857
	* The discount on the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.
	Current maturities for the next five years ending October 31 and thereafter are as follows.
	In thousands
	2015	$	—
	2016	40,000
	2017	35,000
	2018	—
	2019	—
	Thereafter	1,350,000
	Total	$	1,425,000
	We had an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that was available for future use until its expiration date of July 6, 2014. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements.
	On August 1, 2013, we issued $300 million of thirty-year, unsecured senior notes with an interest rate of 4.65% and at a discount of .048% or $144,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to February 1, 2043, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after February 1, 2043, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.2 million from this issuance to finance capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term notes under our unsecured commercial paper (CP) program and for general corporate purposes.
	In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC has approved debt and equity issuances under this shelf registration statement up to $1 billion during its three-year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.
	On September 18, 2014, we issued $250 million of twenty-year, unsecured senior notes with an interest rate of 4.10% and at a discount of .174% or $435,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to March 18, 2034, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after March 18, 2034, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $247.7 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
	The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31, 2014, our net earnings available for restricted payments were $1.1 billion.
	We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements. As of October 31, 2014, we are in compliance with all default provisions.
	The default provisions of some or all of our senior debt include:
	•	Failure to make principal or interest payments,
	•	Bankruptcy, liquidation or insolvency,
	•	Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
	•	Specified events under the Employee Retirement Income Security Act of 1974,
	•	Change in control, and
	•	Failure to observe or perform covenants, including:
	•	Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;
	•	Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;
	•	Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;
	•	Restrictions on permitted liens;
	•	Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
	•	Restrictions on burdensome agreements.

Short_Term_Debt

Short Term Debt	12 Months Ended
	Oct. 31, 2014
Line of Credit Facility [Abstract]
Short-term Debt [Text Block]	Short-Term Debt Instruments
	We have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million, of which $1.8 million and $2.1 million were issued and outstanding at October 31, 2014 and 2013, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. See Note 4 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements.
	We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.
	As of October 31, 2014, we had $355 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets, with original maturities ranging from 4 to 28 days from their dates of issuance at a weighted average interest rate of .17%. As of October 31, 2013, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $400 million at a weighted average interest rate of .36%.
	We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2014. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2014 is as follows
	In thousands
	Minimum amount outstanding	$	275,000
	Maximum amount outstanding	$	625,000
	Minimum interest rate	0.1		%
	Maximum interest rate	0.43		%
	Weighted average interest rate	0.19		%
	Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at October 31, 2014.

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Oct. 31, 2014
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Stockholders’ Equity
	Capital Stock
	Changes in common stock for the years ended October 31, 2014, 2013 and 2011 are as follows.
	In thousands		Shares			Amount
	Balance, October 31, 2011		72,318			$	446,791
	Issued to participants in the Employee Stock Purchase Plan (ESPP)		30			894
	Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)		677			20,508
	Issued to participants in the Incentive Compensation Plan (ICP)		25			796
	Shares repurchased under Accelerated Share Repurchase (ASR) agreement		(800	)		(26,528		)
	Balance, October 31, 2012		72,250			442,461
	Issued to ESPP		33			1,056
	Issued to DRIP		720			22,791
	Issued to ICP		96			3,065
	Issuance of common stock through public share offering, net of underwriting fees		3,000			92,640
	Costs from issuance of common stock		—			(369		)
	Balance, October 31, 2013		76,099			561,644
	Issued to ESPP		34			1,143
	Issued to DRIP		698			23,443
	Issued to ICP		100			3,315
	Issuance of common stock through forward sale agreements, net of expenses		1,600			47,290
	Balance, October 31, 2014		78,531			$	636,835
	In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are canceled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.
	On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved at that time an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.
	On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.
	The remaining 1.6 million shares under this same underwriting agreement were under forward sale agreements (FSAs) with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid-December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements.
	On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. We recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
	In accordance with ASC 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control. As a result of this classification, no amounts were recorded in the consolidated financial statements until settlement of each FSA.
	Upon physical settlement of the FSAs, delivery of our shares resulted in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.
	On January 4, 2012, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $33.77 per share. The settlement and retirement of those shares occurred on January 5, 2012. Total consideration paid to purchase the shares of $27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the Consolidated Balance Sheets.
	As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.09 per share discount, was higher than the January 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on February 28, 2012, we received $.5 million from the investment bank and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets. The $.5 million was the difference between the investment bank’s weighted average purchase price of $33.25 per share less a discount of $.09 per share for a settlement price of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares. We had an ASR transaction in 2011 as presented in the table above with a similar structure with the investment bank, which was accounted for in the same manner.
	As of October 31, 2014, our shares of common stock were reserved for issuance as follows.
	In thousands
	ESPP	176
	DRIP	840
	ICP	950
	Total	1,966
	Other Comprehensive Income (Loss)
	Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 12 to the consolidated financial statements. Beginning in 2014, another component of our accumulated OCIL is the allocation of retirement benefits to SouthStar Energy Services, LLC (SouthStar) by its majority member. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2014 and 2013.
	Changes in Accumulated OCIL (1)
	In thousands		2014				2013
	Accumulated OCIL beginning balance, net of tax		$	(284	)		$	(305	)
	Hedging activities of equity method investments:
	OCIL before reclassifications, net of tax		355				(109		)
	Amounts reclassified from accumulated OCIL, net of tax		(284		)		130
	Total current period activity of hedging activities of equity method investments, net of tax		71				21
	Net current period benefit activities of equity method investments, net of tax		(24		)
	Accumulated OCIL ending balance, net of tax		$	(237	)		$	(284	)
	(1) Amounts in parentheses indicate debits to accumulated OCIL.
	A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2014 and 2013.
			Reclassification Out of
			Accumulated OCIL (1)
			Years Ended
			31-Oct							Affected Line Items on Statement of
	In thousands		2014				2013			Comprehensive Income
	Hedging activities of equity method investments		$	(461	)		$	215		Income from equity method investments
	Income tax expense		177				(85		)	Income taxes
	Hedging activities of equity method investments		(284		)		$	130
	Net benefit activities of equity method investments		(40		)					Income from equity method investments
	Income tax expense		16							Income taxes
	Net benefit activities of equity method investments		(24		)
	Total reclassification for the period, net of tax		$	(308	)		$	130
	(1) Amounts in parentheses indicate debits to accumulated OCIL.

Financial_Instruments_Related_

Financial Instruments & Related Fair Value Financial Instruments & Related Fair Value (Notes)	12 Months Ended
	Oct. 31, 2014
Financial Instruments & Related Fair Value [Abstract]
Financial Instruments Disclosure [Text Block]	Financial Instruments and Related Fair Value
	Derivative Assets and Liabilities under Master Netting Arrangements
	We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2014 and 2013, we had long gas purchase options providing total coverage of 29.2 million dekatherms and 25.4 million dekatherms, respectively. The long gas purchase options held at October 31, 2014 are for the period from December 2014 through November 2015.
	Fair Value Measurements
	We use financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.
	The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2014 and 2013. Financial assets and liabilities are classified in their entirety 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 consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2014 and 2013. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.
	Recurring Fair Value Measurements as of October 31, 2014
				Significant					Effects of
		Quoted Prices		Other			Significant		Netting and
		in Active		Observable			Unobservable		Cash Collateral			Total
		Markets		Inputs			Inputs		Receivables/			Carrying
	In thousands	(Level 1)		(Level 2)			(Level 3)		Payables			Value
	Assets:
	Derivatives held for distribution operations	$	4,898	$	—		$	—	$	—		$	4,898
	Debt and equity securities held as trading securities:
	Money markets	469		—			—		—			469
	Mutual funds	3,472		—			—		—			3,472
	Total fair value assets	$	8,839	$	—		$	—	$	—		$	8,839
	Recurring Fair Value Measurements as of October 31, 2013
				Significant					Effects of
		Quoted Prices		Other			Significant		Netting and
		in Active		Observable			Unobservable		Cash Collateral			Total
		Markets		Inputs			Inputs		Receivables/			Carrying
	In thousands	(Level 1)		(Level 2)			(Level 3)		Payables			Value
	Assets:
	Derivatives held for distribution operations	$	1,834	$	—		$	—	$	—		$	1,834
	Debt and equity securities held as trading securities:
	Money markets	380		—			—		—			380
	Mutual funds	2,814		—			—		—			2,814
	Total fair value assets	$	5,028	$	—		$	—	$	—		$	5,028
	Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 1 to the consolidated financial statements. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.
	Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.
	Our long-term debt is recorded at unamortized cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.
		Carrying
	In thousands	Amount *		Fair Value
	As of October 31, 2014	$	1,425,000	$	1,617,453
	As of October 31, 2013	1,275,000		1,409,892
	* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.
	Quantitative and Qualitative Disclosures
	The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value of our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.
	The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2014 and 2013.
	Fair Value of Derivative Instruments
	In thousands	2014		2013
	Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
	Asset Financial Instruments:
	Current Assets - Gas purchase derivative assets (December 2014 - November 2015)	$	4,898
	Current Assets - Gas purchase derivative assets (December 2013 - October 2014)			$	1,834
	We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 1 to the consolidated financial statements and recognized in the Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.
	The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2014 and 2013, absent the regulatory treatment under our approved PGA procedures.
		Amount of					Amount of					Location of Gain (Loss)
		Gain (Loss) Recognized					Gain (Loss) Deferred					Recognized through
		on Derivative Instruments					Under PGA Procedures					PGA Procedures
		Twelve Months Ended					Twelve Months Ended
		October 31					October 31
	In thousands	2014		2013			2014		2013
	Gas purchase options	$	6,162	$	(6,303	)	$	6,162	$	(6,303	)	Cost of Gas
	In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.
	Credit and Counterparty Risk
	We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.
	We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $3.5 million, or approximately 5% of our gross trade accounts receivable at October 31, 2014. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.
	We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2014, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.
	Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.
	Risk Management
	Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.
We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management (ERM) program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

Commitment_Contingencies

Commitment & Contingencies	12 Months Ended
	Oct. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingent Liabilities
	Leases
	We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.
	Operating lease payments for the years ended October 31, 2014, 2013 and 2012 are as follows.
	In thousands		2014			2013		2012
	Operating lease payments (1)		$	4,701		$	4,729	$	3,712
	(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments.
	Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
	In thousands
	2015	$	4,600
	2016	4,491
	2017	4,297
	2018	4,225
	2019	4,137
	Thereafter	27,359
	Total	$	49,109
	Long-term contracts
	We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to twenty-one years. The time periods for fixed payments under gas supply contracts are up to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.
	Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”
	As of October 31, 2014, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
			Pipeline			Gas Supply		Telecommunications
			Storage			Reservation		and Information
	In thousands		Capacity			Fees		Technology		Other		Total
	2015		$	158,984		$	8,657	$	14,601	$	41,008	$	223,250
	2016		149,412			137		4,786		—		154,335
	2017		145,579			135		736		—		146,450
	2018		142,433			—		126		—		142,559
	2019		132,186			—		80		—		132,266
	Thereafter		627,602			—		—		—		627,602
	Total		$	1,356,196		$	8,929	$	20,329	$	41,008	$	1,426,462
	Legal
	We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows.
	Letters of Credit
	We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.8 million in letters of credit that were issued and outstanding at October 31, 2014. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.
	Surety Bonds
	In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of October 31, 2014, we had open surety bonds with a total contingent obligation of $4.8 million.
	Environmental Matters
	Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded for manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).
	In 1997, we entered into a settlement with a third-party with respect to nine MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.
	In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly-owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy Corporation (Duke Energy), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.
	The following table summarizes information regarding our environmental sites as of October 31, 2014.
						Costs		Undiscounted
			Site			Incurred		Environmental
	In thousands		Type		Site Status	to Date		Liability *
	Anderson, SC		MGP		Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control.	$	7	$	890
	Hickory, NC		MGP		Remediation complete. Land use restrictions in progress.	1,494		18
	Reidsville, NC		MGP		Remediation complete. Land use restrictions filed.	641		199
	Huntersville, NC		LNG		Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete.	4,738		81
	Charlotte, NC		UST		USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources.	32		33
	Clemmons, NC		UST		Potential responsible party for propane tank	—		38
	Totals					$	6,912	$	1,259
	* Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others.
	We continue to expand our sampling of our pipelines for coatings containing asbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline.
	As of October 31, 2014, our regulatory assets for unamortized environmental costs in our three-state territory totaled $8 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.1 million of our deferred South Carolina environmental costs over a one-year period beginning November 2014, pursuant to the annual rate stabilization order issued in October 2014.
	Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Oct. 31, 2014
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Employee Benefit Plans
	Under accounting guidance, we are required to recognize all obligations related to defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Our plans’ assets are required to be accounted for at fair value.
	Pension Benefits
	We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.
	The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.
	Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:
	•	Achieve full funding over the longer term, and
	•	Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.
	We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.
	The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
	The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield debt, asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.
	Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2014, we contributed $.9 million to the MPP plan.
	OPEB Plan
	We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.
	OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
	Supplemental Executive Retirement Plans
	We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.
	We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.
	We have a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded monthly through a rabbi trust with a bank as the trustee. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.
	The funding to the DCR plan accounts for the years ended October 31, 2014 and 2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2014 and 2013 are presented below.
	In thousands		2014				2013
	Funding		$	524			$	434
	Liability:
	Current		214				199
	Noncurrent		4,248				3,328
	We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.
	In thousands		2014				2013				2012
	Term life policies of certain officers at the vice president level and above		$	30			$	27			$	43
	Officers and director-level employees		32				28				25
	Actuarial Plan Information
	A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2014 and 2013, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2014 and 2013 are presented below.
			Qualified Pension								Nonqualified Pension							Other Benefits
	In thousands		2014				2013				2014			2013				2014			2013
	Accumulated benefit obligation at year end		$	252,706			$	230,175			$	5,925		$	4,736			N/A			N/A
	Change in projected benefit obligation:
	Obligation at beginning of year		$	272,403			$	293,327			$	4,736		$	5,569			$	33,678		$	34,830
	Service cost		10,865				12,005				—			—				1,109			1,327
	Interest cost		11,781				9,946				200			157				1,448			1,130
	Plan amendments		—				—				485			—				—			—
	Actuarial (gain) loss		23,646				(24,859		)		956			(540		)		3,734			(1,094		)
	Participant contributions		—				—				—			—				805			641
	Administrative expenses		(465		)		(534		)		—			—				—			—
	Benefit payments		(15,544		)		(17,482		)		(452		)	(450		)		(2,957		)	(3,156		)
	Obligation at end of year		302,686				272,403				5,925			4,736				37,817			33,678
	Change in fair value of plan assets:
	Fair value at beginning of year		300,661				272,337				—			—				25,961			23,663
	Actual return on plan assets		31,791				26,340				—			—				1,874			2,848
	Employer contributions		20,000				20,000				452			450				2,064			1,965
	Participant contributions		—				—				—			—				805			641
	Administrative expenses		(465		)		(534		)		—			—				—			—
	Benefit payments		(15,544		)		(17,482		)		(452		)	(450		)		(2,957		)	(3,156		)
	Fair value at end of year		336,443				300,661				—			—				27,747			25,961
	Funded status at year end - over (under)		$	33,757			$	28,258			$	(5,925	)	$	(4,736	)		$	(10,070	)	$	(7,717	)
	Noncurrent assets		$	33,757			$	28,258			$	—		$	—			$	—		$	—
	Current liabilities		—				—				(521		)	(445		)		—			—
	Noncurrent liabilities		—				—				(5,404		)	(4,291		)		(10,070		)	(7,717		)
	Net amount recognized		$	33,757			$	28,258			$	(5,925	)	$	(4,736	)		$	(10,070	)	$	(7,717	)
	Amounts Not Yet Recognized as a Component
	of Cost and Recognized in a Deferred
	Regulatory Account:
	Unrecognized transition obligation		$	—			$	—			$	—		$	—			$	—		$	—
	Unrecognized prior service credit (cost)		15,046				17,243				(439		)	(196		)		—			—
	Unrecognized actuarial loss		(103,038		)		(96,338		)		(1,745		)	(820		)		(3,995		)	(354		)
	Regulatory asset		(87,992		)		(79,095		)		(2,184		)	(1,016		)		(3,995		)	(354		)
Cumulative employer contributions in
excess of cost		121,749				107,353				(3,741		)	(3,720		)		(6,075		)	(7,363		)
Net amount recognized		$	33,757			$	28,258			$	(5,925	)	$	(4,736	)		$	(10,070	)	$	(7,717	)
In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCIL as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.
Net periodic benefit cost for the years ended October 31, 2014, 2013 and 2012 includes the following components.
		Qualified Pension											Nonqualified Pension										Other Benefits
In thousands		2014				2013				2012			2014				2013			2012			2014			2013			2012
Service cost		$	10,865			$	12,005			$	9,573		$	—			$	—		$	39		$	1,109		$	1,327		$	1,387
Interest cost		11,781				9,946				10,640			200				157			203			1,448			1,130			1,347
Expected return on plan assets		(22,530		)		(21,105		)		(20,289		)	—				—			—			(1,782		)	(1,663		)	(1,551		)
Amortization of transition obligation		—				—				—			—				—			—			—			667			667
Amortization of prior service cost
(credit)		(2,198		)		(2,198		)		(2,198		)	243				81			81			—			—			—
Amortization of net loss		7,685				11,202				5,966			31				161			49			—			—			—
Net periodic benefit cost		5,603				9,850				3,692			474				399			372			775			1,461			1,850
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost		—				—				—			485				—			—			—			—			—
Net loss (gain)		14,385				(30,094		)		43,945			956				(540		)	629			3,641			(2,278		)	2,209
Amounts recognized as a component of
net periodic benefit cost:
Transition obligation		—				—				—			—				—			—			—			(667		)	(667		)
Amortization of net loss		(7,685		)		(11,202		)		(5,966		)	(31		)		(161		)	(49		)	—			—			—
Prior service (cost) credit		2,198				2,198				2,198			(243		)		(81		)	(81		)	—			—			—
Total recognized in regulatory asset
(liability)		8,898				(39,098		)		40,177			1,167				(782		)	499			3,641			(2,945		)	1,542
Total recognized in net periodic benefit
and regulatory asset (liability)		$	14,501			$	(29,248	)		$	43,869		$	1,641			$	(383	)	$	871		$	4,416		$	(1,484	)	$	3,392
The 2015 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.
		Qualified				Nonqualified				Other
In thousands		Pension				Pension				Benefits
Amortization of unrecognized prior service (credit) cost		$	(2,198	)		$	231			$	—
Amortization of unrecognized actuarial loss		8,121				85				29
The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s Investors Service’s or Standard & Poor’s Ratings Services that have a yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31, 2014, the benchmark by plan was as follows.
Pension plan	4.13	%
NCNG SERP	3.64	%
Directors’ SERP	3.74	%
Piedmont SERP	3.1	%
OPEB	4.03	%
Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.
We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2014 and 2013 are presented below.
		Qualified Pension						Nonqualified Pension					Other Benefits
		2014			2013			2014			2013		2014			2013
Discount rate		4.13	%		4.55	%		3.69	%		3.98	%	4.03	%		4.44	%
Rate of compensation increase		3.68	%		3.72	%		N/A			N/A		N/A			N/A
In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. As of October 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014.
The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2014, 2013 and 2012 are presented below.
		Qualified Pension									Nonqualified Pension
		2014			2013			2012			2014		2013			2012
Discount rate		4.55	%		3.51	%		4.67	%		3.98	%	2.95	%		4.1	%
Expected long-term rate of return on plan assets		7.75	%		8	%		8	%		N/A		N/A			N/A
Rate of compensation increase		3.72	%		3.76	%		3.78	%		N/A		N/A			N/A
		Other Benefits
		2014			2013			2012
Discount rate		4.44	%		3.34	%		4.36	%
Expected long-term rate of return on plan assets		7.75	%		8	%		8	%
Rate of compensation increase		N/A			N/A			N/A
We anticipate that we will contribute the following amounts to our plans in 2015.
In thousands
Qualified pension plan *	$	10,000
Nonqualified pension plans	521
MPP plan	1,300
OPEB plan	1,500
* Funded in November 2014.
The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.
Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
		Qualified				Nonqualified				Other
In thousands		Pension				Pension				Benefits
2015		$	29,946			$	521			$	2,409
2016		16,794				507				2,449
2017		16,332				491				2,527
2018		19,197				472				2,606
2019		20,685				490				2,682
2020 - 2024		110,459				2,149				14,179
The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2014 and 2013 are presented below.
		2014			2013
Health care cost trend rate assumed for next year		7.4	%		7.4	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend rate		2027			2027
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.
In thousands		1% Increase				1% Decrease
Effect on total of service and interest cost components of net periodic
postretirement health care benefit cost for the year ended October 31, 2014		$	31			$	(32	)
Effect on the health care cost component of the accumulated postretirement
benefit obligation as of October 31, 2014		829				(841		)
Fair Value Measurements
Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.
Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.
Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have been valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.
U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.
Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.
Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.
High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.
Derivatives – The Level 1 assets were valued using a compilation of observable market information on an active market. The Level 2 assets were valued using broker quotes on a non-active market.
Large cap core index – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).
Large cap value and small cap value – These are Level 1 assets valued at the market price of the active market on which the individual security is traded.
Large cap growth and global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed equity funds.
Common trust funds – International growth and bank loans (and for 2013, international value) – These are Level 2 assets held in common trust funds in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently there are no restrictions on redemptions for the funds.
Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.
Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 3.5% but is still being funded through capital calls; $5.4 million of the original $12 million subscription remains unfunded. Until a 3.5% allocation can be achieved, the balance of the 3.5% allocation is invested in a low-cost equity index fund that tracks the S&P 500 Index. Our investment is in various funds that invests in North American companies; allocate capital to private equity funds; invest in venture capital partnerships; and private equity partnerships in emerging markets.
Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.
As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
						Redemptions
		Redemption				Notice
Investment		Frequency		Other Redemption Restrictions		Period
Common trust fund -		Monthly		None		30 days
International growth
Hedge fund of funds		Quarterly		Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.		65 days
Private equity fund of funds		Limited		Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.		-1
Commodities fund of funds		Monthly		Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.		35 days
Bank loans		Daily		None		30 days
(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.
The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. 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 their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.
		Qualified Pension Plan as of October 31, 2014
						Significant Other Observable Inputs(Level 2)
		Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
													Total Carrying Value				% of Total
In thousands
Cash and cash equivalents		$	27,932			$	435			$	—		$	28,367			8	%
Fixed Income Securities:																	45	%
U.S. treasuries		—				27,224				—			27,224				8	%
Long duration bonds		—				48,049				—			48,049				14	%
Corporate bonds		—				49,816				—			49,816				15	%
High yield bonds		8,100				—				—			8,100				3	%
Common trust fund - Bank loans		—				16,187				—			16,187				5	%
Collateralized mortgage
obligations		—				1,035				—			1,035				—	%
Derivatives		48				(49		)		—			(1		)		—	%
Equity Securities:																	31	%
Large cap core index		9,982				—				—			9,982				3	%
Large cap value		19,937				—				—			19,937				6	%
Large cap growth		19,745				—				—			19,745				6	%
Small cap value		31,329				—				—			31,329				9	%
Common trust fund - International
growth		—				22,877				—			22,877				7	%
Real Estate:																	5	%
Global REIT		16,675				—				—			16,675				5	%
Other Investments:																	11	%
Hedge fund of funds		—				19,829				—			19,829				6	%
Private equity fund of funds		—				—				7,158			7,158				2	%
Commodities fund of funds		—				10,134				—			10,134				3	%
Total assets at fair value		$	133,748			$	195,537			$	7,158		$	336,443			100	%
Percent of fair value hierarchy		40		%		58		%		2		%	100		%
		Qualified Pension Plan as of October 31, 2013
						Significant Other Observable Inputs(Level 2)
		Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
													Total Carrying Value				% of Total
In thousands
Cash and cash equivalents		$	5,566			$	156			$	—		$	5,722			2	%
Fixed Income Securities:																	38	%
U.S. treasuries		—				24,078				—			24,078				8	%
Long duration bonds		—				34,041				—			34,041				11	%
Corporate bonds		—				42,701				—			42,701				14	%
High yield bonds		14,680				—				—			14,680				5	%
Collateralized mortgage
obligations		—				1,098				—			1,098				—	%
Derivatives		6				(17		)		—			(11		)		—	%
Equity Securities:																	43	%
Large cap core index		12,023				—				—			12,023				4	%
Large cap value		16,908				—				—			16,908				6	%
Large cap growth		17,823				—				—			17,823				6	%
Small cap value		30,831				—				—			30,831				10	%
Common trust fund - International
value		—				24,460				—			24,460				8	%
Common trust fund - International
growth		—				27,270				—			27,270				9	%
Real Estate:																	5	%
Global REIT		15,042				—				—			15,042				5	%
Other Investments:																	12	%
Hedge fund of funds		—				18,571				—			18,571				6	%
Private equity fund of funds		—				—				4,659			4,659				2	%
Commodities fund of funds		—				10,765				—			10,765				4	%
Total assets at fair value		$	112,879			$	183,123			$	4,659		$	300,661			100	%
Percent of fair value hierarchy		37		%		61		%		2		%	100		%
The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.
		Private
		Equity Fund
In thousands		of Funds
Balance, October 31, 2012		$	3,522
Actual return on plan assets:
Relating to assets still held at the reporting date		116
Relating to assets sold during the period		61
Purchases, sales and settlements (net)		960
Transfer in/out of Level 3		—
Balance, October 31, 2013		4,659
Actual return on plan assets:
Relating to assets still held at the reporting date		1,031
Relating to assets sold during the period		113
Purchases, sales and settlements (net)		1,355
Transfer in/out of Level 3		—
Balance, October 31, 2014		$	7,158
During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.
There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.
Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.
Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.
U.S. treasuries – These are Level 1 assets in an actively managed mutual fund measured at NAV.
Corporate bonds/Other fixed income securities – These are Level 1 assets valued at the quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to high yield fixed income.
Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV as invested in mutual funds that invest by a specific style.
Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.
International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.
Global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.
The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. 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 their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.
		Other Benefits as of October 31, 2014
						Significant Other Observable Inputs(Level 2)
		Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
													Total Carrying Value				% of Total
In thousands
Cash and cash equivalents		$	2,590			$	—			$	—		$	2,590			9	%
Fixed Income Securities:																	44	%
U.S. treasuries		2,013				—				—			2,013				7	%
Corporate bonds / Other fixed income
securities		10,187				—				—			10,187				37	%
Equity Securities:																	42	%
Large cap value		1,269				—				—			1,269				4	%
Large cap growth		1,310				—				—			1,310				5	%
Small cap value		1,336				—				—			1,336				5	%
Small cap growth		1,319				—				—			1,319				5	%
Large cap index		2,532				—				—			2,532				9	%
International blend		3,846				—				—			3,846				14	%
Real Estate:																	5	%
Global REIT		1,345				—				—			1,345				5	%
Total assets at fair value		$	27,747			$	—			$	—		$	27,747			100	%
Percent of fair value hierarchy		100		%		—		%		—		%	100		%
		Other Benefits as of October 31, 2013
						Significant Other Observable Inputs(Level 2)
		Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
													Total Carrying Value				% of Total
In thousands
Cash and cash equivalents		$	982			$	—			$	—		$	982			4	%
Fixed Income Securities:																	46	%
U.S. treasuries		2,582				—				—			2,582				10	%
Corporate bonds / Other fixed income
securities		9,232				—				—			9,232				36	%
Equity Securities:																	45	%
Large cap value		1,327				—				—			1,327				5	%
Large cap growth		1,352				—				—			1,352				5	%
Small cap value		1,331				—				—			1,331				5	%
Small cap growth		1,313				—				—			1,313				5	%
Large cap index		2,384				—				—			2,384				9	%
International blend		4,206				—				—			4,206				16	%
Real Estate:																	5	%
Global REIT		1,252				—				—			1,252				5	%
Total assets at fair value		$	25,961			$	—			$	—		$	25,961			100	%
Percent of fair value hierarchy		100		%		—		%		—		%	100		%
401(k) Plan
We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.
Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2014, 2013 and 2012, we made matching contributions to participant accounts as follows.
In thousands		2014				2013				2012
401(k) matching contributions		$	6,134			$	5,688			$	5,400
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statement of Stockholders’ Equity as an increase in retained earnings.

Employee_Share_Based_Plans

Employee Share Based Plans	12 Months Ended
	Oct. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	Employee Share-Based Plans
	Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2014, 2013 and 2012, we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.
	We have granted three series of awards under approved incentive compensation plans, each with a three-year performance period (ending October 31, 2014, October 31, 2015 and October 31, 2016). For each of these performance periods, awards will be based on achievement relative to a target annual compounded increase in basic EPS and the achievement of total shareholder returns relative to a group of peer companies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours, with each measure being weighted at 50%. The plans with performance periods ending October 31, 2015 (2015 plan) and October 31, 2016 (2016 plan) have an additional performance measure of actual average return on equity compared to the weighted average return on equity allowed by our regulatory commissions. The weighting of the units awarded under the 2015 plan and the 2016 plan is based on EPS at 37.5%, total shareholder return at 37.5% and return on equity at 25% of the total units awarded.
	In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award vested for participants who met the retention requirements at the end of the three-year period ending in December 2013 and settled in the same month with payment in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors had the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2013 and 2012, we recorded compensation expense and a liability as of October 31, 2013 with compensation expense recorded in fiscal 2014 until December 2013 when the award was settled. The liability, which we accrued for this award based on the fair market value of our stock at the end of each quarter, was re-measured to market value in December 2013, the settlement date.
	Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2014, 2013 and 2012,we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for this award based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.
	The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.
	At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in the Consolidated Statements of Stockholders’ Equity and in Note 6 to the consolidated financial statements.
	The compensation expense related to the incentive compensation plans for the years ended October 31, 2014, 2013 and 2012, and the amounts recorded as liabilities in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities" in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.
	In thousands	2014		2013		2012
	Compensation expense	$	8,496	$	4,526	$	5,730
	Tax benefit	2,476		1,538		2,080
	Liability	15,130		11,098
	Based on current accrual assumptions as of October 31, 2014, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.
	In thousands	2015		2016		2017
	Amount of payout	$	7,204	$	4,980	$	2,946
	On a quarterly basis, we issue shares of common stock under the ESPP and account for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.

Income_Taxes

Income Taxes	12 Months Ended
	Oct. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes
	The components of income tax expense for the years ended October 31, 2014, 2013 and 2012 are presented below.
		2014						2013						2012
	In thousands	Federal			State			Federal			State			Federal			State
	Charged (Credited) to operating
	income:
	Current (1)	$	(1,653	)	$	950		$	(3,032	)	$	919		$	(29,062	)	$	1,857
	Deferred (1)	70,654			13,434			67,885			11,829			86,496			10,144
	Tax Credits:
	Amortization	(209		)	—			(267		)	—			(334		)	—
	Total	68,792			14,384			64,586			12,748			57,100			12,001
	Charged (Credited) to other income
	(expense):
	Current	4,233			870			6,049			984			5,636			1,027
	Deferred	5,811			728			2,225			(646		)	2,214			239
	Total	10,044			1,598			8,274			338			7,850			1,266
	Total	$	78,836		$	15,982		$	72,860		$	13,086		$	64,950		$	13,267
	(1) Includes utilization of federal NOL carryforward benefit of $28.6 million for the year ended October 31, 2014 and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.
	A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014			2013			2012
	Federal taxes at 35%	$	83,517		$	77,127		$	69,322
	State income taxes, net of federal benefit	10,389			8,506			8,624
	Amortization of investment tax credits	(209		)	(267		)	(334		)
	Other, net	1,121			580			605
	Total	$	94,818		$	85,946		$	78,217
	As of October 31, 2014 and 2013, deferred income taxes consisted of the following temporary differences.
	In thousands	2014			2013
	Deferred tax assets:
	Benefit of loss carryforwards	$	39,532		$	66,087
	Revenues and cost of gas	4,960			—
	Employee benefits and compensation	16,547			13,834
	Revenue requirement	20,320			19,062
	Utility plant	5,631			10,386
	Other	12,869			12,796
	Total deferred tax assets	99,859			122,165
	Valuation allowance	(505		)	(505		)
	Total deferred tax assets, net	99,354			121,660
	Deferred tax liabilities:
	Utility plant	724,172			652,822
	Revenues and cost of gas	4,340			21,257
	Equity method investments	42,998			38,710
	Deferred costs	65,828			59,221
	Other	18,065			18,324
	Total deferred tax liabilities	855,403			790,334
	Net deferred income tax liabilities	$	756,049		$	668,674
	As of October 31, 2014 and 2013, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly-owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 2014 and 2013, we have federal NOL carryforwards of $97 million and $178.1 million, respectively, which expire in 2033. We also have $5.9 million of federal NOL carryforwards as of October 31, 2014 and 2013 that expire in 2021 through 2025 and are subject to an annual limitation of $.3 million. As of October 31, 2014, we have a $2.4 million alternative minimum tax credit carryforward.
	As of October 31, 2014 and 2013, we have state NOL carryforwards of $7.2 million and $6.4 million, respectively, that expire from 2020 through 2028. We may use the carryforwards to offset taxable income.
	We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2009, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2009. The IRS is currently auditing the federal income tax returns for years ended October 31, 2010, 2011 and 2012.
	A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014			2013			2012
	Balance at beginning of year	$	505		$	505		$	505
	Credited to income tax expense	—			—			—
	Balance at end of year	$	505		$	505		$	505
	There were no unrecognized tax benefits for the years ended October 31, 2014 and 2013.
	In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduced the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax balances at October 31, 2013 by approximately $25 million for temporary differences expected to reverse at a lower rate than under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our regulated non-utility activities segment, with the balance of approximately $24 million recorded in deferred income taxes in “Regulatory Liabilities” as presented in Note 1 to the consolidated financial statements, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. This increased our deferred income taxes recorded in “Regulatory Liabilities” to approximately $27 million. Our state regulatory commissions will determine the refund period of this regulatory liability in future proceedings.

Equity_Method_Investments

Equity Method Investments	12 Months Ended
	Oct. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	Equity Method Investments
	The consolidated financial statements include the accounts of wholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.
	As of October 31, 2014, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.
	Cardinal Pipeline Company, L.L.C.
	We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.
	Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.
	We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2014, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Transportation costs	$	8,825	$	8,775	$	6,613
	Trade accounts payable	747		755
	Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013		2012
	Current assets	$	8,856	$	15,179
	Noncurrent assets	111,881		116,414
	Current liabilities	1,468		2,637
	Noncurrent liabilities	45,402		45,273
	Revenues	16,705		17,649		$	16,165
	Gross profit	16,705		17,649		16,165
	Income before income taxes	8,042		9,361		10,433
	Pine Needle LNG Company, L.L.C.
	We own 45% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company that owns an interstate LNG storage facility in North Carolina regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc. and SCANA Corporation.
	Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.
	We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Gas storage costs	$	11,364	$	11,098	$	10,410
	Trade accounts payable	989		940
	Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013		2012
	Current assets	$	8,812	$	9,225
	Noncurrent assets	70,837		74,710
	Current liabilities	38,029		3,531
	Noncurrent liabilities	—		35,391
	Revenues	18,025		16,810		$	16,390
	Gross profit	18,025		16,810		16,390
	Income before income taxes	6,011		5,804		5,832
	SouthStar Energy Services LLC
	We own 15% of the membership interests in SouthStar, a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL). SouthStar primarily sells natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.
	In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.
	SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.
	These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Beginning in 2014, retirement benefits were allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. Our share of movements in the market value of these derivative contracts are recorded as a hedge and the activity of the retirement benefit items are reflected in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts and the retirement benefits are combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.
	We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Operating revenues	$	3,541	$	3,291	$	2,442
	Trade accounts receivable	460		441
	Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013*		2012
	Current assets	$	196,286	$	199,425
	Noncurrent assets	143,420		147,571
	Current liabilities	51,435		76,346
	Noncurrent liabilities	83		31
	Revenues	845,695		639,426		$	585,291
	Gross profit	234,581		174,993		161,122
	Income before income taxes	136,569		102,805		94,631
	* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.
	Hardy Storage Company, LLC
	We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.
	We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Gas storage costs	$	9,461	$	9,702	$	9,702
	Trade accounts payable	774		808
	Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2014 and 2013, and for the twelve months ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013		2012
	Current assets	$	12,644	$	7,641
	Noncurrent assets	157,861		161,282
Current liabilities	17,316		12,378
Noncurrent liabilities	78,830		87,184
Revenues	23,804		24,375		$	24,359
Gross profit	23,804		24,375		24,359
Income before income taxes	10,497		10,582		9,939
Constitution Pipeline Company, LLC
We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies is the operator of the project. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $730 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.
In thousands	2014		2013 (1)
Current assets	$	11,273	$	10,944
Noncurrent assets	219,208		62,438
Current liabilities	7,667		7,960
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income before income taxes	10,091		3,459
(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012.
Atlantic Coast Pipeline, LLC
On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.
We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP.
In October 2014, ACP requested approval from the FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline will commence. ACP expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016 and begin construction thereafter. The project is subject to FERC, state and other federal approvals.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Oct. 31, 2014
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Aggregation Of Variable Interest Entities Disclosures [Text Block]	Variable Interest Entities
	Under accounting guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor, or the primary beneficiary, is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
	On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.
	As of October 31, 2014, we have determined that we are not the primary beneficiary under VIE accounting guidance in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2014 and 2013, our investment balances are as follows.
		October 31,		October 31,
	In thousands	2014		2013
	Cardinal	$	16,073	$	18,207
	Pine Needle	18,689		20,270
	SouthStar	40,965		38,372
	Hardy Storage	37,179		34,681
	Constitution	57,255		16,939
	ACP	10
	Total equity method investments in non-utility activities	$	170,171	$	128,469
	We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Business_Segments

Business Segments	12 Months Ended
	Oct. 31, 2014
Segment Reporting [Abstract]
Segment Reporting Disclosure [Text Block]	Business Segments
	We have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company.
	Prior to this fiscal year ended October 31, 2014, we aggregated the regulated non-utility activities and unregulated non-utility activities into one segment, the non-utility activities segment. These activities shared a majority of characteristics that permitted aggregation under relevant accounting guidance. Based on this accounting guidance, the unaggregated operating activities individually have never met the quantitative thresholds for separate disclosure. In September 2014 with the formation of ACP and our equity membership in the venture, our current and future commitment to fund construction of regulated pipelines through our equity method investments became more significant and, as a result, we have changed our segment presentation to separately disclose our non-utility activities into regulated non-utility and unregulated non-utility activities. The effect on our company's risk profile of regulation versus non-regulation of our equity method investments and management’s view that this segmentation will provide disclosures that will help users of our financial statements to better understand how management assesses organizational performance and makes decisions about the allocation of resources were key factors in our decision to modify our reportable segments. We anticipate significant growth in our regulated non-utility activities as compared to our unregulated non-utility activities. This is especially so given our equity ownership in Constitution and ACP, both FERC regulated pipelines. Once these pipelines are in operation, the earnings contribution is expected to increase for this segment.
	Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.
	Operations of the regulated utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.
	Operations by segment for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014, 2013 and 2012 are presented below. The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.
					Regulated			Unregulated
		Regulated			Non-Utility			Non-Utility
	In thousands	Utility			Activities			Activities			Total
	2014
	Revenues from external customers	$	1,469,988		$	—		$	—		$	1,469,988
	Margin	690,208			—			—			690,208
	Operations and maintenance expenses	270,877			132			92			271,101
	Depreciation	118,996			—			18			119,014
	Operating income (loss) before income taxes	263,041			(183		)	(203		)	262,655
	Income from equity method investments	—			12,318			20,435			32,753
	Interest expense	54,686			—			—			54,686
	Income before income taxes	206,253			12,135			20,231			238,619
	Total assets	4,442,185			129,206			41,309			4,612,700
	Equity method investments in non-utility activities	—			129,206			40,965			170,171
	Construction expenditures	460,444			—			—			460,444
					Regulated			Unregulated
		Regulated			Non-Utility			Non-Utility
	In thousands	Utility			Activities			Activities			Total
	2013
	Revenues from external customers	$	1,278,229		$	—		$	—		$	1,278,229
	Margin	621,490			—			—			621,490
	Operations and maintenance expenses	253,120			103			78			253,301
	Depreciation	112,207			—			18			112,225
	Operating income (loss) before income taxes	221,528			(150		)	(202		)	221,176
	Income from equity method investments	—			10,584			15,472			26,056
	Interest expense	24,938			—			—			24,938
	Income before income taxes	194,659			10,434			15,270			220,363
	Total assets	4,053,591			90,097			38,735			4,182,423
	Equity method investments in non-utility activities	—			90,097			38,372			128,469
	Construction expenditures	599,999			—			—			599,999
					Regulated			Unregulated
		Regulated			Non-Utility			Non-Utility
	In thousands	Utility			Activities			Activities			Total
	2012
	Revenues from external customers	$	1,122,780		$	—		$	—		$	1,122,780
	Margin	575,446			—			—			575,446
	Operations and maintenance expenses	242,599			31			71			242,701
	Depreciation	103,192			—			18			103,210
	Operating income (loss) before income taxes	194,824			(78		)	(186		)	194,560
	Income from equity method investments	—			9,709			14,195			23,904
	Interest expense	20,097			—			—			20,097
	Income before income taxes	174,424			9,631			14,009			198,064
	Total assets	3,475,640			69,749			18,498			3,563,887
	Equity method investments in non-utility activities	—			69,749			18,118			87,867
	Construction expenditures	529,576			—			—			529,576
	Reconciliations to the consolidated financial statements for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014 and 2013 are as follows.
	In thousands	2014			2013			2012
	Operating Income:
	Segment operating income before income taxes	$	262,655		$	221,176		$	194,560
	Utility income taxes	(83,176		)	(77,334		)	(69,101		)
	Regulated non-utility activities operating loss before income taxes	183			150			78
	Unregulated non-utility activities operating loss before income taxes	203			202			186
	Total	$	179,865		$	144,194		$	125,723
	Net Income:
	Income before income taxes for reportable segments	$	238,619		$	220,363		$	198,064
	Income taxes	(94,818		)	(85,946		)	(78,217		)
	Total	$	143,801		$	134,417		$	119,847
	In thousands	2014			2013
Consolidated Assets:
Total assets for reportable segments	$	4,612,700		$	4,182,423
Eliminations/Adjustments	171,553			186,186
Total	$	4,784,253		$	4,368,609

Subsequent_Events

Subsequent Events	12 Months Ended
	Oct. 31, 2014
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events
	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. For information on subsequent event disclosure items related to regulatory matters and employee share-based plans, see Note 2 and Note 10, respectively, to the consolidated financial statements.

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data	12 Months Ended
	Oct. 31, 2014
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
											Earnings (Loss)
								Net			Per Share of
		Operating				Operating		Income			Common Stock
		Revenues		Margin		Income		(Loss)			Basic			Diluted
	Fiscal Year 2014
	31-Jan	$	657,733	$	261,512	$	102,319	$	97,572		$	1.27		$	1.26
	30-Apr	462,247		211,523		67,299		62,540			0.8			0.8
	31-Jul	164,187		104,847		3,254		(7,344		)	(0.09		)	(0.09		)
	31-Oct	185,821		112,326		6,993		(8,967		)	(0.11		)	(0.11		)
	Fiscal Year 2013
	31-Jan	$	515,875	$	231,623	$	86,213	$	85,923		$	1.19		$	1.18
	30-Apr	399,411		183,856		51,504		55,790			0.74			0.74
	31-Jul	162,943		97,000		591		(2,293		)	(0.03		)	(0.03		)
	31-Oct	200,000		109,011		5,886		(5,003		)	(0.07		)	(0.07		)
	The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

Recovered_Sheet2

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Oct. 31, 2014
Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	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.
	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).
	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.
Use of Estimates, Policy [Policy Text Block]	In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.
Segment Reporting, Policy [Policy Text Block]	Our segments are based on the components of the Company for which we produce separate financial information internally that is used 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 (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from and our cash flows in the ventures.
Rate Regulated Basis of Accounting, Policy [Policy Text Block]	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. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.
	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 or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions.
Utility Plant And Depreciation, Policy	Depreciation rates for utility plant are approved by our regulatory commissions.
	As authorized by our regulatory commissions, 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 collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate.
	We compute depreciation expense using the straight-line method
	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, 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 costs 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
Cash and Cash Equivalents, Policy [Policy Text Block]	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.
	With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.
Trade Receivables And Allowance For Doubtful Accounts, Policy	We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the PSCSC and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA).
	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 policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, 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.
Inventories, Policy	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.
	Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders.
	Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.
Fair Value Measurements, Policy [Policy Text Block]	We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.
	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 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.
	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.
	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.
	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.
	The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year.
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	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.
Equity Method Investments And Long Lived Assets, Policy	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.
Marketable Securities, Policy [Policy Text Block]	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.
	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.
Unamortized Debt Expense, Policy	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 it 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.
	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
	We amortize bank debt expense over the life of the syndicated revolving credit facility
Common Stock Issuance and Repurchase Policy	we may repurchase shares on the open market and such shares are then canceled 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.
Asset Retirement Obligations, Policy [Policy Text Block]	The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate
	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
Revenue Recognition, Policy [Policy Text Block]	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.
	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.
	Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees.
	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 approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions.
	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.
Capitalization and Amortization of Fuel Costs, Policy [Policy Text Block]	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 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 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.
Taxes, Policy	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.
	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.
	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.
	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.
Earnings Per Share, Policy [Policy Text Block]	We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.
Subsequent Events, Policy [Policy Text Block]	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.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Oct. 31, 2014
Accounting Policies [Abstract]
Schedule of Regulatory Assets [Table Text Block]	Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are as follows.
	In thousands	2014			2013
	Regulatory Assets:
	Current:
	Unamortized debt expense	$	1,490		$	1,274
	Amounts due from customers	16,108			66,321
	Environmental costs	1,568			1,480
	Deferred operations and maintenance expenses	916			739
	Deferred pipeline integrity expenses	3,470			3,149
	Deferred pension and other retirement benefits costs	2,769			2,768
	Robeson liquefied natural gas (LNG) development costs	917			382
	Other	1,850			1,091
	Total current	29,088			77,204
	Noncurrent:
	Unamortized debt expense	15,402			14,149
	Environmental costs	6,470			7,936
	Deferred operations and maintenance expenses	4,721			5,637
	Deferred pipeline integrity expenses	24,694			16,300
	Deferred pension and other retirement benefits costs	18,799			17,968
	Amounts not yet recognized as a component of pension and other retirement benefit costs	94,265			80,604
	Regulatory cost of removal asset	18,275			22,974
	Robeson LNG development costs	509			1,426
	Other	1,644			2,108
	Total noncurrent	184,779			169,102
	Total	$	213,867		$	246,306
Schedule of Regulatory Liabilities [Table Text Block]
	Regulatory Liabilities:
	Current:
	Amounts due to customers	$	46,231		$	—
	Noncurrent:
	Regulatory cost of removal obligations	506,574			493,111
	Deferred income taxes	51,930			48,647
	Amounts not yet recognized as a component of pension and other retirement costs	94			139
	Total noncurrent	558,598			541,897
	Total	$	604,829		$	541,897
Public Utility Property, Plant, and Equipment [Table Text Block]	The classification of total utility plant, net, for the years ended October 31, 2014 and 2013 is presented below.
	In thousands	2014			2013
	Intangible plant	$	3,374		$	3,374
	Other storage plant	180,058			171,349
	Transmission plant	1,787,990			1,403,829
	Distribution plant	2,623,560			2,505,160
	General plant	421,763			335,847
	Asset retirement cost	11			7,565
	Contributions in aid of construction	(5,259		)	(5,187		)
	Total utility plant in service	5,011,497			4,421,937
	Less accumulated depreciation	(1,166,922		)	(1,088,331		)
	Total utility plant in service, net	3,844,575			3,333,606
	Construction work in progress	141,693			297,717
	Plant held for future use	3,155			3,155
	Total utility plant, net	$	3,989,423		$	3,634,478
	AFUDC for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014			2013			2012
	AFUDC	$	16,427		$	30,975		$	25,211
Schedule of Trade Account Receivables [Table Text Block]	As of October 31, 2014 and 2013, our trade accounts receivable consisted of the following.
	In thousands	2014			2013
	Gas receivables	$	64,400		$	78,540
	Non-regulated merchandise and service work receivables	3,012			2,274
	Allowance for doubtful accounts	(2,152		)	(1,604		)
	Trade accounts receivable	$	65,260		$	79,210
Schedule of Changes in Allowance for Doubtful Accounts [Table Text Block]	A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014			2013			2012
	Balance at beginning of year	$	1,604		$	1,579		$	1,347
	Additions charged to uncollectibles expense	6,959			5,314			4,584
	Accounts written off, net of recoveries	(6,411		)	(5,289		)	(4,352		)
	Balance at end of year	$	2,152		$	1,604		$	1,579
Marketable Securities [Table Text Block]	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, 2014 and 2013 is as follows.
		2014						2013
	In thousands	Cost			Fair Value			Cost			Fair Value
	Current trading securities:
	Money markets	$	22		$	22		$	—		$	—
	Mutual funds	106			192			134			199
	Total current trading securities	128			214			134			199
	Noncurrent trading securities:
	Money markets	447			447			380			380
	Mutual funds	2,598			3,280			1,995			2,615
	Total noncurrent trading securities	3,045			3,727			2,375			2,995
	Total trading securities	$	3,173		$	3,941		$	2,509		$	3,194
Schedule of Asset Retirement Obligations [Table Text Block]	The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.
	In thousands	2014			2013
	Regulatory non-legal AROs	$	506,574		$	493,111
	Conditional AROs	14,647			27,016
	Total cost of removal obligations	$	521,221		$	520,127
Schedule of Change in Asset Retirement Obligation [Table Text Block]	A reconciliation of the changes in conditional AROs for the year ended October 31, 2014 and 2013 is presented below.
	In thousands	2014			2013
	Beginning of period	$	27,016		$	28,629
	Liabilities incurred during the period	2,108			2,052
	Liabilities settled during the period	(3,576		)	(2,389		)
	Accretion	1,548			1,641
	Adjustment to estimated cash flows	(12,449		)	(2,917		)
	End of period	$	14,647		$	27,016

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Oct. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands, except per share amounts	2014		2013		2012
	Net Income	$	143,801	$	134,417	$	119,847
	Average shares of common stock outstanding for basic earnings per share	77,883		74,884		71,977
	Contingently issuable shares under incentive compensation plans	310		289		301
	Contingently issuable shares under forward sale agreements	—		160		—
	Average shares of dilutive stock	78,193		75,333		72,278
	Earnings Per Share of Common Stock:
	Basic	$	1.85	$	1.8	$	1.67
	Diluted	$	1.84	$	1.78	$	1.66

Long_Term_Debt_Tables

Long Term Debt (Tables)	12 Months Ended
	Oct. 31, 2014
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2014 and 2013 is as follows.
	In thousands		2014		2013
	Senior Notes:
	2.92%, due June 6, 2016		$	40,000	$	40,000
	8.51%, due September 30, 2017		35,000		35,000
	4.24%, due June 6, 2021		160,000		160,000
	3.47%, due July 16, 2027		100,000		100,000
	3.57%, due July 16, 2027		200,000		200,000
	4.10%, due September 18, 2034		250,000		—
	4.65%, due August 1, 2043		300,000		300,000
	Medium-Term Notes:
	5.00%, due December 19, 2013		—		100,000
	6.87%, due October 6, 2023		45,000		45,000
	8.45%, due September 19, 2024		40,000		40,000
	7.40%, due October 3, 2025		55,000		55,000
	7.50%, due October 9, 2026		40,000		40,000
	7.95%, due September 14, 2029		60,000		60,000
	6.00%, due December 19, 2033		100,000		100,000
	Total		1,425,000		1,275,000
	Less current maturities		—		100,000
	Less discount on issuance of notes *		570		143
	Total		$	1,424,430	$	1,174,857
	* The discount on the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.
Schedule of Maturities of Long-term Debt [Table Text Block]	Current maturities for the next five years ending October 31 and thereafter are as follows.
	In thousands
	2015	$	—
	2016	40,000
	2017	35,000
	2018	—
	2019	—
	Thereafter	1,350,000
	Total	$	1,425,000

Short_Term_Debt_Tables

Short Term Debt (Tables)	12 Months Ended
	Oct. 31, 2014
Line of Credit Facility [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2014 is as follows
	In thousands
	Minimum amount outstanding	$	275,000
	Maximum amount outstanding	$	625,000
	Minimum interest rate	0.1		%
	Maximum interest rate	0.43		%
	Weighted average interest rate	0.19		%

Stockholders_Equity_Tables

Stockholders' Equity (Tables)	12 Months Ended
	Oct. 31, 2014
Stockholders' Equity Note [Abstract]
Schedule of Common Stock Outstanding Roll Forward [Table Text Block]	Changes in common stock for the years ended October 31, 2014, 2013 and 2011 are as follows.
	In thousands		Shares			Amount
	Balance, October 31, 2011		72,318			$	446,791
	Issued to participants in the Employee Stock Purchase Plan (ESPP)		30			894
	Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)		677			20,508
	Issued to participants in the Incentive Compensation Plan (ICP)		25			796
	Shares repurchased under Accelerated Share Repurchase (ASR) agreement		(800	)		(26,528		)
	Balance, October 31, 2012		72,250			442,461
	Issued to ESPP		33			1,056
	Issued to DRIP		720			22,791
	Issued to ICP		96			3,065
	Issuance of common stock through public share offering, net of underwriting fees		3,000			92,640
	Costs from issuance of common stock		—			(369		)
	Balance, October 31, 2013		76,099			561,644
	Issued to ESPP		34			1,143
	Issued to DRIP		698			23,443
	Issued to ICP		100			3,315
	Issuance of common stock through forward sale agreements, net of expenses		1,600			47,290
	Balance, October 31, 2014		78,531			$	636,835
Schedule Shares Reserved For Issuance [Table Text Block]	As of October 31, 2014, our shares of common stock were reserved for issuance as follows.
	In thousands
	ESPP	176
	DRIP	840
	ICP	950
	Total	1,966
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2014 and 2013.
	Changes in Accumulated OCIL (1)
	In thousands		2014				2013
	Accumulated OCIL beginning balance, net of tax		$	(284	)		$	(305	)
	Hedging activities of equity method investments:
	OCIL before reclassifications, net of tax		355				(109		)
	Amounts reclassified from accumulated OCIL, net of tax		(284		)		130
	Total current period activity of hedging activities of equity method investments, net of tax		71				21
	Net current period benefit activities of equity method investments, net of tax		(24		)
	Accumulated OCIL ending balance, net of tax		$	(237	)		$	(284	)
	(1) Amounts in parentheses indicate debits to accumulated OCIL.
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2014 and 2013.
			Reclassification Out of
			Accumulated OCIL (1)
			Years Ended
			31-Oct							Affected Line Items on Statement of
	In thousands		2014				2013			Comprehensive Income
	Hedging activities of equity method investments		$	(461	)		$	215		Income from equity method investments
	Income tax expense		177				(85		)	Income taxes
	Hedging activities of equity method investments		(284		)		$	130
	Net benefit activities of equity method investments		(40		)					Income from equity method investments
	Income tax expense		16							Income taxes
	Net benefit activities of equity method investments		(24		)
	Total reclassification for the period, net of tax		$	(308	)		$	130
	(1) Amounts in parentheses indicate debits to accumulated OCIL.

Financial_Instruments_Related_1

Financial Instruments & Related Fair Value (Tables)	12 Months Ended
	Oct. 31, 2014
Financial Instruments And Related Fair Value Detail [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	We have had no transfers between any level during the years ended October 31, 2014 and 2013.
	Recurring Fair Value Measurements as of October 31, 2014
				Significant					Effects of
		Quoted Prices		Other			Significant		Netting and
		in Active		Observable			Unobservable		Cash Collateral			Total
		Markets		Inputs			Inputs		Receivables/			Carrying
	In thousands	(Level 1)		(Level 2)			(Level 3)		Payables			Value
	Assets:
	Derivatives held for distribution operations	$	4,898	$	—		$	—	$	—		$	4,898
	Debt and equity securities held as trading securities:
	Money markets	469		—			—		—			469
	Mutual funds	3,472		—			—		—			3,472
	Total fair value assets	$	8,839	$	—		$	—	$	—		$	8,839
	Recurring Fair Value Measurements as of October 31, 2013
				Significant					Effects of
		Quoted Prices		Other			Significant		Netting and
		in Active		Observable			Unobservable		Cash Collateral			Total
		Markets		Inputs			Inputs		Receivables/			Carrying
	In thousands	(Level 1)		(Level 2)			(Level 3)		Payables			Value
	Assets:
	Derivatives held for distribution operations	$	1,834	$	—		$	—	$	—		$	1,834
	Debt and equity securities held as trading securities:
	Money markets	380		—			—		—			380
	Mutual funds	2,814		—			—		—			2,814
	Total fair value assets	$	5,028	$	—		$	—	$	—		$	5,028
	The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2014 and 2013.
Fair Value, by Balance Sheet Grouping [Table Text Block]	The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2014 and 2013.
	Fair Value of Derivative Instruments
	In thousands	2014		2013
	Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
	Asset Financial Instruments:
	Current Assets - Gas purchase derivative assets (December 2014 - November 2015)	$	4,898
	Current Assets - Gas purchase derivative assets (December 2013 - October 2014)			$	1,834
	The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.
		Carrying
	In thousands	Amount *		Fair Value
	As of October 31, 2014	$	1,425,000	$	1,617,453
	As of October 31, 2013	1,275,000		1,409,892
	* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.
Amount Of Gain Loss Recognized On Derivatives And Deferred Under PGA Procedures [Table Text Block]	The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2014 and 2013, absent the regulatory treatment under our approved PGA procedures.
		Amount of					Amount of					Location of Gain (Loss)
		Gain (Loss) Recognized					Gain (Loss) Deferred					Recognized through
		on Derivative Instruments					Under PGA Procedures					PGA Procedures
		Twelve Months Ended					Twelve Months Ended
		October 31					October 31
	In thousands	2014		2013			2014		2013
	Gas purchase options	$	6,162	$	(6,303	)	$	6,162	$	(6,303	)	Cost of Gas

Commitment_Contingencies_Table

Commitment & Contingencies (Tables)	12 Months Ended
	Oct. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Rent Expense [Table Text Block]	Operating lease payments for the years ended October 31, 2014, 2013 and 2012 are as follows.
	In thousands		2014			2013		2012
	Operating lease payments (1)		$	4,701		$	4,729	$	3,712
	(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments.
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
	In thousands
	2015	$	4,600
	2016	4,491
	2017	4,297
	2018	4,225
	2019	4,137
	Thereafter	27,359
	Total	$	49,109
Long-term Purchase Commitment [Table Text Block]	As of October 31, 2014, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
			Pipeline			Gas Supply		Telecommunications
			Storage			Reservation		and Information
	In thousands		Capacity			Fees		Technology		Other		Total
	2015		$	158,984		$	8,657	$	14,601	$	41,008	$	223,250
	2016		149,412			137		4,786		—		154,335
	2017		145,579			135		736		—		146,450
	2018		142,433			—		126		—		142,559
	2019		132,186			—		80		—		132,266
	Thereafter		627,602			—		—		—		627,602
	Total		$	1,356,196		$	8,929	$	20,329	$	41,008	$	1,426,462
Schedule of Environmental Loss Contingencies by Site [Table Text Block]	The following table summarizes information regarding our environmental sites as of October 31, 2014.
						Costs		Undiscounted
			Site			Incurred		Environmental
	In thousands		Type		Site Status	to Date		Liability *
	Anderson, SC		MGP		Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control.	$	7	$	890
	Hickory, NC		MGP		Remediation complete. Land use restrictions in progress.	1,494		18
	Reidsville, NC		MGP		Remediation complete. Land use restrictions filed.	641		199
	Huntersville, NC		LNG		Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete.	4,738		81
	Charlotte, NC		UST		USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources.	32		33
	Clemmons, NC		UST		Potential responsible party for propane tank	—		38
	Totals					$	6,912	$	1,259
	* Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others.

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Oct. 31, 2014
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Supplemental Executive Retirement Plans	The funding to the DCR plan accounts for the years ended October 31, 2014 and 2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2014 and 2013 are presented below.
	In thousands		2014				2013
	Funding		$	524			$	434
	Liability:
	Current		214				199
	Noncurrent		4,248				3,328
Term Life Insurance Premiums	The cost of these premiums is presented below.
	In thousands		2014				2013				2012
	Term life policies of certain officers at the vice president level and above		$	30			$	27			$	43
	Officers and director-level employees		32				28				25
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2014 and 2013, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2014 and 2013 are presented below.
			Qualified Pension								Nonqualified Pension							Other Benefits
	In thousands		2014				2013				2014			2013				2014			2013
	Accumulated benefit obligation at year end		$	252,706			$	230,175			$	5,925		$	4,736			N/A			N/A
	Change in projected benefit obligation:
	Obligation at beginning of year		$	272,403			$	293,327			$	4,736		$	5,569			$	33,678		$	34,830
	Service cost		10,865				12,005				—			—				1,109			1,327
	Interest cost		11,781				9,946				200			157				1,448			1,130
	Plan amendments		—				—				485			—				—			—
	Actuarial (gain) loss		23,646				(24,859		)		956			(540		)		3,734			(1,094		)
	Participant contributions		—				—				—			—				805			641
	Administrative expenses		(465		)		(534		)		—			—				—			—
	Benefit payments		(15,544		)		(17,482		)		(452		)	(450		)		(2,957		)	(3,156		)
	Obligation at end of year		302,686				272,403				5,925			4,736				37,817			33,678
	Change in fair value of plan assets:
	Fair value at beginning of year		300,661				272,337				—			—				25,961			23,663
	Actual return on plan assets		31,791				26,340				—			—				1,874			2,848
	Employer contributions		20,000				20,000				452			450				2,064			1,965
	Participant contributions		—				—				—			—				805			641
	Administrative expenses		(465		)		(534		)		—			—				—			—
	Benefit payments		(15,544		)		(17,482		)		(452		)	(450		)		(2,957		)	(3,156		)
	Fair value at end of year		336,443				300,661				—			—				27,747			25,961
	Funded status at year end - over (under)		$	33,757			$	28,258			$	(5,925	)	$	(4,736	)		$	(10,070	)	$	(7,717	)
	Noncurrent assets		$	33,757			$	28,258			$	—		$	—			$	—		$	—
	Current liabilities		—				—				(521		)	(445		)		—			—
	Noncurrent liabilities		—				—				(5,404		)	(4,291		)		(10,070		)	(7,717		)
	Net amount recognized		$	33,757			$	28,258			$	(5,925	)	$	(4,736	)		$	(10,070	)	$	(7,717	)
	Amounts Not Yet Recognized as a Component
	of Cost and Recognized in a Deferred
	Regulatory Account:
	Unrecognized transition obligation		$	—			$	—			$	—		$	—			$	—		$	—
	Unrecognized prior service credit (cost)		15,046				17,243				(439		)	(196		)		—			—
	Unrecognized actuarial loss		(103,038		)		(96,338		)		(1,745		)	(820		)		(3,995		)	(354		)
	Regulatory asset		(87,992		)		(79,095		)		(2,184		)	(1,016		)		(3,995		)	(354		)
	Cumulative employer contributions in
	excess of cost		121,749				107,353				(3,741		)	(3,720		)		(6,075		)	(7,363		)
	Net amount recognized		$	33,757			$	28,258			$	(5,925	)	$	(4,736	)		$	(10,070	)	$	(7,717	)
Components Of Net Periodic Benefit Cost	Net periodic benefit cost for the years ended October 31, 2014, 2013 and 2012 includes the following components.
			Qualified Pension											Nonqualified Pension										Other Benefits
	In thousands		2014				2013				2012			2014				2013			2012			2014			2013			2012
	Service cost		$	10,865			$	12,005			$	9,573		$	—			$	—		$	39		$	1,109		$	1,327		$	1,387
	Interest cost		11,781				9,946				10,640			200				157			203			1,448			1,130			1,347
	Expected return on plan assets		(22,530		)		(21,105		)		(20,289		)	—				—			—			(1,782		)	(1,663		)	(1,551		)
	Amortization of transition obligation		—				—				—			—				—			—			—			667			667
	Amortization of prior service cost
	(credit)		(2,198		)		(2,198		)		(2,198		)	243				81			81			—			—			—
	Amortization of net loss		7,685				11,202				5,966			31				161			49			—			—			—
	Net periodic benefit cost		5,603				9,850				3,692			474				399			372			775			1,461			1,850
	Other changes in plan assets and benefit
	obligation recognized through
	regulatory asset or liability:
	Prior service cost		—				—				—			485				—			—			—			—			—
	Net loss (gain)		14,385				(30,094		)		43,945			956				(540		)	629			3,641			(2,278		)	2,209
	Amounts recognized as a component of
	net periodic benefit cost:
	Transition obligation		—				—				—			—				—			—			—			(667		)	(667		)
	Amortization of net loss		(7,685		)		(11,202		)		(5,966		)	(31		)		(161		)	(49		)	—			—			—
	Prior service (cost) credit		2,198				2,198				2,198			(243		)		(81		)	(81		)	—			—			—
	Total recognized in regulatory asset
	(liability)		8,898				(39,098		)		40,177			1,167				(782		)	499			3,641			(2,945		)	1,542
	Total recognized in net periodic benefit
	and regulatory asset (liability)		$	14,501			$	(29,248	)		$	43,869		$	1,641			$	(383	)	$	871		$	4,416		$	(1,484	)	$	3,392
Amortization Recorded As A Regulatory Asset Or Liability Expected Refunds For Defined Benefit Plans	The 2015 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.
			Qualified				Nonqualified				Other
	In thousands		Pension				Pension				Benefits
	Amortization of unrecognized prior service (credit) cost		$	(2,198	)		$	231			$	—
	Amortization of unrecognized actuarial loss		8,121				85				29
Benefit Obligation Benchmark Discount Rate	As of October 31, 2014, the benchmark by plan was as follows.
	Pension plan	4.13	%
	NCNG SERP	3.64	%
	Directors’ SERP	3.74	%
	Piedmont SERP	3.1	%
	OPEB	4.03	%
The Weighted Average Assumptions Used To Determine The Benefit Obligation and Net Periodic Benefit Cost	The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2014 and 2013 are presented below.
			Qualified Pension						Nonqualified Pension					Other Benefits
			2014			2013			2014			2013		2014			2013
	Discount rate		4.13	%		4.55	%		3.69	%		3.98	%	4.03	%		4.44	%
	Rate of compensation increase		3.68	%		3.72	%		N/A			N/A		N/A			N/A
	The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2014, 2013 and 2012 are presented below.
			Qualified Pension									Nonqualified Pension
			2014			2013			2012			2014		2013			2012
	Discount rate		4.55	%		3.51	%		4.67	%		3.98	%	2.95	%		4.1	%
	Expected long-term rate of return on plan assets		7.75	%		8	%		8	%		N/A		N/A			N/A
	Rate of compensation increase		3.72	%		3.76	%		3.78	%		N/A		N/A			N/A
			Other Benefits
			2014			2013			2012
	Discount rate		4.44	%		3.34	%		4.36	%
	Expected long-term rate of return on plan assets		7.75	%		8	%		8	%
	Rate of compensation increase		N/A			N/A			N/A
Anticipated Employer Contribution To Benefit Plans	We anticipate that we will contribute the following amounts to our plans in 2015.
	In thousands
	Qualified pension plan *	$	10,000
	Nonqualified pension plans	521
	MPP plan	1,300
	OPEB plan	1,500
	* Funded in November 2014.
Expected Benefit Payments For The Next Ten Years	Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
			Qualified				Nonqualified				Other
	In thousands		Pension				Pension				Benefits
	2015		$	29,946			$	521			$	2,409
	2016		16,794				507				2,449
	2017		16,332				491				2,527
	2018		19,197				472				2,606
	2019		20,685				490				2,682
	2020 - 2024		110,459				2,149				14,179
Assumed Health Care Cost Trend Rates	The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2014 and 2013 are presented below.
			2014			2013
	Health care cost trend rate assumed for next year		7.4	%		7.4	%
	Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5	%		5	%
	Year that the rate reaches the ultimate trend rate		2027			2027
Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.
	In thousands		1% Increase				1% Decrease
	Effect on total of service and interest cost components of net periodic
	postretirement health care benefit cost for the year ended October 31, 2014		$	31			$	(32	)
	Effect on the health care cost component of the accumulated postretirement
	benefit obligation as of October 31, 2014		829				(841		)
Redemption Limitations, Restrictions and Notice Requirements	As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
							Redemptions
			Redemption				Notice
	Investment		Frequency		Other Redemption Restrictions		Period
	Common trust fund -		Monthly		None		30 days
	International growth
	Hedge fund of funds		Quarterly		Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.		65 days
	Private equity fund of funds		Limited		Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.		-1
	Commodities fund of funds		Monthly		Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.		35 days
	Bank loans		Daily		None		30 days
	(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.
The Qualified Pension and The OPEB Plan's Asset Allocations By Level Within the Fair Value Hierarchy	The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below.
			Qualified Pension Plan as of October 31, 2014
							Significant Other Observable Inputs(Level 2)
			Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
														Total Carrying Value				% of Total
	In thousands
	Cash and cash equivalents		$	27,932			$	435			$	—		$	28,367			8	%
	Fixed Income Securities:																	45	%
	U.S. treasuries		—				27,224				—			27,224				8	%
	Long duration bonds		—				48,049				—			48,049				14	%
	Corporate bonds		—				49,816				—			49,816				15	%
	High yield bonds		8,100				—				—			8,100				3	%
	Common trust fund - Bank loans		—				16,187				—			16,187				5	%
	Collateralized mortgage
	obligations		—				1,035				—			1,035				—	%
	Derivatives		48				(49		)		—			(1		)		—	%
	Equity Securities:																	31	%
	Large cap core index		9,982				—				—			9,982				3	%
	Large cap value		19,937				—				—			19,937				6	%
	Large cap growth		19,745				—				—			19,745				6	%
	Small cap value		31,329				—				—			31,329				9	%
	Common trust fund - International
	growth		—				22,877				—			22,877				7	%
	Real Estate:																	5	%
	Global REIT		16,675				—				—			16,675				5	%
	Other Investments:																	11	%
	Hedge fund of funds		—				19,829				—			19,829				6	%
	Private equity fund of funds		—				—				7,158			7,158				2	%
	Commodities fund of funds		—				10,134				—			10,134				3	%
	Total assets at fair value		$	133,748			$	195,537			$	7,158		$	336,443			100	%
	Percent of fair value hierarchy		40		%		58		%		2		%	100		%
	The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below.
			Other Benefits as of October 31, 2014
							Significant Other Observable Inputs(Level 2)
			Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
														Total Carrying Value				% of Total
	In thousands
	Cash and cash equivalents		$	2,590			$	—			$	—		$	2,590			9	%
	Fixed Income Securities:																	44	%
	U.S. treasuries		2,013				—				—			2,013				7	%
	Corporate bonds / Other fixed income
	securities		10,187				—				—			10,187				37	%
	Equity Securities:																	42	%
	Large cap value		1,269				—				—			1,269				4	%
	Large cap growth		1,310				—				—			1,310				5	%
	Small cap value		1,336				—				—			1,336				5	%
	Small cap growth		1,319				—				—			1,319				5	%
	Large cap index		2,532				—				—			2,532				9	%
	International blend		3,846				—				—			3,846				14	%
	Real Estate:																	5	%
	Global REIT		1,345				—				—			1,345				5	%
	Total assets at fair value		$	27,747			$	—			$	—		$	27,747			100	%
	Percent of fair value hierarchy		100		%		—		%		—		%	100		%
			Other Benefits as of October 31, 2013
							Significant Other Observable Inputs(Level 2)
			Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
														Total Carrying Value				% of Total
	In thousands
	Cash and cash equivalents		$	982			$	—			$	—		$	982			4	%
	Fixed Income Securities:																	46	%
	U.S. treasuries		2,582				—				—			2,582				10	%
	Corporate bonds / Other fixed income
	securities		9,232				—				—			9,232				36	%
	Equity Securities:																	45	%
Large cap value		1,327				—				—			1,327				5	%
Large cap growth		1,352				—				—			1,352				5	%
Small cap value		1,331				—				—			1,331				5	%
Small cap growth		1,313				—				—			1,313				5	%
Large cap index		2,384				—				—			2,384				9	%
International blend		4,206				—				—			4,206				16	%
Real Estate:																	5	%
Global REIT		1,252				—				—			1,252				5	%
Total assets at fair value		$	25,961			$	—			$	—		$	25,961			100	%
Percent of fair value hierarchy		100		%		—		%		—		%	100		%
		Qualified Pension Plan as of October 31, 2013
						Significant Other Observable Inputs(Level 2)
		Quoted Prices In Active Markets (Level 1)								Significant Unobservable Inputs (Level 3)
													Total Carrying Value				% of Total
In thousands
Cash and cash equivalents		$	5,566			$	156			$	—		$	5,722			2	%
Fixed Income Securities:																	38	%
U.S. treasuries		—				24,078				—			24,078				8	%
Long duration bonds		—				34,041				—			34,041				11	%
Corporate bonds		—				42,701				—			42,701				14	%
High yield bonds		14,680				—				—			14,680				5	%
Collateralized mortgage
obligations		—				1,098				—			1,098				—	%
Derivatives		6				(17		)		—			(11		)		—	%
Equity Securities:																	43	%
Large cap core index		12,023				—				—			12,023				4	%
Large cap value		16,908				—				—			16,908				6	%
Large cap growth		17,823				—				—			17,823				6	%
Small cap value		30,831				—				—			30,831				10	%
Common trust fund - International
value		—				24,460				—			24,460				8	%
Common trust fund - International
growth		—				27,270				—			27,270				9	%
Real Estate:																	5	%
Global REIT		15,042				—				—			15,042				5	%
Other Investments:																	12	%
Hedge fund of funds		—				18,571				—			18,571				6	%
Private equity fund of funds		—				—				4,659			4,659				2	%
Commodities fund of funds		—				10,765				—			10,765				4	%
Total assets at fair value		$	112,879			$	183,123			$	4,659		$	300,661			100	%
Percent of fair value hierarchy		37		%		61		%		2		%	100		%
Level 3 Qualified Pension Plan Reconciliation	The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.
			Private
			Equity Fund
	In thousands		of Funds
	Balance, October 31, 2012		$	3,522
	Actual return on plan assets:
	Relating to assets still held at the reporting date		116
	Relating to assets sold during the period		61
	Purchases, sales and settlements (net)		960
	Transfer in/out of Level 3		—
	Balance, October 31, 2013		4,659
	Actual return on plan assets:
	Relating to assets still held at the reporting date		1,031
	Relating to assets sold during the period		113
	Purchases, sales and settlements (net)		1,355
	Transfer in/out of Level 3		—
	Balance, October 31, 2014		$	7,158
401(k) Matching Contributions	For the years ended October 31, 2014, 2013 and 2012, we made matching contributions to participant accounts as follows.
	In thousands		2014				2013				2012
	401(k) matching contributions		$	6,134			$	5,688			$	5,400

Employee_Share_Based_Plans_Tab

Employee Share Based Plans (Tables)	12 Months Ended
	Oct. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]	The compensation expense related to the incentive compensation plans for the years ended October 31, 2014, 2013 and 2012, and the amounts recorded as liabilities in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities" in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.
	In thousands	2014		2013		2012
	Compensation expense	$	8,496	$	4,526	$	5,730
	Tax benefit	2,476		1,538		2,080
	Liability	15,130		11,098
Expected Payout For Approved Incentive Compensation Plans [Table Text Block]	Based on current accrual assumptions as of October 31, 2014, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.
	In thousands	2015		2016		2017
	Amount of payout	$	7,204	$	4,980	$	2,946

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Oct. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of income tax expense for the years ended October 31, 2014, 2013 and 2012 are presented below.
		2014						2013						2012
	In thousands	Federal			State			Federal			State			Federal			State
	Charged (Credited) to operating
	income:
	Current (1)	$	(1,653	)	$	950		$	(3,032	)	$	919		$	(29,062	)	$	1,857
	Deferred (1)	70,654			13,434			67,885			11,829			86,496			10,144
	Tax Credits:
	Amortization	(209		)	—			(267		)	—			(334		)	—
	Total	68,792			14,384			64,586			12,748			57,100			12,001
	Charged (Credited) to other income
	(expense):
	Current	4,233			870			6,049			984			5,636			1,027
	Deferred	5,811			728			2,225			(646		)	2,214			239
	Total	10,044			1,598			8,274			338			7,850			1,266
	Total	$	78,836		$	15,982		$	72,860		$	13,086		$	64,950		$	13,267
	(1) Includes utilization of federal NOL carryforward benefit of $28.6 million for the year ended October 31, 2014 and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014			2013			2012
	Federal taxes at 35%	$	83,517		$	77,127		$	69,322
	State income taxes, net of federal benefit	10,389			8,506			8,624
	Amortization of investment tax credits	(209		)	(267		)	(334		)
	Other, net	1,121			580			605
	Total	$	94,818		$	85,946		$	78,217
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	As of October 31, 2014 and 2013, deferred income taxes consisted of the following temporary differences.
	In thousands	2014			2013
	Deferred tax assets:
	Benefit of loss carryforwards	$	39,532		$	66,087
	Revenues and cost of gas	4,960			—
	Employee benefits and compensation	16,547			13,834
	Revenue requirement	20,320			19,062
	Utility plant	5,631			10,386
	Other	12,869			12,796
	Total deferred tax assets	99,859			122,165
	Valuation allowance	(505		)	(505		)
	Total deferred tax assets, net	99,354			121,660
	Deferred tax liabilities:
	Utility plant	724,172			652,822
	Revenues and cost of gas	4,340			21,257
	Equity method investments	42,998			38,710
	Deferred costs	65,828			59,221
	Other	18,065			18,324
	Total deferred tax liabilities	855,403			790,334
	Net deferred income tax liabilities	$	756,049		$	668,674
Summary of Valuation Allowance [Table Text Block]	A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014			2013			2012
	Balance at beginning of year	$	505		$	505		$	505
	Credited to income tax expense	—			—			—
	Balance at end of year	$	505		$	505		$	505

Equity_Method_Investments_Tabl

Equity Method Investments (Tables)	12 Months Ended
	Oct. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments [Table Text Block]	We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2014, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Transportation costs	$	8,825	$	8,775	$	6,613
	Trade accounts payable	747		755
	We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Gas storage costs	$	9,461	$	9,702	$	9,702
	Trade accounts payable	774		808
	Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2014 and 2013, and for the twelve months ended October 31, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013		2012
	Current assets	$	12,644	$	7,641
	Noncurrent assets	157,861		161,282
	Current liabilities	17,316		12,378
	Noncurrent liabilities	78,830		87,184
	Revenues	23,804		24,375		$	24,359
	Gross profit	23,804		24,375		24,359
	Income before income taxes	10,497		10,582		9,939
	Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013		2012
	Current assets	$	8,856	$	15,179
	Noncurrent assets	111,881		116,414
	Current liabilities	1,468		2,637
	Noncurrent liabilities	45,402		45,273
	Revenues	16,705		17,649		$	16,165
	Gross profit	16,705		17,649		16,165
	Income before income taxes	8,042		9,361		10,433
	We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Operating revenues	$	3,541	$	3,291	$	2,442
	Trade accounts receivable	460		441
	Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013*		2012
	Current assets	$	196,286	$	199,425
	Noncurrent assets	143,420		147,571
	Current liabilities	51,435		76,346
	Noncurrent liabilities	83		31
	Revenues	845,695		639,426		$	585,291
	Gross profit	234,581		174,993		161,122
	Income before income taxes	136,569		102,805		94,631
	* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.
	We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2014 and 2013 are as follows.
	In thousands	2014		2013		2012
	Gas storage costs	$	11,364	$	11,098	$	10,410
	Trade accounts payable	989		940
	Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
	In thousands	2014		2013		2012
	Current assets	$	8,812	$	9,225
	Noncurrent assets	70,837		74,710
	Current liabilities	38,029		3,531
	Noncurrent liabilities	—		35,391
	Revenues	18,025		16,810		$	16,390
	Gross profit	18,025		16,810		16,390
	Income before income taxes	6,011		5,804		5,832
	Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.
	In thousands	2014		2013 (1)
	Current assets	$	11,273	$	10,944
	Noncurrent assets	219,208		62,438
	Current liabilities	7,667		7,960
	Noncurrent liabilities	—		—
	Revenues	—		—
	Gross profit	—		—
	Income before income taxes	10,091		3,459
	(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012.

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	12 Months Ended
	Oct. 31, 2014
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Schedule Of Variable Interest Entities Investment Balances [Table Text Block]	As of October 31, 2014 and 2013, our investment balances are as follows.
		October 31,		October 31,
	In thousands	2014		2013
	Cardinal	$	16,073	$	18,207
	Pine Needle	18,689		20,270
	SouthStar	40,965		38,372
	Hardy Storage	37,179		34,681
	Constitution	57,255		16,939
	ACP	10
	Total equity method investments in non-utility activities	$	170,171	$	128,469

Business_Segments_Tables

Business Segments (Tables)	12 Months Ended
	Oct. 31, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Operations by segment for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014, 2013 and 2012 are presented below. The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.
					Regulated			Unregulated
		Regulated			Non-Utility			Non-Utility
	In thousands	Utility			Activities			Activities			Total
	2014
	Revenues from external customers	$	1,469,988		$	—		$	—		$	1,469,988
	Margin	690,208			—			—			690,208
	Operations and maintenance expenses	270,877			132			92			271,101
	Depreciation	118,996			—			18			119,014
	Operating income (loss) before income taxes	263,041			(183		)	(203		)	262,655
	Income from equity method investments	—			12,318			20,435			32,753
	Interest expense	54,686			—			—			54,686
	Income before income taxes	206,253			12,135			20,231			238,619
	Total assets	4,442,185			129,206			41,309			4,612,700
	Equity method investments in non-utility activities	—			129,206			40,965			170,171
	Construction expenditures	460,444			—			—			460,444
					Regulated			Unregulated
		Regulated			Non-Utility			Non-Utility
	In thousands	Utility			Activities			Activities			Total
	2013
	Revenues from external customers	$	1,278,229		$	—		$	—		$	1,278,229
	Margin	621,490			—			—			621,490
	Operations and maintenance expenses	253,120			103			78			253,301
	Depreciation	112,207			—			18			112,225
	Operating income (loss) before income taxes	221,528			(150		)	(202		)	221,176
	Income from equity method investments	—			10,584			15,472			26,056
	Interest expense	24,938			—			—			24,938
	Income before income taxes	194,659			10,434			15,270			220,363
	Total assets	4,053,591			90,097			38,735			4,182,423
	Equity method investments in non-utility activities	—			90,097			38,372			128,469
	Construction expenditures	599,999			—			—			599,999
					Regulated			Unregulated
		Regulated			Non-Utility			Non-Utility
	In thousands	Utility			Activities			Activities			Total
	2012
	Revenues from external customers	$	1,122,780		$	—		$	—		$	1,122,780
	Margin	575,446			—			—			575,446
	Operations and maintenance expenses	242,599			31			71			242,701
	Depreciation	103,192			—			18			103,210
	Operating income (loss) before income taxes	194,824			(78		)	(186		)	194,560
	Income from equity method investments	—			9,709			14,195			23,904
	Interest expense	20,097			—			—			20,097
	Income before income taxes	174,424			9,631			14,009			198,064
	Total assets	3,475,640			69,749			18,498			3,563,887
	Equity method investments in non-utility activities	—			69,749			18,118			87,867
	Construction expenditures	529,576			—			—			529,576
Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block]	Reconciliations to the consolidated financial statements for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014 and 2013 are as follows.
	In thousands	2014			2013			2012
	Operating Income:
	Segment operating income before income taxes	$	262,655		$	221,176		$	194,560
	Utility income taxes	(83,176		)	(77,334		)	(69,101		)
	Regulated non-utility activities operating loss before income taxes	183			150			78
	Unregulated non-utility activities operating loss before income taxes	203			202			186
	Total	$	179,865		$	144,194		$	125,723
	Net Income:
	Income before income taxes for reportable segments	$	238,619		$	220,363		$	198,064
	Income taxes	(94,818		)	(85,946		)	(78,217		)
	Total	$	143,801		$	134,417		$	119,847
Reconciliation of Assets from Segment to Consolidated [Table Text Block]
	In thousands	2014			2013
	Consolidated Assets:
	Total assets for reportable segments	$	4,612,700		$	4,182,423
	Eliminations/Adjustments	171,553			186,186
	Total	$	4,784,253		$	4,368,609

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Oct. 31, 2014
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
											Earnings (Loss)
								Net			Per Share of
		Operating				Operating		Income			Common Stock
		Revenues		Margin		Income		(Loss)			Basic			Diluted
	Fiscal Year 2014
	31-Jan	$	657,733	$	261,512	$	102,319	$	97,572		$	1.27		$	1.26
	30-Apr	462,247		211,523		67,299		62,540			0.8			0.8
	31-Jul	164,187		104,847		3,254		(7,344		)	(0.09		)	(0.09		)
	31-Oct	185,821		112,326		6,993		(8,967		)	(0.11		)	(0.11		)
	Fiscal Year 2013
	31-Jan	$	515,875	$	231,623	$	86,213	$	85,923		$	1.19		$	1.18
	30-Apr	399,411		183,856		51,504		55,790			0.74			0.74
	31-Jul	162,943		97,000		591		(2,293		)	(0.03		)	(0.03		)
	31-Oct	200,000		109,011		5,886		(5,003		)	(0.07		)	(0.07		)

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Details) (USD $)	1 Months Ended	12 Months Ended
	Apr. 30, 2014	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Dec. 31, 2013
		segment
Segment Reporting [Abstract]
Number of Reportable Segments		3
Regulatory Assets [Line Items]
Regulatory Assets, Current		$29,088,000	$77,204,000
Regulatory Assets, Noncurrent		184,779,000	169,102,000
Total Regulatory Assets		213,867,000	246,306,000
Other Regulatory Assets On Which We Do Not Earn a Return		98,100,000
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		46,231,000	0
Regulatory Liability, Noncurrent		558,598,000	541,897,000
Total Regulatory Liabilities		604,829,000	541,897,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use		3,155,000	3,155,000
Intangible plant		3,374,000	3,374,000
Other storage plant		180,058,000	171,349,000
Transmission plant		1,787,990,000	1,403,829,000
Distribution plant		2,623,560,000	2,505,160,000
General plant		421,763,000	335,847,000
Asset retirement cost		11,000	7,565,000
Contributions in aid of construction		-5,259,000	-5,187,000
Total utility plant in service		5,011,497,000	4,421,937,000
Less accumulated depreciation		-1,166,922,000	-1,088,331,000
Utility plant in service, net		3,844,575,000	3,333,606,000
Construction work in progress		141,693,000	297,717,000
Plant held for future use		3,155,000	3,155,000
Total utility plant, net		3,989,423,000	3,634,478,000
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment			1,800,000
Property, Plant and Equipment [Line Items]
Allowance for borrowed funds used during construction		16,427,000	30,975,000	25,211,000
Composite weighted-average depreciation rates		2.54%	2.77%	2.94%
Accounts, Notes, Loans and Financing Receivable, Net, Current [Abstract]
Gas receivables		64,400,000	78,540,000
Non-regulated merchandise and service work receivables		3,012,000	2,274,000
Allowance for doubtful accounts		-2,152,000	-1,604,000	-1,579,000
Trade accounts receivable		65,260,000	79,210,000
Customers Payment Due Date		30 days
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year		1,604,000	1,579,000	1,347,000
Additions charged to uncollectibles expense		6,959,000	5,314,000	4,584,000
Accounts written off, net of recoveries		-6,411,000	-5,289,000	-4,352,000
Balance at end of year		2,152,000	1,604,000	1,579,000
Inventory, Net [Abstract]
Natural Gas Inventories Not Available For Sale Held by Asset Manager		35,000,000	31,500,000
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Near Term Redemption		180 days
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill, Accumulated Impairment Loss		0
Goodwill, Impairment Loss		0	0	0
Asset Impairment Charges	2,000,000		0	0
Investment Measurement [Line Items]
Current trading securities (cost)		128,000	134,000
Noncurrent trading securities(cost)		3,045,000	2,375,000
Current trading securities		214,000	199,000
Noncurrent trading securities		3,727,000	2,995,000
Total trading securities		3,941,000	3,194,000
Total trading securities (cost)		3,173,000	2,509,000
Deferred Finance Costs [Abstract]
Long Term Debt Expense Amortization Period		5 to 30 years
Short Term Debt Expense Amortization Period		5 years
Asset Retirement Obligations [Line Items]
Regulatory non-legal AROs		506,574,000	493,111,000
Conditional cost of removal obligations		14,647,000	27,016,000
Total cost of removal obligations		521,221,000	520,127,000
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of period		27,016,000	28,629,000
Liabilities incurred during the period		2,108,000	2,052,000
Liabilities settled during the period		-3,576,000	-2,389,000
Accretion		1,548,000	1,641,000
Adjustment to estimated cash flows		-12,449,000	-2,917,000
End of period		14,647,000	27,016,000	28,629,000
Weighted Average Risk Free Rate		5.09%
Money Market Funds [Member]
Investment Measurement [Line Items]
Current trading securities (cost)		22,000	0
Noncurrent trading securities(cost)		447,000	380,000
Current trading securities		22,000	0
Noncurrent trading securities		447,000	380,000
Total trading securities		469,000	380,000
Equity Funds [Member]
Investment Measurement [Line Items]
Current trading securities (cost)		106,000	134,000
Noncurrent trading securities(cost)		2,598,000	1,995,000
Current trading securities		192,000	199,000
Noncurrent trading securities		3,280,000	2,615,000
Total trading securities		3,472,000	2,814,000
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 years
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Credit Adjusted Risk Free Rate		4.40%
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		80 years
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Credit Adjusted Risk Free Rate		5.15%
Land Costs [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use				3,200,000
Plant held for future use				3,200,000
Non-real Estate Costs [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use				3,500,000
Plant held for future use				3,500,000
Amount Due To Customers
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		46,231,000	0
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent		506,574,000	493,111,000
Deferred Income Tax Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent		51,930,000	48,647,000
Amounts Not Yet Recognized As Component Of Pension and Other Post Retirement Benefit Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent		94,000	139,000
NCUC [Member]
Property, Plant and Equipment [Line Items]
Depreciation Study Requirement		5 years
Unamortized debt expense
Regulatory Assets [Line Items]
Regulatory Assets, Current		1,490,000	1,274,000
Regulatory Assets, Noncurrent		15,402,000	14,149,000
Amounts due from customers
Regulatory Assets [Line Items]
Regulatory Assets, Current		16,108,000	66,321,000
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets, Current		1,568,000	1,480,000
Regulatory Assets, Noncurrent		6,470,000	7,936,000
Total Regulatory Assets		8,000,000
Environmental costs | PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		100,000
Total Regulatory Assets		100,000
Amortization Time Period For Specified Expenses		1 year
Regulatory Noncurrent Asset, End Date for Recovery		31-Oct-15
Deferred operations and maintenance expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current		916,000	739,000
Regulatory Assets, Noncurrent		4,721,000	5,637,000
Deferred operations and maintenance expenses | NCUC [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets		5,600,000	6,400,000
Deferred pipeline integrity expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current		3,470,000	3,149,000
Regulatory Assets, Noncurrent		24,694,000	16,300,000
Deferred pipeline integrity expenses | NCUC [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets		28,200,000	19,400,000
Deferred pension and other retirement benefits costs
Regulatory Assets [Line Items]
Regulatory Assets, Current		2,769,000	2,768,000
Regulatory Assets, Noncurrent		18,799,000	17,968,000
Amounts Not Yet Recognized As Component Of Pension and Other Post Retirement Benefit Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent		94,265,000	80,604,000
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent		18,275,000	22,974,000
Amount Of Regulatory Costs Approved To Be Accrued Not Included In Rate Base		18,300,000
Robeson LNG Development Cost [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		917,000	382,000
Regulatory Assets, Noncurrent		509,000	1,426,000
Robeson LNG Development Cost [Member] | NCUC [Member] | General Rate Application Settlement 2013 [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets					1,200,000
Amortization Time Period For Specified Expenses		38 months
Regulatory Noncurrent Asset, End Date for Recovery		28-Feb-17
Robeson LNG Development Cost [Member] | PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		500,000
Amortization Time Period For Specified Expenses		12 months
Regulatory Noncurrent Asset, End Date for Recovery		31-Oct-15
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		1,850,000	1,091,000
Regulatory Assets, Noncurrent		$1,644,000	$2,108,000

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

24 Months Ended

1 Months Ended

2 Months Ended

Oct. 31, 2014

Oct. 31, 2013

Oct. 31, 2012

Dec. 31, 1998

Apr. 30, 2014

Dec. 31, 2001

Dec. 31, 2000

Dec. 31, 2001

Nov. 30, 2014

Dec. 31, 2014

31-May-12

Oct. 31, 2011

Sep. 30, 2014

Dec. 31, 2014

Jan. 01, 2014

Oct. 31, 2008

Dec. 31, 2013

Aug. 31, 2013

Mar. 01, 2012

Feb. 29, 2012

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Description of Regulatory Scope

Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities. The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.

Regulatory Assets

$213,867,000

$246,306,000

Regulatory Assets, Current

29,088,000

77,204,000

Payments to Acquire Property, Plant, and Equipment

460,444,000

599,999,000

529,576,000

Operations and maintenance

270,877,000

253,120,000

242,599,000

Total Amount Of Margin Generated From Secondary Market Activity

97,600,000

35,900,000

38,700,000

Amount Of Net Secondary Market Margins Flowed Through To Jurisdictional Customers

72,200,000

26,900,000

29,000,000

Amount Of Net Secondary Market Margins Retained

25,400,000

9,000,000

9,700,000

North Carolina

Public Utilities, Rate Matters, Requested [Abstract]

North Carolina Bond Issuance Amount

200,000,000

Capital Investments In Integrity and Safety Projects

241,900,000

Tennessee

Public Utilities, Rate Matters, Requested [Abstract]

Capital Investments In Integrity and Safety Projects

54,000,000

Deferred operations and maintenance expenses

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

916,000

739,000

Deferred pipeline integrity expenses

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

3,470,000

3,149,000

Environmental costs

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

8,000,000

Regulatory Assets, Current

1,568,000

1,480,000

Robeson LNG Development Cost [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

917,000

382,000

Other Regulatory Assets (Liabilities) [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

1,850,000

1,091,000

NCUC [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Debt Equity Securities Limit, Amount

1,000,000,000

1,000,000,000

Public Utilities, Rate Matters, Requested [Abstract]

Request Transfer Plant Held For Future Use To Deferred Regulatory Asset

6,700,000

Percentage Of Net Secondary Market Margins Flowed Through To Customers

75.00%

Percentage Of Net Secondary Market Margins Retained

25.00%

NCUC [Member] | Minimum [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Target Percentage Range Normalized Sales

22.50%

NCUC [Member] | Maximum [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Target Percentage Range Normalized Sales

45.00%

NCUC [Member] | EasternNC Exclusive Franchise Rights [Member]

Public Utilities, Rate Matters, Requested [Abstract]

North Carolina Bond Issuance Amount

149,600,000

38,700,000

188,300,000

Operational Feasibility Assessment Time Period

2 years

NCUC [Member] | General Rate Case Proceeding 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Overall Rate Base With Approved Rates And Charges

1,800,000,000

Public Utilities, Approved Return on Equity, Percentage

10.00%

Public Utilities, Approved Return on Investment, Percentage

7.51%

Public Utilities, Approved Equity Capital Structure, Percentage

50.70%

Approved Annual Average Revenue Percentage Increase From Last Rate Case

0.70%

NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Sales [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

30,700,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.58%

NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Sales [Member] | Gas Utility Margin [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

16,800,000

NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Sales [Member] | Fixed Gas Costs [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

13,800,000

NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Revised Pre-Tax Income [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

24,200,000

NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Operating Expense [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

-10,900,000

NCUC [Member] | North Carolina Public Staff Audit 2011 Gas Cost Review Period [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

NCUC [Member] | North Carolina Public Staff Audit 2012 Gas Cost Review Period [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

NCUC [Member] | North Carolina Public Staff Audit 2013 Gas Cost Review Period [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

NCUC [Member] | North Carolina Public Staff Audit 2013 Gas Cost Review Period [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

NCUC [Member] | North Carolina Public Staff Audit 2014 Gas Cost Review Period [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

NCUC [Member] | North Carolina IMR Adjustment 2014 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

800,000

NCUC [Member] | NCUC Petition for IMR Rate Adjustment Filed December 2014 [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

26,600,000

Public Utilities, Disclosure of Rate Matters

In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.

NCUC [Member] | NCUC Petition for Limited Waiver 2014 [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Operations and maintenance

65,000

NCUC [Member] | Deferred operations and maintenance expenses

Public Utilities, Rate Matters, Approved [Abstract]

Deferral Time Period Of Operation And Maintenance Expense

8 years

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

5,600,000

6,400,000

NCUC [Member] | Deferred operations and maintenance expenses | General Rate Case Proceeding 2008 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Interest Accrued On Deferred Expenses

7.84%

Amortization Time Period For Specified Expenses

12 years

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

9,000,000

NCUC [Member] | Deferred operations and maintenance expenses | General Rate Case Proceeding 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Interest Accrued On Deferred Expenses

6.55%

Amortization Time Period For Specified Expenses

82 months

Regulatory Noncurrent Asset, End Date for Recovery

31-Oct-20

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

6,300,000

NCUC [Member] | Deferred pipeline integrity expenses

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

28,200,000

19,400,000

NCUC [Member] | Deferred pipeline integrity expenses | General Rate Case Proceeding 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

5 years

Regulatory Noncurrent Asset, End Date for Recovery

31-Dec-18

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

17,300,000

NCUC [Member] | Environmental costs | General Rate Case Proceeding 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

5 years

Regulatory Noncurrent Asset, End Date for Recovery

31-Dec-18

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

6,300,000

NCUC [Member] | Robeson LNG Development Cost [Member] | General Rate Case Proceeding 2013 [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

1,200,000

NCUC [Member] | Robeson LNG Development Cost [Member] | General Rate Application Settlement 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

38 months

Regulatory Noncurrent Asset, End Date for Recovery

28-Feb-17

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

1,200,000

PSCSC [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Percentage Of Net Secondary Market Margins Flowed Through To Customers

75.00%

Percentage Of Net Secondary Market Margins Retained

25.00%

Maximum Utility Rate of Return Change Allowed Under RSA

50

PSCSC [Member] | Minimum [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Target Percentage Range Normalized Sales

22.50%

PSCSC [Member] | Maximum [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Target Percentage Range Normalized Sales

45.00%

PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2012 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

11.30%

PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2012 [Member] | Margin [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

-1,100,000

PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

11.30%

PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2013 [Member] | Margin [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

-100,000

PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

10.20%

PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member] | Margin [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

-2,900,000

PSCSC [Member] | Environmental costs | Settlement With Office Of Regulatory Staff October 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

1 year

Regulatory Noncurrent Asset, End Date for Recovery

31-Oct-14

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

200,000

PSCSC [Member] | Environmental costs | Settlement With Office of Regulatory Staff October 2014 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

1 year

Regulatory Noncurrent Asset, End Date for Recovery

31-Oct-15

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

100,000

Regulatory Assets, Current

100,000

PSCSC [Member] | Robeson LNG Development Cost [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

12 months

Regulatory Noncurrent Asset, End Date for Recovery

31-Oct-15

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

500,000

Tennessee Regulatory Authority [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Percentage Of Net Secondary Market Margins Flowed Through To Customers

75.00%

Percentage Of Net Secondary Market Margins Retained

25.00%

Annual Incentive Cap On Gains And Losses

1,600,000

Tennessee Regulatory Authority [Member] | Collection Nashville Franchise Fee [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Denied Franchise Fees

1,500,000

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

2,900,000

Operations and maintenance

-500,000

1,500,000

Tennessee Regulatory Authority [Member] | Actual Cost Adjustment [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

Tennessee Regulatory Authority [Member] | Adjustment Filed August 2013 [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

3,700,000

Expense Related to Actual Cost Adjustment

1,700,000

Tennessee Regulatory Authority [Member] | TRA Settlement December 2014 [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

2,000,000

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In November 2014, we filed a joint settlement agreement with the TRA and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the filed ACA annual report for the twelve-month period ended June 30, 2013.

Tennessee Regulatory Authority [Member] | General Rate Application Settlement 2012 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

10.20%

Public Utilities, Rate Matters, Requested [Abstract]

Recovery Of Fixed Charges Cost Allocations

37.00%

29.00%

Recovery Of Volumetric Charges Cost Allocations

63.00%

71.00%

Tennessee Regulatory Authority [Member] | General Rate Application Settlement 2012 [Member] | Sales [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

11,900,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

6.30%

Tennessee Regulatory Authority [Member] | Tennessee IMR Petition August 2013 [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

13,100,000

Tennessee Regulatory Authority [Member] | Tennessee IMR Settlement 2013 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

13,100,000

Tennessee Regulatory Authority [Member] | TRA IMR Rate Adjustment Petition Filed December 2014 [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

6,500,000

Public Utilities, Disclosure of Rate Matters

In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the TRA at this time.

Tennessee Regulatory Authority [Member] | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

-4,700,000

Tennessee Regulatory Authority [Member] | Tennessee CNG Rider Petition September 2014 [Member] | Subsequent Event [Member]

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015. A hearing on this matter has been scheduled for January 12, 2015.

Tennessee Regulatory Authority [Member] | Environmental costs | General Rate Application Settlement 2012 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

8 years

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

2,000,000

Tennessee Regulatory Authority [Member] | Other Regulatory Assets (Liabilities) [Member] | General Rate Application Settlement 2012 [Member]

Public Utilities, Rate Matters, Approved [Abstract]

Amortization Time Period For Specified Expenses

8 years

Regulatory Noncurrent Asset, End Date for Recovery

28-Feb-20

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

1,000,000

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Earnings Per Share [Abstract]
Net income	($8,967)	($7,344)	$62,540	$97,572	($5,003)	($2,293)	$55,790	$85,923	$143,801	$134,417	$119,847
Average shares of common stock outstanding for basic earnings per share									77,883	74,884	71,977
Contingently issuable shares under incentive compensation plans									310	289	301
Contingently issuable shares under forward sale agreements									0	160	0
Average shares of dilutive stock									78,193	75,333	72,278
Basic (usd per share)	($0.11)	($0.09)	$0.80	$1.27	($0.07)	($0.03)	$0.74	$1.19	$1.85	$1.80	$1.67
Diluted (usd per share)	($0.11)	($0.09)	$0.80	$1.26	($0.07)	($0.03)	$0.74	$1.18	$1.84	$1.78	$1.66

Long_Term_Debt_Details

Long Term Debt (Details) (USD $)	12 Months Ended	1 Months Ended	0 Months Ended
	Oct. 31, 2014	Apr. 30, 2014	Sep. 18, 2014	Aug. 01, 2013	Oct. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Gross	$1,425,000,000				$1,275,000,000
Current maturities of long-term debt	0				100,000,000
Discount on issuance of notes	570,000				143,000
Long-term debt	1,424,430,000				1,174,857,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	40,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	35,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	1,350,000,000
Total Long-term Debt	1,425,000,000				1,275,000,000
Net Earnings Available For Restricted Payments	1,100,000,000
Debt Instrument, Covenant Description	The default provisions of some or all of our senior debt include: Failure to make principal or interest payments, Bankruptcy, liquidation or insolvency, Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal, Specified events under the Employee Retirement Income Security Act of 1974, Change in control, and Failure to observe or perform covenants, including: Interest coverage of at least 1.75 times. Funded debt cannot exceed 70% of total capitalization. Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. Restrictions on permitted liens; Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and Restrictions on burdensome agreements.
Senior Debt Default Provision, Interest Coverage Ratio	1.75
Interest Coverage Ratio	4.29
Senior Debt Default Provision, Ratio of Indebtedness to Net Capital	0.7
Ratio of Indebtedness to Net Capital	0.58
Senior Debt Default Provision, Funded Debt of Subsidiaries	0.15
Funded Debt Of Subsidiaries	0
NCUC [Member]
Long-term Debt, Fiscal Year Maturity [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount	1,000,000,000	1,000,000,000
Debt and Equity Shelf Registration, Term	3 years
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	1,425,000,000				1,275,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	1,425,000,000				1,275,000,000
Senior Notes 2.92% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.92%
Debt Instrument, Maturity Date	6-Jun-16
Senior Notes 2.92% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	40,000,000				40,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	40,000,000				40,000,000
Senior Notes 8.51% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.51%
Debt Instrument, Maturity Date	30-Sep-17
Senior Notes 8.51% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	35,000,000				35,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	35,000,000				35,000,000
Senior Notes 4.24% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.24%
Debt Instrument, Maturity Date	6-Jun-21
Senior Notes 4.24% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	160,000,000				160,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	160,000,000				160,000,000
Senior Notes 3.47% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.47%
Debt Instrument, Maturity Date	16-Jul-27
Senior Notes 3.47% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	100,000,000				100,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	100,000,000				100,000,000
Senior Notes 3.57% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.57%
Debt Instrument, Maturity Date	16-Jul-27
Senior Notes 3.57% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	200,000,000				200,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	200,000,000				200,000,000
Senior Notes 4.10% [Member]
Debt Instrument [Line Items]
Discount on issuance of notes	432,000		435,000
Debt Instrument, Interest Rate, Stated Percentage	4.10%
Debt Instrument, Maturity Date	18-Sep-34
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Face Amount			250,000,000
Debt Instrument, Issuance Date	18-Sep-14
Debt Instrument, Term	20 years
Proceeds from Debt, Net of Issuance Costs			247,700,000
Debt Issuance Discount Percentage			0.17%
Senior Notes 4.10% [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	18-Sep-14
Debt Instrument, Redemption Period, End Date	17-Mar-34
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.10% [Member] | Debt Instrument, Redemption, Period One [Member] | Base Rate [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate	0.15%
Senior Notes 4.10% [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	100% of the principal amount plus any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	18-Mar-34
Debt Instrument, Redemption Period, End Date	18-Sep-34
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.10% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	250,000,000				0
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	250,000,000				0
Senior Notes 4.65% [Member]
Debt Instrument [Line Items]
Discount on issuance of notes	138,000			144,000	143,000
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	1-Aug-43
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Face Amount				300,000,000
Debt Instrument, Issuance Date	1-Aug-13
Debt Instrument, Term	30 years
Proceeds from Debt, Net of Issuance Costs				297,200,000
Debt Issuance Discount Percentage				0.05%
Senior Notes 4.65% [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	1-Aug-13
Debt Instrument, Redemption Period, End Date	31-Jan-43
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.65% [Member] | Debt Instrument, Redemption, Period One [Member] | Base Rate [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate	0.15%
Senior Notes 4.65% [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	100% of the principal amount plus any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	1-Feb-43
Debt Instrument, Redemption Period, End Date	1-Aug-43
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.65% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	300,000,000				300,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	300,000,000				300,000,000
Medium Term Notes 5.00% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	19-Dec-13
Medium Term Notes 5.00% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0				100,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	0				100,000,000
Medium Term Notes 6.87% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.87%
Debt Instrument, Maturity Date	6-Oct-23
Medium Term Notes 6.87% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	45,000,000				45,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	45,000,000				45,000,000
Medium Term Notes 8.45% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.45%
Debt Instrument, Maturity Date	19-Sep-24
Medium Term Notes 8.45% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	40,000,000				40,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	40,000,000				40,000,000
Medium Term Notes 7.40% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.40%
Debt Instrument, Maturity Date	3-Oct-25
Medium Term Notes 7.40% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	55,000,000				55,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	55,000,000				55,000,000
Medium Term Notes 7.50% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	9-Oct-26
Medium Term Notes 7.50% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	40,000,000				40,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	40,000,000				40,000,000
Medium Term Notes 7.95% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.95%
Debt Instrument, Maturity Date	14-Sep-29
Medium Term Notes 7.95% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	60,000,000				60,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	60,000,000				60,000,000
Medium Term Notes 6.00% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Debt Instrument, Maturity Date	19-Dec-33
Medium Term Notes 6.00% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	100,000,000				100,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	$100,000,000				$100,000,000

Short_Term_Debt_Details

Short Term Debt (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$850,000,000
Ratio of Indebtedness to Net Capital	0.58
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	1-Oct-17
Line of Credit Facility, Current Borrowing Capacity	850,000,000
Line of Credit Facility, Commitment Fee Description	$35,000 plus 8.5 basis
Line of Credit Facility, Frequency of Commitment Fee Payment	annual
Line of Credit Facility, Commitment Fee Amount	35,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.09%
Line of Credit Facility, Interest Rate Description	30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points
Line of Credit Facility, Covenant Terms	total debt to total capitalization of no greater than 70%
Line of Credit Facility, Covenant Compliance	actual ratio was 58%
Debt Covenant Total Debt To Total Capital Ratio	70.00%
Ratio of Indebtedness to Net Capital	0.58
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	10,000,000	10,000,000
Letters of Credit Outstanding, Amount	1,800,000	2,100,000
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	850,000,000
Line of Credit Facility, Interest Rate Description	interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points
Short-term Debt, Description	$850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt.
Maximum Number Of Possible Days Outstanding For Commercial Paper Program	397 days
Commercial Paper	355,000,000	400,000,000
Short-term Debt, Weighted Average Interest Rate	0.17%	0.36%
Minimum Amount Outstanding During Period	275,000,000
Maximum Amount Outstanding During Period	$625,000,000
Commercial Paper [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity	4 days
Line of Credit Facility, Interest Rate During Period	0.10%
Commercial Paper [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity	28 days
Line of Credit Facility, Interest Rate During Period	0.43%
Commercial Paper [Member] | Weighted Average [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Interest Rate During Period	0.19%
Base Rate [Member] | Commercial Paper [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	0.05%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	0.75%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	1.25%

Stockholders_Equity_Details

Stockholders' Equity (Details) (USD $)	0 Months Ended					3 Months Ended								12 Months Ended			0 Months Ended
	Dec. 16, 2013	Feb. 04, 2013	Jan. 29, 2013	Feb. 28, 2012	Jan. 05, 2012	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Feb. 19, 2013	Dec. 16, 2005	Sep. 30, 2004	Mar. 06, 2009
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Beginning Balance									76,099,000				72,250,000	76,099,000	72,250,000	72,318,000
Common Stock, Value, Issued, Beginning Balance									$561,644,000				$442,461,000	$561,644,000	$442,461,000	$446,791,000
Stock Issued During Period, Shares, Employee Stock Purchase Plans														34,000	33,000	30,000
Stock Issued During Period, Value, Employee Stock Purchase Plan														1,143,000	1,056,000	894,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan														698,000	720,000	677,000
Stock Issued During Period, Value, Dividend Reinvestment Plan														23,443,000	22,791,000	20,508,000
Shares Issued During Period Shares Incentive Compensation Plan (ICP)														100,000	96,000	25,000
Shares Issued During Period Value Incentive Compensation Plan (ICP)														3,315,000	3,065,000	796,000
Shares Repurchased During Period Shares Accelerated Share Repurchase (ASR) Plan					-800,000											-800,000
Shares repurchased under Accelerated Share Repurchase (ASR) agreement																-26,528,000
Issuance of commons stock shares through public share offering, net of underwriting fees	1,600,000	3,000,000												1,600,000	3,000,000
Issuance of common stock through public share offering, net of underwriting fees														47,290,000	92,640,000
Expenses from Issuance of Common Stock														-12,000	-369,000
Common Stock, Shares, Outstanding, Ending Balance						78,531,000				76,099,000				78,531,000	76,099,000	72,250,000
Common Stock, Value, Issued, Ending Balance						636,835,000				561,644,000				636,835,000	561,644,000	442,461,000
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated OCIL beginning balance, net of tax									-284,000				-305,000	-284,000	-305,000
Total other comprehensive income														47,000	21,000	147,000
Accumulated OCIL ending balance, net of tax						-237,000				-284,000				-237,000	-284,000	-305,000
Accelerated Share Repurchases, Initial Price Paid Per Share					$33.77
Stock Repurchased During Period Value At Initial Price ASR Plan					-27,000,000
Accelerated Share Repurchases, Settlement (Payment) or Receipt				500,000
Accelerated Share Repurchases Weighted Average Purchase Price Per Share				$33.25
Accelerated Share Repurchases Discount On Weighted Average Purchase Price Per Share				$0.09
Accelerated Share Repurchases, Final Price Paid Per Share				$33.16
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						1,966,000								1,966,000
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Equity Method Investments														32,753,000	26,056,000	23,904,000
Income taxes														-11,642,000	-8,612,000	-9,116,000
Net Income						-8,967,000	-7,344,000	62,540,000	97,572,000	-5,003,000	-2,293,000	55,790,000	85,923,000	143,801,000	134,417,000	119,847,000
Forward Contract Indexed to Issuer's Equity [Line Items]
Maximum Number Of Shares To Be Purchased			4,600,000
Common Stock Issued, Value	47,300,000	92,600,000												75,203,000	119,552,000	22,198,000
Common Stock Issued, Shares	1,600,000	3,000,000												1,600,000	3,000,000
Shares Issued, Price Per Share		$32
Underwriter Discount		$1.12
Net Settlement Price Per Share	$30.88	$30.88
Forward Contract Indexed to Issuer's Equity, Settlement Date														16-Dec-13
Combined Forward Sale Agreements [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		1,600,000
Forward Sale Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		1,000,000
Additional Forward Sale Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares Option To Purchase Exercised By Underwriters																	600,000
Additional Forward Sale Agreement [Member] | Maximum [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Indexed Shares		600,000
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income														-308,000	130,000
Common Stock Open Market Purchase Program [Member]
Class of Stock [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased																		6,000,000	3,000,000
ASR Program [Member]
Class of Stock [Line Items]
Additional Authorized Common Stock Repurchases Shares																		4,000,000
Common Stock Open Market Purchase Program and ASR Program [Member]
Class of Stock [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased																		10,000,000
Additional Authorized Common Stock Repurchases Shares																				4,000,000
Employee Stock Purchase Plan [Member]
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						176,000								176,000
Dividend Reinvestment Plan [Member]
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						840,000								840,000
Stock Compensation Plan [Member]
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						950,000								950,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax														355,000	-109,000
Amounts reclassified, net of tax														-284,000	130,000
Total other comprehensive income														71,000	21,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Equity Method Investments														-461,000	215,000
Income taxes														177,000	-85,000
Net Income														-284,000	130,000
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Total other comprehensive income														-24,000
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Equity Method Investments														-40,000
Income taxes														16,000
Net Income														($24,000)

Financial_Instruments_Related_2

Financial Instruments & Related Fair Value (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
	MMBTU	MMBTU
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Options Total Coverage	29,200,000	25,400,000
Fair Value Measurement Transfers Between Levels Activity	$0	$0
Derivative Liability	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Assets [Abstract]
Derivative Asset	4,898,000	1,834,000
Marketable Securities	3,941,000	3,194,000
Total Recurring Fair Value Assets	8,839,000	5,028,000
Long-term debt, carrying value	1,425,000,000	1,275,000,000
Long-term debt, fair value	1,617,453,000	1,409,892,000
Discount on issuance of notes	570,000	143,000
Current Assets, Gas purchase derivative assets	4,898,000	1,834,000
Gas purchase options	6,162,000	-6,303,000
Amount Of Gain (Loss) Deferred Under PGA Procedures	6,162,000	-6,303,000
Percentage Of Annual Gas Purchase Options and All Other Costs Related To Hedging Approved For Recovery Under TIP	1.00%
Concentration Risk [Line Items]
Concentration Risk, Benchmark Description	“Trade accounts receivable” in “Current Assets” in the Condensed Consolidated Balance Sheets
Concentration Risk, Customer	We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base. We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers.
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk Amount	3,500,000
Accounts Receivable [Member] | Credit Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	5.00%
Money Market Funds [Member]
Assets [Abstract]
Marketable Securities	469,000	380,000
Equity Funds [Member]
Assets [Abstract]
Marketable Securities	3,472,000	2,814,000
Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Derivative Asset	4,898,000	1,834,000
Total Recurring Fair Value Assets	8,839,000	5,028,000
Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Assets [Abstract]
Marketable Securities	469,000	380,000
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Assets [Abstract]
Marketable Securities	3,472,000	2,814,000
Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Derivative Asset
Total Recurring Fair Value Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Money Market Funds [Member]
Assets [Abstract]
Marketable Securities
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Assets [Abstract]
Marketable Securities
Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative Asset
Total Recurring Fair Value Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Money Market Funds [Member]
Assets [Abstract]
Marketable Securities
Fair Value, Inputs, Level 3 [Member] | Equity Funds [Member]
Assets [Abstract]
Marketable Securities

Commitment_Contingencies_Detai

Commitment & Contingencies (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Mar. 01, 2012	Dec. 31, 2013
	regulatory_commission
	sites
Guarantor Obligations [Line Items]
Payments for Rent	$4,701,000	$4,729,000	$3,712,000
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	4,600,000
Operating Leases, Future Minimum Payments, Due in Two Years	4,491,000
Operating Leases, Future Minimum Payments, Due in Three Years	4,297,000
Operating Leases, Future Minimum Payments, Due in Four Years	4,225,000
Operating Leases, Future Minimum Payments, Due in Five Years	4,137,000
Operating Leases, Future Minimum Payments, Due Thereafter	27,359,000
Operating Leases Future Minimum Payments Due	49,109,000
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	223,250,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	154,335,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	146,450,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	142,559,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	132,266,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	627,602,000
Unrecorded Unconditional Purchase Obligation	1,426,462,000
Number Of Regulatory Commissions	3
MGP Sites Under Settlement	9
Site Contingency, Unasserted Claims	0
Site Contingency [Line Items]
Environmental Costs Incurred to Date	6,912,000
Undiscounted Environmental Liability	1,259,000
Regulatory Assets [Line Items]
Regulatory Assets	213,867,000	246,306,000
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets	8,000,000
Tennessee Regulatory Authority [Member] | Environmental costs | General Rate Application Settlement 2012 [Member]
Regulatory Assets [Line Items]
Regulatory Assets				2,000,000
Amortization Time Period For Specified Expenses	8 years
NCUC [Member] | Environmental costs | General Rate Case Proceeding 2013 [Member]
Regulatory Assets [Line Items]
Regulatory Assets					6,300,000
Amortization Time Period For Specified Expenses	5 years
PSCSC [Member] | Environmental costs | Settlement With Office of Regulatory Staff October 2014 [Member]
Regulatory Assets [Line Items]
Regulatory Assets	100,000
Amortization Time Period For Specified Expenses	1 year
Anderson SC MGP Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	7,000
Undiscounted Environmental Liability	890,000
Hickory NC MGP Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	1,494,000
Undiscounted Environmental Liability	18,000
Reidsville NC MGP Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	641,000
Undiscounted Environmental Liability	199,000
Huntersville NC LNG Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	4,738,000
Undiscounted Environmental Liability	81,000
Charlotte NC UST Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	32,000
Undiscounted Environmental Liability	33,000
Clemmons NC UST Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	0
Undiscounted Environmental Liability	38,000
Pipeline And Storage Capacity Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	158,984,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	149,412,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	145,579,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	142,433,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	132,186,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	627,602,000
Unrecorded Unconditional Purchase Obligation	1,356,196,000
Gas Supply Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	8,657,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	137,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	135,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	8,929,000
Telecommunications And Technology Outsourcing Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	14,601,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	4,786,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	736,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	126,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	80,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	20,329,000
Others [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	41,008,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	41,008,000
Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1,800,000
Surety Bond [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$4,800,000

Commitment_Contingencies_Long_

Commitment & Contingencies - Long Term Contracts (Details) (Maximum [Member])	12 Months Ended
	Oct. 31, 2014
Pipeline And Storage Capacity Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	21 years
Gas Supply Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	3 years
Telecommunications And Technology Outsourcing Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	5 years

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Measurement Date	31-Oct
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Noncurrent assets	$33,757,000	$28,258,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Regulatory asset	-213,867,000	-246,306,000
Defined Benefit Plan Actuarial Gains And Losses Amortization Corridor	5 years
Gains And Losses Amortized In Excess Of Percentage	10.00%
Qualified Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.
Standard Eligibility Age For Defined Benefit Plan	30 years
Service Required For Eligibility In Defined Benefit Plan	125 days
Years Of Highest Compensation For Benefit Calculation	5 years
Duration To Complete Service Requirement	12 months
Horizon For DBPP Long Term Rates Of Return	20 years
Period Of Compensation For Benefit Calculation	10 years
Plan Vesting Period Defined Benefit Plan	5 years
Maximum Credited Service Period	35 years
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	336,443,000	300,661,000	272,337,000
Defined Benefit Pension Plan Funding Target	100.00%
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	10,000,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End	252,706,000	230,175,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	272,403,000	293,327,000
Service cost	10,865,000	12,005,000	9,573,000
Interest cost	11,781,000	9,946,000	10,640,000
Plan amendments	0	0
Actuarial (gain) loss	23,646,000	-24,859,000
Participant contributions	0	0
Administrative expenses	-465,000	-534,000
Benefit payments	-15,544,000	-17,482,000
Obligation at end of year	302,686,000	272,403,000	293,327,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	300,661,000	272,337,000
Actual return on plan assets	31,791,000	26,340,000
Employer contributions	20,000,000	20,000,000
Participant contributions	0	0
Administrative expenses	-465,000	-534,000
Benefit payments	-15,544,000	-17,482,000
Fair value at end of year	336,443,000	300,661,000	272,337,000
Funded status at year end - (under) over	33,757,000	28,258,000
Noncurrent assets	33,757,000	28,258,000
Current liabilities	0	0
Noncurrent liabilities	0	0
Net amount recognized	33,757,000	28,258,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized transition obligation	0	0
Unrecognized prior service (cost) credit	15,046,000	17,243,000
Unrecognized actuarial loss	-103,038,000	-96,338,000
Regulatory asset	-87,992,000	-79,095,000
Cumulative employer contributions in excess of cost	121,749,000	107,353,000
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	10,865,000	12,005,000	9,573,000
Interest cost	11,781,000	9,946,000	10,640,000
Expected return on plan assets	-22,530,000	-21,105,000	-20,289,000
Transition obligation	0	0	0
Amortization of prior service cost (credit)	-2,198,000	-2,198,000	-2,198,000
Amortization of net loss	7,685,000	11,202,000	5,966,000
Net periodic benefit cost	5,603,000	9,850,000	3,692,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	-2,198,000
Amortization of unrecognized actuarial loss	8,121,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost	0	0	0
Net loss (gain)	14,385,000	-30,094,000	43,945,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	0
Amortization of net loss	-7,685,000	-11,202,000	-5,966,000
Amortization of prior service (cost) credit	2,198,000	2,198,000	2,198,000
Total recognized in regulatory asset (liability)	8,898,000	-39,098,000	40,177,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	14,501,000	-29,248,000	43,869,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	4.13%	4.55%
Rate Of Compensation Increase	3.68%	3.72%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.55%	3.51%	4.67%
Expected Long Term Rate Of Return On Plan Assets	7.75%	8.00%	8.00%
Rate Of Compensation Increase	3.72%	3.76%	3.78%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	29,946,000
2016	16,794,000
2017	16,332,000
2018	19,197,000
2019	20,685,000
2020 - 2024	110,459,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	300,661,000	272,337,000
Actual return on plan assets:
Fair value at end of year	336,443,000	300,661,000	272,337,000
Qualified Pension [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age For Defined Benefit Plan	21 years
Qualified Pension [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	8.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets	28,367,000	5,722,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	28,367,000	5,722,000
Actual return on plan assets:
Fair value at end of year	28,367,000	5,722,000
Qualified Pension [Member] | Fixed Income Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations	45.00%	38.00%
Qualified Pension [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	8.00%	8.00%
Defined Benefit Plan, Fair Value of Plan Assets	27,224,000	24,078,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,224,000	24,078,000
Actual return on plan assets:
Fair value at end of year	27,224,000	24,078,000
Qualified Pension [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%	11.00%
Defined Benefit Plan, Fair Value of Plan Assets	48,049,000	34,041,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	48,049,000	34,041,000
Actual return on plan assets:
Fair value at end of year	48,049,000	34,041,000
Qualified Pension [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	15.00%	14.00%
Defined Benefit Plan, Fair Value of Plan Assets	49,816,000	42,701,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	49,816,000	42,701,000
Actual return on plan assets:
Fair value at end of year	49,816,000	42,701,000
Qualified Pension [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	8,100,000	14,680,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	8,100,000	14,680,000
Actual return on plan assets:
Fair value at end of year	8,100,000	14,680,000
Qualified Pension [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	16,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	16,187,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Daily
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	None
Actual return on plan assets:
Fair value at end of year	16,187,000
Qualified Pension [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,035,000	1,098,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,035,000	1,098,000
Actual return on plan assets:
Fair value at end of year	1,035,000	1,098,000
Qualified Pension [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	-1,000	-11,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	-1,000	-11,000
Actual return on plan assets:
Fair value at end of year	-1,000	-11,000
Qualified Pension [Member] | Derivatives [Member] | Maximum [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Investment Limitation Percentage	10.00%
Qualified Pension [Member] | Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	35.00%
Defined Benefit Plan, Actual Plan Asset Allocations	31.00%	43.00%
Qualified Pension [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%	4.00%
Defined Benefit Plan, Fair Value of Plan Assets	9,982,000	12,023,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	9,982,000	12,023,000
Actual return on plan assets:
Fair value at end of year	9,982,000	12,023,000
Qualified Pension [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	6.00%	6.00%
Defined Benefit Plan, Fair Value of Plan Assets	19,937,000	16,908,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,937,000	16,908,000
Actual return on plan assets:
Fair value at end of year	19,937,000	16,908,000
Qualified Pension [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	6.00%	6.00%
Defined Benefit Plan, Fair Value of Plan Assets	19,745,000	17,823,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,745,000	17,823,000
Actual return on plan assets:
Fair value at end of year	19,745,000	17,823,000
Qualified Pension [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	10.00%
Defined Benefit Plan, Fair Value of Plan Assets	31,329,000	30,831,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	31,329,000	30,831,000
Actual return on plan assets:
Fair value at end of year	31,329,000	30,831,000
Qualified Pension [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations		8.00%
Defined Benefit Plan, Fair Value of Plan Assets		24,460,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		24,460,000
Actual return on plan assets:
Fair value at end of year		24,460,000
Qualified Pension [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	9.00%
Defined Benefit Plan, Fair Value of Plan Assets	22,877,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,270,000
Fair value at end of year	22,877,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	None
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,270,000
Actual return on plan assets:
Fair value at end of year	22,877,000
Qualified Pension [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	16,675,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	15,042,000
Fair value at end of year	16,675,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	15,042,000
Actual return on plan assets:
Fair value at end of year	16,675,000
Qualified Pension [Member] | Total Other Investments [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	15.00%
Defined Benefit Plan, Actual Plan Asset Allocations	11.00%	12.00%
Qualified Pension [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	6.00%	6.00%
Defined Benefit Plan, Fair Value of Plan Assets	19,829,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	18,571,000
Fair value at end of year	19,829,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Quarterly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	18,571,000
Actual return on plan assets:
Fair value at end of year	19,829,000
Qualified Pension [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.50%
Defined Benefit Plan, Actual Plan Asset Allocations	2.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	4,659,000
Fair value at end of year	7,158,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Initial Unfunded Subscription Balance	12,000,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Limited
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	5,400,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	4,659,000
Actual return on plan assets:
Fair value at end of year	7,158,000
Qualified Pension [Member] | Private Equity Fund of Funds [Member] | Minimum [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	10 years
Qualified Pension [Member] | Private Equity Fund of Funds [Member] | Maximum [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	12 years
Qualified Pension [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%	4.00%
Defined Benefit Plan, Fair Value of Plan Assets	10,134,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	10,765,000
Fair value at end of year	10,134,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	35 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	10,765,000
Actual return on plan assets:
Fair value at end of year	10,134,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	40.00%	37.00%
Defined Benefit Plan, Fair Value of Plan Assets	133,748,000	112,879,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	133,748,000	112,879,000
Actual return on plan assets:
Fair value at end of year	133,748,000	112,879,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	27,932,000	5,566,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,932,000	5,566,000
Actual return on plan assets:
Fair value at end of year	27,932,000	5,566,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	8,100,000	14,680,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	8,100,000	14,680,000
Actual return on plan assets:
Fair value at end of year	8,100,000	14,680,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0
Actual return on plan assets:
Fair value at end of year	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	48,000	6,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	48,000	6,000
Actual return on plan assets:
Fair value at end of year	48,000	6,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	9,982,000	12,023,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	9,982,000	12,023,000
Actual return on plan assets:
Fair value at end of year	9,982,000	12,023,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	19,937,000	16,908,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,937,000	16,908,000
Actual return on plan assets:
Fair value at end of year	19,937,000	16,908,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	19,745,000	17,823,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,745,000	17,823,000
Actual return on plan assets:
Fair value at end of year	19,745,000	17,823,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	31,329,000	30,831,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	31,329,000	30,831,000
Actual return on plan assets:
Fair value at end of year	31,329,000	30,831,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		0
Actual return on plan assets:
Fair value at end of year		0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16,675,000	15,042,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	16,675,000	15,042,000
Actual return on plan assets:
Fair value at end of year	16,675,000	15,042,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	58.00%	61.00%
Defined Benefit Plan, Fair Value of Plan Assets	195,537,000	183,123,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	195,537,000	183,123,000
Actual return on plan assets:
Fair value at end of year	195,537,000	183,123,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	435,000	156,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	435,000	156,000
Actual return on plan assets:
Fair value at end of year	435,000	156,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	27,224,000	24,078,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,224,000	24,078,000
Actual return on plan assets:
Fair value at end of year	27,224,000	24,078,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	48,049,000	34,041,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	48,049,000	34,041,000
Actual return on plan assets:
Fair value at end of year	48,049,000	34,041,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	49,816,000	42,701,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	49,816,000	42,701,000
Actual return on plan assets:
Fair value at end of year	49,816,000	42,701,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	16,187,000
Actual return on plan assets:
Fair value at end of year	16,187,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,035,000	1,098,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,035,000	1,098,000
Actual return on plan assets:
Fair value at end of year	1,035,000	1,098,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	-49,000	-17,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	-49,000	-17,000
Actual return on plan assets:
Fair value at end of year	-49,000	-17,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		24,460,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		24,460,000
Actual return on plan assets:
Fair value at end of year		24,460,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	22,877,000	27,270,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	22,877,000	27,270,000
Actual return on plan assets:
Fair value at end of year	22,877,000	27,270,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	19,829,000	18,571,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,829,000	18,571,000
Actual return on plan assets:
Fair value at end of year	19,829,000	18,571,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10,134,000	10,765,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	10,134,000	10,765,000
Actual return on plan assets:
Fair value at end of year	10,134,000	10,765,000
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	2.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000	4,659,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	7,158,000	4,659,000
Actual return on plan assets:
Fair value at end of year	7,158,000	4,659,000
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0
Actual return on plan assets:
Fair value at end of year	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		0
Actual return on plan assets:
Fair value at end of year		0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000	4,659,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	4,659,000	3,522,000
Fair value at end of year	7,158,000	4,659,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	4,659,000	3,522,000
Actual return on plan assets:
Relating to assets still held at the reporting date	1,031,000	116,000
Relating to assets sold during the period	113,000	61,000
Purchases, sales and settlements (net)	1,355,000	960,000
Transfer in/out of Level 3	0	0
Fair value at end of year	7,158,000	4,659,000
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Supplemental Executive Retirement Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year.
Defined Benefit Plan, Information about Plan Assets [Abstract]
Assets for Participant Benefits	0
Officers and Director-Level Employees Life Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies.
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Per Individual Benefit Provided By Employer	200,000
Term Life Insurance Premiums Paid By Employer	32,000	28,000	25,000
Certain Officers Vice President And Above Life Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed.
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Premiums Paid By Employer	30,000	27,000	43,000
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	55 years
Standard Eligibility Age for Defined Benefit Plan Post Amendment	50 years
Age Of Exclusion For Defined Benefit Plan	65 years
Years After Qualifying Age	10 years
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	27,747,000	25,961,000	23,663,000
Benefits Provided After Employee Is Eligible for Medicare Benefits	0
Term Life Insurance Per Individual Benefit Provided By Employer	15,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	1,500,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	33,678,000	34,830,000
Service cost	1,109,000	1,327,000	1,387,000
Interest cost	1,448,000	1,130,000	1,347,000
Plan amendments	0	0
Actuarial (gain) loss	3,734,000	-1,094,000
Participant contributions	805,000	641,000
Administrative expenses	0	0
Benefit payments	-2,957,000	-3,156,000
Obligation at end of year	37,817,000	33,678,000	34,830,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	25,961,000	23,663,000
Actual return on plan assets	1,874,000	2,848,000
Employer contributions	2,064,000	1,965,000
Participant contributions	805,000	641,000
Administrative expenses	0	0
Benefit payments	-2,957,000	-3,156,000
Fair value at end of year	27,747,000	25,961,000	23,663,000
Funded status at year end - (under) over	-10,070,000	-7,717,000
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	-10,070,000	-7,717,000
Net amount recognized	-10,070,000	-7,717,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized transition obligation	0	0
Unrecognized prior service (cost) credit	0	0
Unrecognized actuarial loss	-3,995,000	-354,000
Regulatory asset	-3,995,000	-354,000
Cumulative employer contributions in excess of cost	-6,075,000	-7,363,000
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	1,109,000	1,327,000	1,387,000
Interest cost	1,448,000	1,130,000	1,347,000
Expected return on plan assets	-1,782,000	-1,663,000	-1,551,000
Transition obligation	0	667,000	667,000
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss	0	0	0
Net periodic benefit cost	775,000	1,461,000	1,850,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	0
Amortization of unrecognized actuarial loss	29,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost	0	0	0
Net loss (gain)	3,641,000	-2,278,000	2,209,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	-667,000	-667,000
Amortization of net loss	0	0	0
Amortization of prior service (cost) credit	0	0	0
Total recognized in regulatory asset (liability)	3,641,000	-2,945,000	1,542,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	4,416,000	-1,484,000	3,392,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	4.03%	4.44%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.44%	3.34%	4.36%
Expected Long Term Rate Of Return On Plan Assets	7.75%	8.00%	8.00%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	2,409,000
2016	2,449,000
2017	2,527,000
2018	2,606,000
2019	2,682,000
2020 - 2024	14,179,000
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	7.40%	7.40%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.00%	5.00%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2027	2027
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Effect of One Percentage Point Increase on Service and Interest Cost Components	31,000
Effect of One Percentage Point Decrease on Service and Interest Cost Components	-32,000
Effect Of One Percentage Point Increase on Postretirement Benefit Obligation	829,000
Effect of One Percentage Point Decrease on Postretirement Benefit Obligation	-841,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	25,961,000	23,663,000
Actual return on plan assets:
Fair value at end of year	27,747,000	25,961,000	23,663,000
Other Postretirement Benefit Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	45 years
Other Postretirement Benefit Plan [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.00%
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	4.00%
Defined Benefit Plan, Fair Value of Plan Assets	2,590,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	982,000
Fair value at end of year	2,590,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	982,000
Actual return on plan assets:
Fair value at end of year	2,590,000
Other Postretirement Benefit Plan [Member] | Fixed Income Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations	44.00%	46.00%
Other Postretirement Benefit Plan [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	10.00%
Defined Benefit Plan, Fair Value of Plan Assets	2,013,000	2,582,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,013,000	2,582,000
Actual return on plan assets:
Fair value at end of year	2,013,000	2,582,000
Other Postretirement Benefit Plan [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	37.00%	36.00%
Defined Benefit Plan, Fair Value of Plan Assets	10,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	9,232,000
Fair value at end of year	10,187,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Investment Maturity Date	within ten years
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	9,232,000
Actual return on plan assets:
Fair value at end of year	10,187,000
Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	47.00%
Defined Benefit Plan, Actual Plan Asset Allocations	42.00%	45.00%
Other Postretirement Benefit Plan [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	9.00%
Defined Benefit Plan, Fair Value of Plan Assets	2,532,000	2,384,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,532,000	2,384,000
Actual return on plan assets:
Fair value at end of year	2,532,000	2,384,000
Other Postretirement Benefit Plan [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%	16.00%
Defined Benefit Plan, Fair Value of Plan Assets	3,846,000	4,206,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	3,846,000	4,206,000
Actual return on plan assets:
Fair value at end of year	3,846,000	4,206,000
Other Postretirement Benefit Plan [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	4.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,269,000	1,327,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,269,000	1,327,000
Actual return on plan assets:
Fair value at end of year	1,269,000	1,327,000
Other Postretirement Benefit Plan [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,310,000	1,352,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,310,000	1,352,000
Actual return on plan assets:
Fair value at end of year	1,310,000	1,352,000
Other Postretirement Benefit Plan [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,336,000	1,331,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,336,000	1,331,000
Actual return on plan assets:
Fair value at end of year	1,336,000	1,331,000
Other Postretirement Benefit Plan [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,319,000	1,313,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,319,000	1,313,000
Actual return on plan assets:
Fair value at end of year	1,319,000	1,313,000
Other Postretirement Benefit Plan [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,345,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	1,252,000
Fair value at end of year	1,345,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	1,252,000
Actual return on plan assets:
Fair value at end of year	1,345,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	27,747,000	25,961,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,747,000	25,961,000
Actual return on plan assets:
Fair value at end of year	27,747,000	25,961,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,590,000	982,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,590,000	982,000
Actual return on plan assets:
Fair value at end of year	2,590,000	982,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,013,000	2,582,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,013,000	2,582,000
Actual return on plan assets:
Fair value at end of year	2,013,000	2,582,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10,187,000	9,232,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	10,187,000	9,232,000
Actual return on plan assets:
Fair value at end of year	10,187,000	9,232,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,532,000	2,384,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,532,000	2,384,000
Actual return on plan assets:
Fair value at end of year	2,532,000	2,384,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	3,846,000	4,206,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	3,846,000	4,206,000
Actual return on plan assets:
Fair value at end of year	3,846,000	4,206,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,269,000	1,327,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,269,000	1,327,000
Actual return on plan assets:
Fair value at end of year	1,269,000	1,327,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,310,000	1,352,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,310,000	1,352,000
Actual return on plan assets:
Fair value at end of year	1,310,000	1,352,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,336,000	1,331,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,336,000	1,331,000
Actual return on plan assets:
Fair value at end of year	1,336,000	1,331,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,319,000	1,313,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,319,000	1,313,000
Actual return on plan assets:
Fair value at end of year	1,319,000	1,313,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,345,000	1,252,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,345,000	1,252,000
Actual return on plan assets:
Fair value at end of year	1,345,000	1,252,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
NCNG SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.64%
Directors SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.74%
Piedmont SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.10%
Non Qualified Pension [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	521,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End	5,925,000	4,736,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	4,736,000	5,569,000
Service cost	0	0	39,000
Interest cost	200,000	157,000	203,000
Plan amendments	485,000	0
Actuarial (gain) loss	956,000	-540,000
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	-452,000	-450,000
Obligation at end of year	5,925,000	4,736,000	5,569,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	452,000	450,000
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	-452,000	-450,000
Fair value at end of year	0	0	0
Funded status at year end - (under) over	-5,925,000	-4,736,000
Noncurrent assets	0	0
Current liabilities	-521,000	-445,000
Noncurrent liabilities	-5,404,000	-4,291,000
Net amount recognized	-5,925,000	-4,736,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized transition obligation	0	0
Unrecognized prior service (cost) credit	-439,000	-196,000
Unrecognized actuarial loss	-1,745,000	-820,000
Regulatory asset	-2,184,000	-1,016,000
Cumulative employer contributions in excess of cost	-3,741,000	-3,720,000
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	39,000
Interest cost	200,000	157,000	203,000
Expected return on plan assets	0	0	0
Transition obligation	0	0	0
Amortization of prior service cost (credit)	243,000	81,000	81,000
Amortization of net loss	31,000	161,000	49,000
Net periodic benefit cost	474,000	399,000	372,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	231,000
Amortization of unrecognized actuarial loss	85,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost	485,000	0	0
Net loss (gain)	956,000	-540,000	629,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	0
Amortization of net loss	-31,000	-161,000	-49,000
Amortization of prior service (cost) credit	-243,000	-81,000	-81,000
Total recognized in regulatory asset (liability)	1,167,000	-782,000	499,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	1,641,000	-383,000	871,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.69%	3.98%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	3.98%	2.95%	4.10%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	521,000
2016	507,000
2017	491,000
2018	472,000
2019	490,000
2020 - 2024	2,149,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0	0
Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Current Liability	214,000	199,000
Noncurrent Liability	4,248,000	3,328,000
Money Purchase Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Description of Defined Contribution Pension and Other Postretirement Plans	Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service.
Defined Contribution Plans Estimated Future Employer Contributions In Next Fiscal Year	1,300,000
Money Purchase Pension Plan [Member] | Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Service Required For Eligibility In Defined Contribution Plan	30 days
Standard Eligibility Age For Defined Contribution Plan	18 years
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	4.00%
Employer Contribution Percentage Above IRS Limit	4.00%
Employer Contribution to Plan	900,000
Plan Vesting Period Defined Contribution Plan	3 years
Voluntary Deferral Plan [Member] | Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution to Plan	0
Deferral Limit As Percentage Of Base Salary	50.00%
Plan Deferral Limit As Percentage Of Annual Incentive Pay	95.00%
Distribution Deferral Time Period Minimum In Years	2 years
Defined Contribution Restoration Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Description of Defined Contribution Pension and Other Postretirement Plans	We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.
Defined Contribution Restoration Plan [Member] | Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution Percentage Above IRS Limit	13.00%
Employer Contribution to Plan	524,000	434,000
Plan Vesting Period Defined Contribution Plan	5 years
Vice Presidents Eligible For One Time Contribution New DCR Plan	4
Plan 401 K [Member]
Defined Contribution Plan Disclosure [Line Items]
Description of Defined Contribution Pension and Other Postretirement Plans	We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service. Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time.
Plan 401 K [Member] | Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Service Required For Eligibility In Defined Contribution Plan	30 days
Standard Eligibility Age For Defined Contribution Plan	18 years
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	5.00%
Employer Contribution to Plan	$6,134,000	$5,688,000	$5,400,000
Plan Vesting Period Defined Contribution Plan	6 months
Employer Match Percentage	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	50.00%
Employee Contribution Rate At Enrollment	2.00%
Contribution Annual Automatic Deferral Increase	1.00%
Employee Contribution Automatic Increase Rate Cap	5.00%
Investment In Company Stock Cap	20.00%

Employee_Share_Based_Plans_Det

Employee Share Based Plans (Details) (USD $)	12 Months Ended			1 Months Ended	0 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Dec. 31, 2011	Dec. 15, 2014	Dec. 12, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Performance Periods Under ICP Plans	3 years
Maximum Statutory Withholdings Allowed	50.00%
Stock Issued During Period, Shares, Share-based Compensation, Gross	100,000	96,000	25,000
Compensation expense	$8,496,000	$4,526,000	$5,730,000
Tax Benefit	2,476,000	1,538,000	2,080,000
Liability	15,130,000	11,098,000
Incentive Compensation Plan Expected Payout In One Year	7,204,000
Incentive Compensation Plan Expected Payout In Two Years	4,980,000
Incentive Compensation Plan Expected Payout In Three Years	2,946,000
Employee Stock Purchase Plan Exercise Price As A Percentage Of Fair Market Value	95.00%
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Incentive Compensation Plan Awards	3
Long Term Incentive Plan Two Performance Measures [Member] | Stock Compensation Plan [Member] | EPS Performance [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	50.00%
Long Term Incentive Plan Two Performance Measures [Member] | Stock Compensation Plan [Member] | Annual Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	50.00%
Long Term Incentive Plan Three Performance Measures [Member] | Stock Compensation Plan [Member] | EPS Performance [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	37.50%
Long Term Incentive Plan Three Performance Measures [Member] | Stock Compensation Plan [Member] | Annual Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	37.50%
Long Term Incentive Plan Three Performance Measures [Member] | Stock Compensation Plan [Member] | Return On Equity [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	25.00%
Retention Stock Unit Award Eligible Officers [Member] | Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	3 years
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period				64,700
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016.
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	20.00%
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche One [Member] | Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Award Vested, Shares, Gross					14,461
Stock Issued During Period, Shares, Share-based Compensation, Gross					7,231
Share Price						$37.89
Payments Related to Tax Withholding for Share-based Compensation					$300,000
Share-based Compensation Arrangement by Share-based Payment Award, Description					The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	30.00%
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	50.00%

Income_Taxes_Income_Tax_Expens

Income Taxes Income Tax Expense Components (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Amortization of investment tax credits	($209)	($267)	($334)
Federal Total	78,836	72,860	64,950
State Total	15,982	13,086	13,267
Regulated Operation [Member]
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)	-1,653	-3,032	-29,062
Current State Tax Expense (Benefit)	950	919	1,857
Deferred Federal Income Tax Expense (Benefit)	70,654	67,885	86,496
Deferred State Income Tax Expense (Benefit)	13,434	11,829	10,144
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Amortization of investment tax credits	-209	-267	-334
Federal Total	68,792	64,586	57,100
State Total	14,384	12,748	12,001
Unregulated Operation [Member]
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)	4,233	6,049	5,636
Current State Tax Expense (Benefit)	870	984	1,027
Deferred Federal Income Tax Expense (Benefit)	5,811	2,225	2,214
Deferred State Income Tax Expense (Benefit)	728	-646	239
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Federal Total	10,044	8,274	7,850
State Total	1,598	338	1,266
Domestic Tax Authority [Member] | NOL Carryforward 1 [Member]
Income Tax Table Continuing Operations [Line Items]
Deferred Federal Income Tax Expense (Benefit)	$28,600	($62,300)

Income_Taxes_Operating_Loss_Ca

Income Taxes Operating Loss Carryforwards (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013
Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Limitations on Use	subject to an annual limitation of $.3 million
Operating Loss Carryforwards, Annual Amount Subject To Limitation	$0.30
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	2.4
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	7.2	6.4
NOL Carryforward 1 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	97	178.1
Operating Loss Carryforwards, Expiration Date	31-Oct-33
NOL Carryforward 2 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$5.90	$5.90
Minimum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Oct-20
Minimum [Member] | NOL Carryforward 2 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Oct-21
Maximum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Oct-28
Maximum [Member] | NOL Carryforward 2 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	31-Oct-25

Income_Taxes_Income_Tax_Examin

Income Taxes Income Tax Examination (Details) (Internal Revenue Service (IRS) [Member])	12 Months Ended
	Oct. 31, 2014
Tax Year 2010 [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2010
Tax Year 2011 [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2011
Tax Year 2012 [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2012

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Oct. 31, 2011	Jul. 31, 2013
NC Tax Law [Line Items]
Non Operating Income Tax Expense Benefit	$11,642,000	$8,612,000	$9,116,000
Regulatory Liabilities	604,829,000	541,897,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal taxes at 35%	83,517,000	77,127,000	69,322,000
State income taxes, net of federal benefit	10,389,000	8,506,000	8,624,000
Amortization of investment tax credits	-209,000	-267,000	-334,000
Other, net	1,121,000	580,000	605,000
Total	94,818,000	85,946,000	78,217,000
Deferred tax assets:
Benefit of loss carryforwards	39,532,000	66,087,000
Revenues and cost of gas	4,960,000	0
Employee benefits and compensation	16,547,000	13,834,000
Revenue requirement	20,320,000	19,062,000
Utility plant	5,631,000	10,386,000
Other	12,869,000	12,796,000
Total deferred tax assets	99,859,000	122,165,000
Valuation allowance	-505,000	-505,000	-505,000	-505,000
Total deferred tax assets, net	99,354,000	121,660,000
Deferred tax liabilities:
Utility Plant	724,172,000	652,822,000
Revenues and cost of gas	4,340,000	21,257,000
Equity Method Investments	42,998,000	38,710,000
Deferred costs	65,828,000	59,221,000
Other	18,065,000	18,324,000
Total Deferred Tax Liabilities	855,403,000	790,334,000
Net Deferred Income Tax Liabilities	756,049,000	668,674,000
Valuation Allowance [Abstract]
Balance at beginning of year	505,000	505,000	505,000	505,000
Credited to income tax expense	0	0	0
Balance at end of year	505,000	505,000	505,000	505,000
Unrecognized Tax Benefits	0	0
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | North Carolina
NC Tax Law [Line Items]
Number Of Additional Rate Reductions	2
Rate Reduction Percentage	1.00%
Non Operating Income Tax Expense Benefit	3,000,000	-1,000,000
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | Tax Year 2013 [Member] | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					6.90%
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | Tax Year 2014 [Member] | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					6.00%
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | Tax Year 2015 [Member] | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					5.00%
Deferred Income Tax Charge [Member] | Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | North Carolina
NC Tax Law [Line Items]
Adjustment To Noncurrent Deferred Income Tax Balances		25,000,000
Regulatory Liabilities	$27,000,000	$24,000,000

Equity_Method_Investments_Deta

Equity Method Investments (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Jul. 01, 2013	Sep. 30, 2013	Jun. 30, 2013
Schedule of Equity Method Investments [Line Items]
Retained Earnings, Undistributed Earnings from Equity Method Investees	$0
Capital contributions to or payments to acquire equity method investments	37,642,000	41,348,000	3,566,000
Cardinal Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	21.49%
Equity Method Investment, Description of Principal Activities	Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.
Pipeline Subscription Capacity Percentage	100.00%
Pipeline Transportation Capacity Subscribed	53.00%
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Transportation or gas storage costs	8,825,000	8,775,000	6,613,000
Trade accounts payable	747,000	755,000
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	8,856,000	15,179,000
Noncurrent assets	111,881,000	116,414,000
Current liabilities	1,468,000	2,637,000
Noncurrent liabilities	45,402,000	45,273,000
Revenues	16,705,000	17,649,000	16,165,000
Gross profit	16,705,000	17,649,000	16,165,000
Income before income taxes	8,042,000	9,361,000	10,433,000
Pine Needle Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	45.00%					40.00%
Equity Method Investment, Description of Principal Activities	Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company, owns an interstate LNG storage facility in North Carolina and is regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%.
Pipeline Subscription Capacity Percentage	100.00%
Pipeline Transportation Capacity Subscribed	64.00%
Capital contributions to or payments to acquire equity method investments				2,900,000
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Transportation or gas storage costs	11,364,000	11,098,000	10,410,000
Trade accounts payable	989,000	940,000
Equity Method Investment, Additional Information	Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%.
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	8,812,000	9,225,000
Noncurrent assets	70,837,000	74,710,000
Current liabilities	38,029,000	3,531,000
Noncurrent liabilities	0	35,391,000
Revenues	18,025,000	16,810,000	16,390,000
Gross profit	18,025,000	16,810,000	16,390,000
Income before income taxes	6,011,000	5,804,000	5,832,000
Additional Equity Method Ownership Percentage Acquired				5.00%
South Star Energy Services [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	15.00%
Equity Method Investment, Description of Principal Activities	SouthStar primarily sells natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.
Capital contributions to or payments to acquire equity method investments					22,500,000
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Operating revenues	3,541,000	3,291,000	2,442,000
Trade accounts receivable	460,000	441,000
Equity Method Investment, Additional Information	In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	196,286,000	199,425,000
Noncurrent assets	143,420,000	147,571,000
Current liabilities	51,435,000	76,346,000
Noncurrent liabilities	83,000	31,000
Revenues	845,695,000	639,426,000	585,291,000
Gross profit	234,581,000	174,993,000	161,122,000
Income before income taxes	136,569,000	102,805,000	94,631,000
Hardy Storage [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Equity Method Investment, Description of Principal Activities	Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Transportation or gas storage costs	9,461,000	9,702,000	9,702,000
Trade accounts payable	774,000	808,000
Storage Capacity Subscription Percentage	100.00%
Storage Capacity Subscribed	40.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	12,644,000	7,641,000
Noncurrent assets	157,861,000	161,282,000
Current liabilities	17,316,000	12,378,000
Noncurrent liabilities	78,830,000	87,184,000
Revenues	23,804,000	24,375,000	24,359,000
Gross profit	23,804,000	24,375,000	24,359,000
Income before income taxes	10,497,000	10,582,000	9,939,000
Constitution Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	24.00%
Equity Method Investment, Description of Principal Activities	The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $680 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
Pipeline Subscription Capacity Percentage	100.00%
Capital contributions to or payments to acquire equity method investments	37,600,000
Total Contributions To Equity Method Investments For Project	53,500,000
Summarized Financial Information Percentage	100.00%	100.00%
Estimated Pipeline Development And Construction Costs	730,000,000
Pipeline Target In Service Date	late 2015 or 2016
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	11,273,000	10,944,000
Noncurrent assets	219,208,000	62,438,000
Current liabilities	7,667,000	7,960,000
Noncurrent liabilities	0	0
Revenues	0	0
Gross profit	0	0
Income before income taxes	10,091,000	3,459,000
Atlantic Coast Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	10.00%
Equity Method Investment, Description of Principal Activities	ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.
Capital contributions to or payments to acquire equity method investments	0
Pipeline Target In Service Date	late 2018
Long-term Purchase Commitment, Period	20 years
Equity Method Investment, Summarized Financial Information [Abstract]
Estimated Percentage Project Financing	70.00%
Atlantic Coast Pipeline [Member] | Minimum [Member]
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs	4,500,000,000
Atlantic Coast Pipeline [Member] | Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs	$5,000,000,000

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (Variable Interest Entity, Not Primary Beneficiary [Member], USD $)	Oct. 31, 2014	Oct. 31, 2013
In Thousands, unless otherwise specified
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$170,171	$128,469
Cardinal Pipeline Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	16,073	18,207
Pine Needle Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	18,689	20,270
South Star Energy Services [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	40,965	38,372
Hardy Storage [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	37,179	34,681
Constitution Pipeline Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	57,255	16,939
Atlantic Coast Pipeline [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$10

Business_Segments_Details

Business Segments (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
									segment
Segment Reporting Information [Line Items]
Number of Reportable Segments									3
Segment Reporting, Disclosure of Major Customers									0
Segment Reporting Information [Abstract]
Revenues from external customers	$185,821	$164,187	$462,247	$657,733	$200,000	$162,943	$399,411	$515,875	$1,469,988	$1,278,229	$1,122,780
Margin	112,326	104,847	211,523	261,512	109,011	97,000	183,856	231,623	690,208	621,490	575,446
Operations and maintenance expenses									271,101	253,301	242,701
Depreciation									119,014	112,225	103,210
Operating income (loss) before income taxes									262,655	221,176	194,560
Income from equity method investments									32,753	26,056	23,904
Interest expense									54,686	24,938	20,097
Income before income taxes									238,619	220,363	198,064
Total assets	4,612,700				4,182,423				4,612,700	4,182,423	3,563,887
Equity method investments in non-utility activities	170,171				128,469				170,171	128,469	87,867
Construction expenditures									460,444	599,999	529,576
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes									262,655	221,176	194,560
Utility income taxes									-83,176	-77,334	-69,101
Operating Income	6,993	3,254	67,299	102,319	5,886	591	51,504	86,213	179,865	144,194	125,723
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									238,619	220,363	198,064
Income taxes									-94,818	-85,946	-78,217
Net Income	-8,967	-7,344	62,540	97,572	-5,003	-2,293	55,790	85,923	143,801	134,417	119,847
Segment Consolidated Assets [Abstract]
Total Assets	4,784,253				4,368,609				4,784,253	4,368,609
Operating Segments [Member]
Segment Consolidated Assets [Abstract]
Total Assets	4,612,700				4,182,423				4,612,700	4,182,423
Intersegment Eliminations [Member]
Segment Consolidated Assets [Abstract]
Total Assets	171,553				186,186				171,553	186,186
Regulated Operation [Member]
Segment Reporting Information [Abstract]
Revenues from external customers									1,469,988	1,278,229	1,122,780
Margin									690,208	621,490	575,446
Operations and maintenance expenses									270,877	253,120	242,599
Depreciation									118,996	112,207	103,192
Operating income (loss) before income taxes									263,041	221,528	194,824
Income from equity method investments									0	0	0
Interest expense									54,686	24,938	20,097
Income before income taxes									206,253	194,659	174,424
Total assets	4,442,185				4,053,591				4,442,185	4,053,591	3,475,640
Equity method investments in non-utility activities	0				0				0	0	0
Construction expenditures									460,444	599,999	529,576
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									206,253	194,659	174,424
Regulated Non-Utility Activities [Member]
Segment Reporting Information [Abstract]
Revenues from external customers									0	0	0
Margin									0	0	0
Operations and maintenance expenses									132	103	31
Depreciation									0	0	0
Operating income (loss) before income taxes									-183	-150	-78
Income from equity method investments									12,318	10,584	9,709
Interest expense									0	0	0
Income before income taxes									12,135	10,434	9,631
Total assets	129,206				90,097				129,206	90,097	69,749
Equity method investments in non-utility activities	129,206				90,097				129,206	90,097	69,749
Construction expenditures									0	0	0
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes									183	150	78
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									12,135	10,434	9,631
Unregulated Non-Utility Activities [Member]
Segment Reporting Information [Abstract]
Revenues from external customers									0	0	0
Margin									0	0	0
Operations and maintenance expenses									92	78	71
Depreciation									18	18	18
Operating income (loss) before income taxes									-203	-202	-186
Income from equity method investments									20,435	15,472	14,195
Interest expense									0	0	0
Income before income taxes									20,231	15,270	14,009
Total assets	41,309				38,735				41,309	38,735	18,498
Equity method investments in non-utility activities	40,965				38,372				40,965	38,372	18,118
Construction expenditures									0	0	0
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes									203	202	186
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									$20,231	$15,270	$14,009

Selected_Quarterly_Financial_D2

Selected Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Quarterly Financial Data [Abstract]
Operating Revenues	$185,821	$164,187	$462,247	$657,733	$200,000	$162,943	$399,411	$515,875	$1,469,988	$1,278,229	$1,122,780
Margin	112,326	104,847	211,523	261,512	109,011	97,000	183,856	231,623	690,208	621,490	575,446
Operating Income	6,993	3,254	67,299	102,319	5,886	591	51,504	86,213	179,865	144,194	125,723
Net income (loss)	($8,967)	($7,344)	$62,540	$97,572	($5,003)	($2,293)	$55,790	$85,923	$143,801	$134,417	$119,847
Earnings Per Share of Common Stock:
Basic (usd per share)	($0.11)	($0.09)	$0.80	$1.27	($0.07)	($0.03)	$0.74	$1.19	$1.85	$1.80	$1.67
Diluted (usd per share)	($0.11)	($0.09)	$0.80	$1.26	($0.07)	($0.03)	$0.74	$1.18	$1.84	$1.78	$1.66