Piedmont Natural Gas (PNY) 10-K 23 Dec 15 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Oct. 31, 2015	Dec. 11, 2015	Apr. 30, 2015
Document And Entity Information [Abstract]
Entity Registrant Name	PIEDMONT NATURAL GAS CO INC
Entity Central Index Key	78,460
Current Fiscal Year End Date	--10-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Oct. 31, 2015
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015
Amendment Flag	false
Entity Common Stock, Shares Outstanding		80,985,282
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,923,039,979
Trading Symbol	PNY

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Oct. 31, 2015	Oct. 31, 2014
Utility Plant:
Utility plant in service		$ 5,426,584	$ 5,011,497
Less accumulated depreciation		1,251,940	1,166,922
Utility plant in service, net		4,174,644	3,844,575
Construction work in progress		170,250	141,693
Plant held for future use		3,155	3,155
Total utility plant, net		4,348,049	3,989,423
Other Physical Property, at cost (net of accumulated depreciation of $926 in 2015 and $904 in 2014)		332	355
Current Assets:
Cash and cash equivalents		13,744	9,643
Trade accounts receivable (1) (less allowance for doubtful accounts of $1,648 in 2015 and $2,152 in 2014)	[1]	59,248	65,260
Income taxes receivable		11,447	36,100
Other receivables		10,667	3,361
Unbilled utility revenues		17,422	21,093
Inventories:
Gas in storage		68,240	84,081
Materials, supplies and merchandise		1,251	1,652
Gas purchase derivative assets, at fair value		1,343	4,898
Regulatory assets		10,936	27,837
Prepayments		28,903	39,030
Deferred income taxes		32,392	53,418
Other current assets		344	326
Total current assets		255,937	346,699
Noncurrent Assets:
Equity method investments in non-utility activities		206,956	170,171
Goodwill		48,852	48,852
Regulatory assets		196,726	174,281
Income taxes receivable		26,023	0
Marketable securities, at fair value		4,666	3,727
Overfunded postretirement asset		17,770	33,757
Other noncurrent assets		5,439	7,042
Total noncurrent assets		506,432	437,830
Total		5,110,750	4,774,307
Stockholders’ equity:
Cumulative preferred stock - no par value - 175 shares authorized		0	0
Common stock – no par value – shares authorized: 200,000; shares outstanding: 80,883 in 2015 and 78,531 in 2014		721,419	636,835
Retained earnings		705,748	672,004
Accumulated other comprehensive loss		(855)	(237)
Total stockholders’ equity		1,426,312	1,308,602
Long-term debt, net		1,523,677	1,414,484
Total capitalization		2,949,989	2,723,086
Current Liabilities:
Current maturities of long-term debt		40,000	0
Short-term debt		340,000	355,000
Trade accounts payable (1)	[1]	99,895	85,299
Other accounts payable		52,149	54,349
Accrued interest		29,488	27,982
Customers’ deposits		20,896	19,994
General taxes accrued		27,940	23,828
Regulatory liabilities		13,367	46,231
Other current liabilities		11,861	9,303
Total current liabilities		635,596	621,986
Noncurrent Liabilities:
Deferred income taxes		861,615	809,467
Unamortized federal investment tax credits		1,027	1,193
Accumulated provision for postretirement benefits		14,975	15,471
Regulatory liabilities		590,301	558,598
Conditional cost of removal obligations		19,712	14,647
Other noncurrent liabilities		37,535	29,859
Total noncurrent liabilities		$ 1,525,165	$ 1,429,235
Commitments and Contingencies
Total		$ 5,110,750	$ 4,774,307
[1]	See Note 13 for amounts attributable to affiliates.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Oct. 31, 2015	Oct. 31, 2014
Statement of Financial Position [Abstract]
Other Physical Property accumulated depreciation	$ 926	$ 904
Allowance for doubtful accounts	$ 1,648	$ 2,152
Cumulative preferred stock par value	$ 0	$ 0
Cumulative preferred stock shares authorized	175,000	175,000
Common stock par value	$ 0	$ 0
Common stock shares authorized	200,000,000	200,000,000
Common stock shares outstanding	80,883,000	78,531,000

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Statement of Comprehensive Income [Abstract]
Operating Revenues (1)	[1]	$ 1,371,718	$ 1,469,988	$ 1,278,229
Cost of Gas (1)	[1]	644,424	779,780	656,739
Margin		727,294	690,208	621,490
Operating Expenses:
Operations and maintenance		294,517	270,877	253,120
Depreciation		128,704	118,996	112,207
General taxes		42,110	37,294	34,635
Utility income taxes		76,934	83,176	77,334
Total operating expenses		542,265	510,343	477,296
Operating Income		185,029	179,865	144,194
Other Income (Expense):
Income from equity method investments		34,461	32,753	26,056
Non-operating income		3,164	1,842	2,839
Non-operating expense		(3,724)	(4,331)	(5,122)
Income taxes		(13,288)	(11,642)	(8,612)
Total other income (expense)		20,613	18,622	15,161
Utility Interest Charges:
Interest on long-term debt		70,619	61,562	54,158
Allowance for borrowed funds used during construction		(11,106)	(16,427)	(30,975)
Other		9,118	9,551	1,755
Total utility interest charges		68,631	54,686	24,938
Net Income		137,011	143,801	134,417
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($1,028), $225 and ($69) for the years ended October 31, 2015, 2014 and 2013, respectively		(1,601)	355	(109)
Reclassification adjustment of realized (gain) loss from hedging activities of equity method investments included in net income, net of tax of $652, ($177) and $85 for the years ended October 31, 2015, 2014 and 2013, respectively		1,018	(284)	130
Net current period benefit activities of equity method investments, net of tax of ($23) and ($16) for the years ended October 31, 2015 and 2014, respectively		(35)	(24)
Total other comprehensive income (loss)		(618)	47	21
Comprehensive Income		$ 136,393	$ 143,848	$ 134,438
Average Shares of Common Stock:
Basic (in shares)		78,942	77,883	74,884
Diluted (in shares)		79,231	78,193	75,333
Earnings Per Share of Common Stock:
Basic (usd per share)		$ 1.74	$ 1.85	$ 1.80
Diluted (usd per share)		$ 1.73	$ 1.84	$ 1.78
[1]	See Note 13 for amounts attributable to affiliates.

Consolidated Statements of Com5

Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Statement of Comprehensive Income [Abstract]
Unrealized gain (loss) from hedging activities of equity method investments arising during period, tax	$ (1,028)	$ 225	$ (69)
Reclassification adjustment of realized (gain) loss from hedging activities of equity investments included in net income, tax	652	(177)	$ 85
Net current period benefit activities of equity method investments, tax	$ (23)	$ (16)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Cash Flows from Operating Activities:
Net income	$ 137,011	$ 143,801	$ 134,417
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	140,217	129,343	120,797
Provision for doubtful accounts	5,095	6,959	5,314
Impairment loss on investment	0	2,000	0
Net gain on sale of property	0	(817)	(349)
Income from equity method investments	(34,461)	(32,753)	(26,056)
Distributions of earnings from equity method investments	24,875	24,843	22,139
Deferred income taxes, net	73,407	87,136	57,637
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	3,555	(3,064)	1,319
Receivables, net	(2,637)	9,785	(28,616)
Inventories	16,242	(10,079)	(2,059)
Settlement of legal asset retirement obligations	(5,563)	(3,575)	(2,389)
Regulatory assets	(14,917)	20,297	43,338
Other assets	16,220	(2,829)	4,629
Accounts payable	(7,626)	18	2,381
Contributions to benefit plans	(12,728)	(22,516)	(22,415)
Accrued/deferred postretirement benefit costs	28,219	20,446	(31,100)
Regulatory liabilities	(16,065)	49,468	23,429
Other liabilities	20,791	12,149	10,831
Net cash provided by operating activities	371,635	430,612	313,247
Cash Flows from Investing Activities:
Utility capital expenditures	(443,654)	(460,444)	(599,999)
Allowance for borrowed funds used during construction	(11,106)	(16,427)	(30,975)
Contributions to equity method investments	(29,723)	(37,642)	(41,348)
Distributions of capital from equity method investments	1,505	3,929	4,700
Proceeds from sale of property	717	1,883	1,951
Investments in marketable securities	(866)	(454)	(414)
Other	4,707	4,708	2,609
Net cash used in investing activities	(478,420)	(504,447)	(663,476)
Cash Flows from Financing Activities:
Borrowings under credit facility	0	0	10,000
Repayments under credit facility	0	0	(10,000)
Net (repayments) borrowings - commercial paper	(15,000)	(45,000)	35,000
Proceeds from issuance of long-term debt, net of discount	149,902	249,565	299,856
Repayment of long-term debt	0	(100,000)	0
Expenses related to issuance of debt	(1,330)	(2,871)	(3,250)
Proceeds from issuance of common stock, net of expenses	53,707	47,290	92,271
Issuance of common stock through dividend reinvestment and employee stock plans	26,992	25,556	24,610
Dividends paid	(103,390)	(99,151)	(92,146)
Other	5	26	(8)
Net cash provided by financing activities	110,886	75,415	356,333
Net Increase in Cash and Cash Equivalents	4,101	1,580	6,104
Cash and Cash Equivalents at Beginning of Year	9,643	8,063	1,959
Cash and Cash Equivalents at End of Year	13,744	9,643	8,063
Cash Paid During the Year for:
Interest	71,519	64,276	50,275
Income Taxes:
Income taxes paid	3,680	10,840	5,760
Income taxes refunded	530	30	169
Income taxes, net	3,150	10,810	5,591
Noncash Investing and Financing Activities:
Accrued construction expenditures	$ 58,868	$ 38,869	$ 39,389

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Stockholders' Equity, beginning balance at Oct. 31, 2012	$ 1,027,004	$ 442,461	$ 584,848	$ (305)
Comprehensive Income:
Net income	134,417		134,417
Other comprehensive income (loss)	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)
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 (loss)	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)
Stockholders' Equity, ending balance at Oct. 31, 2014	1,308,602	636,835	672,004	(237)
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	(213)
Benefit activities of equity method investments	(24)
Net income	137,011		137,011
Other comprehensive income (loss)	(618)			(618)
Comprehensive Income	136,393
Common Stock Issued	84,966	84,966
Expenses from Issuance of Common Stock	(382)	(382)
Tax Benefit from Dividends Paid on ESOP Shares	123		123
Dividends Declared	(103,390)		(103,390)
Stockholders' Equity, ending balance at Oct. 31, 2015	1,426,312	$ 721,419	$ 705,748	$ (855)
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	(796)
Benefit activities of equity method investments	$ (59)

Consolidated Statements of Sto8

Consolidated Statements of Stockholders Equity (Parentheticals) - $ / shares	12 Months Ended
	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Statement of Stockholders' Equity [Abstract]
Dividends Declared per share	$ 1.31	$ 1.27	$ 1.23

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Oct. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies	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 3 to the consolidated financial statements. The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). 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. 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. 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. For further information on equity method investments and related party transactions, see Note 13 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 16 to the consolidated financial statements. On October 24, 2015 , we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy). For further information, see Note 2 to the consolidated financial statements. Use of Estimates 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 (CODM) in deciding how to allocate resources and in assessing performance. Our CODM 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 our cash flows in the ventures. 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. 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. 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. Earnings or losses from equity method investments of the regulated and unregulated non-utility activities segments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. All other revenues and expenses of the regulated and unregulated non-utility activities segments are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. See Note 15 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. 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, 2015 and 2014 is presented below. In thousands 2015 2014 Intangible plant $ 3,374 $ 3,374 Other storage plant 180,960 180,058 Transmission plant 2,024,264 1,787,990 Distribution plant 2,766,871 2,623,560 General plant 452,301 421,763 Asset retirement cost 4,159 11 Contributions in aid of construction (5,345 ) (5,259 ) Total utility plant in service 5,426,584 5,011,497 Less accumulated depreciation (1,251,940 ) (1,166,922 ) Total utility plant in service, net 4,174,644 3,844,575 Construction work in progress 170,250 141,693 Plant held for future use 3,155 3,155 Total utility plant, net $ 4,348,049 $ 3,989,423 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, 2015 , 2014 and 2013 , all of our AFUDC was attributable to borrowed funds. AFUDC for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 AFUDC $ 11,106 $ 16,427 $ 30,975 In accordance with utility accounting practice, we classified real estate and development costs associated with a liquefied natural gas (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 with amortization 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 was recorded as a regulatory asset with amortization over the 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 3 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 2.48% for 2015 , 2.54% for 2014 and 2.77% for 2013 . 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 Note 3 to the consolidated financial statements. 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, 2015 and 2014 . 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 Tennessee Regulatory Authority (TRA), we are authorized to recover actual 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 believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2015 and 2014 , our trade accounts receivable consisted of the following. In thousands 2015 2014 Gas receivables $ 57,759 $ 64,400 Non-regulated merchandise and service work receivables 3,137 3,012 Allowance for doubtful accounts (1,648 ) (2,152 ) Trade accounts receivable $ 59,248 $ 65,260 A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 Balance at beginning of year $ 2,152 $ 1,604 $ 1,579 Additions charged to uncollectibles expense 5,095 6,959 5,314 Accounts written off, net of recoveries (5,599 ) (6,411 ) (5,289 ) Balance at end of year $ 1,648 $ 2,152 $ 1,604 For information on credit risk, see "Credit and Counterparty Risk" in Note 8 of the consolidated financial statements. 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, 2015 and 2014 , such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of $24.8 million and $35 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 3 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 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 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 8 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 10 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. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 15 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 as of October 31, 2015 was performed using a qualitative approach. As part of our qualitative assessment, we considered macroeconomic conditions such as general deterioration in economic condition, limitations on accessing capital and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any changes in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors, such as increases in utility construction expenditures, labor or other costs, that would have a negative effect on earnings. We determined the relevance of any entity-specific events or events affecting our regulated utility segment which would have a negative effect on the carrying value of the reporting unit. Based on our qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test as of October 31, 2015 . The annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment was recognized during the years ended October 31, 2015 , 2014 and 2013. 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, 2015 and 2013 that resulted in any impairment charges. For further information on equity method investments, see Note 13 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 10 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 is 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, 2015 and 2014 is as follows. 2015 2014 In thousands Cost Fair Value Cost Fair Value Current trading securities: Money markets $ 51 $ 51 $ 22 $ 22 Mutual funds 114 185 106 192 Total current trading securities 165 236 128 214 Noncurrent trading securities: Money markets 465 465 447 447 Mutual funds 3,625 4,201 2,598 3,280 Total noncurrent trading securities 4,090 4,666 3,045 3,727 Total trading securities $ 4,255 $ 4,902 $ 3,173 $ 3,941 Issuances and Repurchases of Common Stock As discussed in Note 7 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 Sto

Proposed Acquisition by Duke En

Proposed Acquisition by Duke Energy Corporation	12 Months Ended
	Oct. 31, 2015
Business Combinations [Abstract]
Proposed Acquisition by Duke Energy Corporation	Proposed Acquisition by Duke Energy Corporation On October 24, 2015 , we entered into a Merger Agreement with Duke Energy and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provides for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). At the effective time of the Acquisition, subject to receipt of required shareholder and regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. Upon consummation of the Acquisition, Piedmont common stock will be delisted from the New York Stock Exchange (NYSE). Completion of the Acquisition is subject to various closing conditions, including, among others (i) the approval of the Merger Agreement by an affirmative vote of the holders of a majority of the outstanding shares of our common stock, (ii) approval from the NCUC, and (iii) expiration or termination of any applicable waiting period under the federal Hart-Scott-Rodino Antitrust Improvements Act of 1976. The Merger Agreement may be terminated by us or by Duke Energy if the Acquisition is not consummated by October 31, 2016, subject to a six-month extension by either of us under certain circumstances. The Merger Agreement contains certain termination rights for both companies under certain circumstances, and provides that, upon termination of the Merger Agreement under specified circumstances, we would be required to pay Duke Energy a termination fee of $125 million , or Duke Energy would be required to pay us a termination fee of $250 million . The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to completion of the Acquisition. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and caps our cash dividend to no more than the current annual per share dividend plus an increase of not more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practices. Also, provision is made for a stub period dividend payment to holders of record of our shares of common stock immediately prior to consummation of the Acquisition. In connection with this transaction, we recorded Acquisition-related expenses of $8.6 million for costs paid to outside parties in fiscal 2015 , which are reflected in “Operations and maintenance” in “Operating Expenses” in the Consolidated Statements of Comprehensive Income. This amount does not include the cost of company personnel participating in Acquisition-related activities. We also recorded incremental share-based compensation expense of $7.2 million in "Operations and maintenance" as noted above for the end of period remeasurement to market value of the incentive compensation awards and the retention award of our President and Chief Executive Officer based upon the increase in the trading price of our common stock since the announcement of the Acquisition. We treated these costs as tax deductible since the requisite closing conditions to the Acquisition have not yet been satisfied. Upon completion of the Acquisition, we will evaluate the tax deductibility of these costs and reflect any non-deductible amounts in the effective tax rate at the Acquisition closing date. For further information on our employee share-based plans, see Note 11 to the consolidated financial statements.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Oct. 31, 2015
Public Utilities, Rate Matters [Abstract]
Regulatory Matters	Regulatory Matters Rate-Regulated Basis of Accounting Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2015 and 2014 are as follows. In thousands 2015 2014 Regulatory Assets: Current: Unamortized debt expense on reacquired debt $ 238 $ 239 Amounts due from customers — 16,108 Environmental costs 1,513 1,568 Deferred operations and maintenance expenses 847 916 Deferred pipeline integrity expenses 3,470 3,470 Deferred pension and other retirement benefit costs 2,757 2,769 Robeson LNG development costs 381 917 Other 1,730 1,850 Total current 10,936 27,837 Noncurrent: Unamortized debt expense on reacquired debt 4,666 4,904 Environmental costs 5,107 6,470 Deferred operations and maintenance expenses 3,997 4,721 Deferred pipeline integrity expenses 29,824 24,694 Deferred pension and other retirement benefits costs 17,861 18,799 Amounts not yet recognized as a component of pension and other retirement benefit costs 114,854 94,265 Regulatory cost of removal asset 19,087 18,275 Robeson LNG development costs 127 509 Other 1,203 1,644 Total noncurrent 196,726 174,281 Total $ 207,662 $ 202,118 Regulatory Liabilities: Current: Amounts due to customers $ 13,367 $ 46,231 Noncurrent: Regulatory cost of removal obligations 521,478 506,574 Deferred income taxes 68,738 51,930 Amounts not yet recognized as a component of pension and other retirement benefit costs 85 94 Total noncurrent 590,301 558,598 Total $ 603,668 $ 604,829 The 2014 presentation of unamortized debt expense has been changed to conform with the current year presentation in the table above. As discussed in Note 1 to the consolidated financial statements, we early adopted ASU 2015-03 requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt. Consequently, unamortized debt expense of $.9 million current and $9 million noncurrent presented in 2014 as regulatory assets have been reclassified as a reduction of $9.9 million to the carrying value of long-term debt. The amounts presented above in line items "Unamortized debt expense on reacquired debt" represent unamortized debt expense associated with the early retirement or the refunding of debt in accordance with established regulatory practice. Unamortized debt expenses related to short-term bank debt and unallocated expenses of our open debt and equity shelf registration are now presented in the line item "Other noncurrent assets" as "Noncurrent Assets" in the Consolidated Balance Sheets. See Note 1 with discussion of "Unamortized Debt Expense" and Note 5 to the consolidated financial statements for related discussion of these presentation changes. As of October 31, 2015 , we have $19.1 million of AROs and $117 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 TRA on a deferred cash basis. Regulatory Oversight and Rate and Regulatory Actions 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, 2015 and 2014 , we had unamortized balances, including accrued interest, of $4.8 million and $5.6 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, 2015 and 2014 , we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $33.3 million and $28.2 million , respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs is expected to 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, certain 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, as revised by a subsequent settlement approved by the NCUC in November 2015. 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 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. In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. 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 up 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 November 2013, November 2014 and November 2015 found our hedging activities during the review periods to be reasonable and prudent. In April 2013, we withdrew a petition that had been filed with the NCUC in October 2012 requesting 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, citing our intent to address the matter in a general rate application. The 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. 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 provided 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. In February 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. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR: • Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31. • Extension of the IMR tariff from October 31, 2017 to October 31, 2019. • An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings. • Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case: • Transmission integrity: 85% IMR / 15% rate case. • Distribution integrity: 90% IMR / 10% rate case. • Right-of-way clearing for integrity projects: 15% IMR / 85% rate case. • Work and asset management system: 68% IMR / 32% rate case. • Tax-related adjustments. • An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015. Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $13.4 million in annual IMR margin revenues, effective December 1, 2015, based on $161.9 million of IMR-eligible capital investments in integrity and safety projects over the eleven-month period ended September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase. 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 NCUC 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 required 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 5 to the consolidated financial statements. In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina. In March 2015, the NCUC issued an order approving our request. The bill credit of $45.5 million was reflected on customers' April 2015 bills, reducing amounts due to customers in North Carolina. 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 October 2011. 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 stipulated 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 October 2012. 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 stipulated 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 October 2013. 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 June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2% , effective November 1, 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 up 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 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 September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015. 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 Tennessee, we operate under the Tennessee Incentive Plan (TIP) that benchmarks gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. Under the TIP, the TRA established an allocation of secondary marketing gains and losses to ratepayers and shareholders with a uniform 75/25 sharing ratio with a $1.6 million annual incentive cap for us on these gains and losses. The TIP includes procedures for asset management transactions and provides for a triennial review of TIP operations by an independent consultant. Although the TIP replaced annual prudence reviews of our gas purchasing activities, we undergo an annual compliance audit on the accuracy of our calculations and compliance with all TRA orders and directives regarding the calculation of our deferred gas cost account balances under the Actual Cost Adjustment (ACA) mechanism. 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 Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2013, the TRA approved the TIP account balances and issued its written order approving our TIP account balances. 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 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. In March 2015, the Audit Staff submitted their report with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report. The TRA's written order was issued in May 2015. In August 2015, 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, 2015 under the TIP. We are waiting on a ruling from the TRA at this time. 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 March 2013, the TRA approved the deferred gas cost account balances and issued its written order. In August 2013, we filed a 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. In January 2015, the TRA issued its written order approving the settlement agreement. In October 2015, the TRA approved the deferred gas cost account balances for the twelve-month period ended June 30, 2013 and issued its written order. In November 2015, we filed an annual report for the twelve months ended June 30, 2014 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 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 issued its written order 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 of $100.4 million 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 ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015. In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016. We are waiting on the TRA's written order 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. In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we will begin refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. We are waiting on the TRA's written order at this time. In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) 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. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investmen

Earnings Per Share

Earnings Per Share	12 Months Ended
	Oct. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	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 and forward sale agreements (FSAs) 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 and FSAs settle, for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands, except per share amounts 2015 2014 2013 Net Income $ 137,011 $ 143,801 $ 134,417 Average shares of common stock outstanding for basic earnings per share 78,942 77,883 74,884 Contingently issuable shares under incentive compensation plans 289 310 289 Contingently issuable shares under forward sale agreements — — 160 Average shares of dilutive stock 79,231 78,193 75,333 Earnings Per Share of Common Stock: Basic $ 1.74 $ 1.85 $ 1.80 Diluted $ 1.73 $ 1.84 $ 1.78

Long Term Debt

Long Term Debt	12 Months Ended
	Oct. 31, 2015
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	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. None of our debt is actively traded. As of October 31, 2015 , we early adopted the accounting standard requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt, consistent with the presentation of debt discounts. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2015 and 2014 . Long-Term Debt as of October 31, 2015 In thousands Principal Unamortized Debt Issuance Expenses and Discounts Total Senior Notes: 2.92%, due June 6, 2016 $ 40,000 $ (40 ) $ 39,960 8.51%, due September 30, 2017 35,000 — 35,000 4.24%, due June 6, 2021 160,000 (752 ) 159,248 3.47%, due July 16, 2027 100,000 (638 ) 99,362 3.57%, due July 16, 2027 200,000 (1,307 ) 198,693 4.10%, due September 18, 2034 250,000 (2,644 ) 247,356 4.65%, due August 1, 2043 300,000 (3,040 ) 296,960 3.60%, due September 1, 2025 150,000 (1,382 ) 148,618 Medium-Term Notes: 6.87%, due October 6, 2023 45,000 (115 ) 44,885 8.45%, due September 19, 2024 40,000 (115 ) 39,885 7.40%, due October 3, 2025 55,000 (171 ) 54,829 7.50%, due October 9, 2026 40,000 (126 ) 39,874 7.95%, due September 14, 2029 60,000 (273 ) 59,727 6.00%, due December 19, 2033 100,000 (720 ) 99,280 Total 1,575,000 (11,323 ) 1,563,677 Less current maturities 40,000 — 40,000 Total $ 1,535,000 $ (11,323 ) $ 1,523,677 Long-Term Debt as of October 31, 2014 In thousands Principal Unamortized Debt Issuance Expenses and Discounts Total Senior Notes: 2.92%, due June 6, 2016 $ 40,000 $ (107 ) $ 39,893 8.51%, due September 30, 2017 35,000 — 35,000 4.24%, due June 6, 2021 160,000 (887 ) 159,113 3.47%, due July 16, 2027 100,000 (693 ) 99,307 3.57%, due July 16, 2027 200,000 (1,418 ) 198,582 4.10%, due September 18, 2034 250,000 (2,644 ) 247,356 4.65%, due August 1, 2043 300,000 (3,132 ) 296,868 Medium-Term Notes: 6.87%, due October 6, 2023 45,000 (129 ) 44,871 8.45%, due September 19, 2024 40,000 (127 ) 39,873 7.40%, due October 3, 2025 55,000 (189 ) 54,811 7.50%, due October 9, 2026 40,000 (138 ) 39,862 7.95%, due September 14, 2029 60,000 (292 ) 59,708 6.00%, due December 19, 2033 100,000 (760 ) 99,240 Total 1,425,000 (10,516 ) 1,414,484 Less current maturities — — — Total $ 1,425,000 $ (10,516 ) $ 1,414,484 Current maturities for the next five years ending October 31 and thereafter are as follows. In thousands 2016 $ 40,000 2017 35,000 2018 — 2019 — 2020 — Thereafter 1,500,000 Total $ 1,575,000 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 7 to the consolidated financial statements. 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. As of October 31, 2015 , we have $544.1 million remaining for debt and equity issuances as approved by the NCUC. 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 commercial paper (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 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. On September 14, 2015 , we issued $150 million of ten -year, unsecured senior notes with an interest rate of 3.60% and at a discount of .065% or $97,500 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 June 1, 2025 , 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 25 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 June 1, 2025 , at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption . We used the net proceeds of $148.9 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, 2015 , our net earnings available for restricted payments were $1.2 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, 2015 , 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 3.96 times as of October 31, 2015 ; • Funded debt cannot exceed 70% of total capitalization. Funded debt was 57% of total capitalization as of October 31, 2015 ; • 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, 2015 ; • 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, 2015
Line of Credit Facility [Abstract]
Short-Term Debt Instruments	Short-Term Debt Instruments At October 31, 2015, 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 $1.6 million and $1.8 million were issued and outstanding at October 31, 2015 and 2014 , 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 5 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements. On December 14, 2015, we entered into an agreement with the lenders under our existing $850 million five -year revolving syndicated credit facility to amend and extend the facility at substantially similar terms to our existing facility. The amended facility extended the maturity of our facility to December 14, 2020 . The amended facility expressly permits the Acquisition by Duke Energy. The CP program will continue to be backstopped by the new credit facility. 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, 2015 , we had $340 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 7 to 14 days from their dates of issuance at a weighted average interest rate of .22% . As of October 31, 2014 , our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $355 million at a weighted average interest rate of .17% . We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2015 . A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2015 is as follows. In thousands Minimum amount outstanding $ 230,000 Maximum amount outstanding $ 580,000 Minimum interest rate .15 % Maximum interest rate .30 % Weighted average interest rate .21 % 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 57% at October 31, 2015 .

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Oct. 31, 2015
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Stockholders’ Equity Capital Stock Changes in common stock for the years ended October 31, 2015 , 2014 and 2013 are as follows. In thousands Shares Amount Balance, October 31, 2012 72,250 $ 442,461 Issued to participants in the Employee Stock Purchase Plan (ESPP) 33 1,056 Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) 720 22,791 Issued to participants in the Incentive Compensation Plan (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 Issued to ESPP 31 1,239 Issued to DRIP 669 24,679 Issued to ICP 130 4,964 Issuance of common stock through forward sale agreements, net of expenses 1,522 53,702 Balance, October 31, 2015 80,883 $ 721,419 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 accelerated share repurchase (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. Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements, we may issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170 million (subject to certain exceptions) during the period beginning January 7, 2015 and ending October 31, 2016. In addition to the issuance and sale of shares by us through the Agents, we may also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers will, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. We expect to enter into separate FSAs each fiscal quarter during the term of the Sales Agreements and have done so in our second, third and fourth quarters of 2015. Under the Sales Agreements, we specify the maximum number of our shares to be sold and the minimum price per share. We will pay each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale price) a commission of 1.5% of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements may be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs. Under a FSA that we executed with Merrill on March 10, 2015, 612,000 shares were borrowed from third parties and sold by Merrill, from March 10, 2015 to April 24, 2015, at a weighted average share price of $36.83 , net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $36.28 . Under a FSA that we executed with JP Morgan on June 8, 2015, 795,529 shares were borrowed from third parties and sold by JP Morgan, from June 10, 2015 to July 30, 2015, at a weighted average share price of $36.42 , net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $35.87 . Under a FSA that we executed with Merrill on September 8, 2015, 114,500 shares were borrowed from third parties and sold by Merrill, from September 9, 2015 to September 15, 2015, at a weighted average share price of $36.58 , net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $36.03 . Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net settle for all or a portion of our obligation under the agreements any time prior to December 15, 2015. On October 29, 2015 , we issued 1.5 million shares of our common stock to the forward counterparties by physically settling all of the FSAs entered into during 2015 and received net proceeds of $54.1 million . 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. 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 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 accounting guidance, 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 4 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of the incremental shares in our average shares of dilutive stock as calculated under the treasury stock method. As of October 31, 2015 , shares of common stock reserved for future issuance under various plans are as follows. In thousands ESPP 145 DRIP 171 ICP 820 Total 1,136 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 13 to the consolidated financial statements. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2015 and 2014 . Changes in Accumulated OCIL (1) In thousands 2015 2014 Accumulated OCIL beginning balance, net of tax $ (237 ) $ (284 ) Hedging activities of equity method investments: OCIL before reclassifications, net of tax (1,601 ) 355 Amounts reclassified from accumulated OCIL, net of tax 1,018 (284 ) Total current period activity of hedging activities of equity method investments, net of tax (583 ) 71 Net current period benefit activities of equity method investments, net of tax (35 ) (24 ) Accumulated OCIL ending balance, net of tax $ (855 ) $ (237 ) (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, 2015 and 2014 . Reclassification Out of Accumulated OCIL (1) Years Ended October 31 Affected Line Items on Statement of Comprehensive Income In thousands 2015 2014 Hedging activities of equity method investments $ 1,670 $ (461 ) Income from equity method investments Income tax expense (652 ) 177 Income taxes Net hedging activities 1,018 $ (284 ) Net benefit activities of equity method investments (58 ) (40 ) Income from equity method investments Income tax expense 23 16 Income taxes Net benefit activities (35 ) (24 ) Total reclassification for the period, net of tax $ 983 $ (308 ) (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, 2015
Financial Instruments & Related Fair Value [Abstract]
Financial Instruments and Related Fair Value	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, 2015 and 2014 , we had long gas purchase options providing total coverage of 34.7 million dekatherms and 29.2 million dekatherms, respectively. The long gas purchase options held at October 31, 2015 are for the period from December 2015 through October 2016. 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 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, 2015 and 2014 . 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, 2015 and 2014 . 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, 2015 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 $ 1,343 $ — $ — $ — $ 1,343 Debt and equity securities held as trading securities: Money markets 516 — — — 516 Mutual funds 4,386 — — — 4,386 Total fair value assets $ 6,245 $ — $ — $ — $ 6,245 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 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 3 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. The principal and fair value of our long-term debt, which is classified within Level 2, are shown below. In thousands Principal Fair Value As of October 31, 2015 $ 1,575,000 $ 1,720,586 As of October 31, 2014 1,425,000 1,617,453 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, 2015 and 2014 . Fair Value of Derivative Instruments In thousands 2015 2014 Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: Asset Financial Instruments: Current Assets - Gas purchase derivative assets (December 2015 - October 2016) $ 1,343 Current Assets - Gas purchase derivative assets (December 2014 - November 2015) $ 4,898 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 are 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” as presented in Note 3 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, 2015 and 2014 , 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 2015 2014 2015 2014 Gas purchase options $ (4,423 ) $ 6,162 $ (4,423 ) $ 6,162 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 as 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 as 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 have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. 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 $2.9 million , or approximately 5% of our gross trade accounts receivable at October 31, 2015 . 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, 2015 , 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 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.

Commitments & Contingent Liabil

Commitments & Contingent Liabilities	12 Months Ended
	Oct. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	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, 2015 , 2014 and 2013 are as follows. In thousands 2015 2014 2013 Operating lease payments (1) $ 5,024 $ 4,701 $ 4,729 (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 2016 $ 5,052 2017 4,706 2018 4,609 2019 4,433 2020 4,477 Thereafter 24,413 Total $ 47,690 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 years . The time periods for fixed payments under gas supply contracts are up to two years . The time period for the gas supply purchase commitments is up to fifteen 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, 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, 2015 , future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows. Pipeline Gas Supply Gas Supply Telecommunications and Storage Reservation Purchase and Information In thousands Capacity Fees Commitments Technology Other Total 2016 $ 178,594 $ 4,577 $ 65,286 $ 6,164 $ 45,577 $ 300,198 2017 163,806 165 89,784 1,639 — 255,394 2018 143,728 — 69,569 669 — 213,966 2019 132,259 — 69,569 610 — 202,438 2020 114,400 — 69,759 — — 184,159 Thereafter 516,333 — 707,698 — — 1,224,031 Total $ 1,249,120 $ 4,742 $ 1,071,665 $ 9,082 $ 45,577 $ 2,380,186 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 $1.6 million in letters of credit that were issued and outstanding at October 31, 2015 . Additional information concerning letters of credit is included in Note 6 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, 2015 , we had open surety bonds with a total contingent obligation of $6.6 million . Environmental Matters Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and have recorded estimated environmental liabilities, including those for our 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 our 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, 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. As of October 31, 2015 , our estimated undiscounted environmental liability totaled $1.2 million , and consisted of $1.1 million for MGP sites for which we retain responsibility and $.1 million for the Huntersville LNG facility. The costs we reasonable expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others. We have incurred $2.2 million of remediation costs related to our MGP sites and $4.8 million related to our Huntersville LNG facility. 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, 2015 , our regulatory assets for unamortized environmental costs in our three-state territory totaled $6.6 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, 2015
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Employee Benefit Plans	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 the following types of investments: • Fixed income securities: includes U.S. treasuries, corporate bonds, high yield debt (bank loans), 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. • Equity securities: includes large cap growth, large cap value and small cap domestic equity securities, as well as international equity. • Real estate: includes a diversified global real estate investment trust fund. • Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies. The target and actual allocations of the qualified pension plan's assets are as follows: Target Assets at October 31 Asset Allocations Allocation 2015 2014 Fixed income securities 45 % 46 % 45 % Equity securities 35 % 34 % 31 % Real estate 5 % 5 % 5 % Cash and cash equivalents — % 1 % 8 % Other investments 15 % 14 % 11 % Total 100 % 100 % 100 % 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, 2015 , 2014 and 2013 we contributed $1.4 million , $.9 million and $.7 million , respectively, 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. Employees hired after January 1, 2008 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 of $15,000 . In September 2015, we announced the replacement of the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA), effective January 1, 2016. Under the new HRA, participating eligible retirees and their dependents will receive a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical expenses. The impact of the amendment was not material to us. 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, except the OPEB fixed income portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The target and actual allocations of the OPEB plan's assets are as follows: Target Assets at October 31 Asset Allocations Allocation 2015 2014 Fixed income securities 45 % (1) 47 % 44 % Equity securities 47 % 44 % 42 % Real estate 5 % 5 % 5 % Cash and cash equivalents 3 % 4 % 9 % Total 100 % 100 % 100 % (1) Includes 5% target allocation to high yield fixed income. 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 certain 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 of annual contributions. 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 (VDP), 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 VDP on a specified date that is at least two years from the date of deferral, a change in control, on separation of service or upon death. Our funding to the DCR plan account for the years ended October 31, 2015 and 2014 , and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2015 and 2014 , are presented below. In thousands 2015 2014 Funding $ 548 $ 524 Liability: Current 236 214 Noncurrent 5,089 4,248 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 2015 2014 2013 Term life policies of certain officers at the vice president level and above $ 35 $ 30 $ 27 Officers and director-level employees 30 32 28 Actuarial Plan Information A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2015 and 2014 , a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2015 and 2014 , and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2015 and 2014 are presented below. Qualified Pension Nonqualified Pension Other Benefits In thousands 2015 2014 2015 2014 2015 2014 Accumulated benefit obligation at year end $ 263,120 $ 252,706 $ 5,527 $ 5,925 N/A N/A Change in projected benefit obligation: Obligation at beginning of year $ 302,686 $ 272,403 $ 5,925 $ 4,736 $ 37,817 $ 33,678 Service cost 11,403 10,865 — — 1,182 1,109 Interest cost 12,018 11,781 209 200 1,475 1,448 Plan amendments — — — 485 (1,877 ) — Actuarial (gain) loss 3,524 23,646 (100 ) 956 1,697 3,734 Participant contributions — — — — 611 805 Administrative expenses (590 ) (465 ) — — — — Benefit payments (17,504 ) (15,544 ) (507 ) (452 ) (3,348 ) (2,957 ) Obligation at end of year 311,537 302,686 5,527 5,925 37,557 37,817 Change in fair value of plan assets: Fair value at beginning of year 336,443 300,661 — — 27,747 25,961 Actual return on plan assets 958 31,791 — — 315 1,874 Employer contributions 10,000 20,000 507 452 2,221 2,064 Participant contributions — — — — 611 805 Administrative expenses (590 ) (465 ) — — — — Benefit payments (17,504 ) (15,544 ) (507 ) (452 ) (3,348 ) (2,957 ) Fair value at end of year 329,307 336,443 — — 27,546 27,747 Funded status at year end - over (under) $ 17,770 $ 33,757 $ (5,527 ) $ (5,925 ) $ (10,011 ) $ (10,070 ) Noncurrent assets $ 17,770 $ 33,757 $ — $ — $ — $ — Current liabilities — — (520 ) (521 ) — — Noncurrent liabilities — — (5,007 ) (5,404 ) (10,011 ) (10,070 ) Net amount recognized $ 17,770 $ 33,757 $ (5,527 ) $ (5,925 ) $ (10,011 ) $ (10,070 ) Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account: Unrecognized prior service credit (cost) $ 12,848 $ 15,046 $ (208 ) $ (439 ) $ 1,877 $ — Unrecognized actuarial loss (120,541 ) (103,038 ) (1,560 ) (1,745 ) (7,185 ) (3,995 ) Regulatory asset (107,693 ) (87,992 ) (1,768 ) (2,184 ) (5,308 ) (3,995 ) Cumulative employer contributions in excess of cost 125,463 121,749 (3,759 ) (3,741 ) (4,703 ) (6,075 ) Net amount recognized $ 17,770 $ 33,757 $ (5,527 ) $ (5,925 ) $ (10,011 ) $ (10,070 ) Weighted average assumptions used in the measurement of the benefit obligations: Discount rate 4.34 % 4.13 % 3.85 % 3.69 % 4.38 % 4.03 % Rate of compensation increase 4.07 % 3.68 % N/A N/A N/A N/A 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 as presented above instead of OCIL. The regulators have allowed future recovery of our pension and OPEB costs to this date. Net periodic benefit cost components for the years ended October 31, 2015 , 2014 and 2013 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2015 , 2014 and 2013 are presented below. Qualified Pension Nonqualified Pension Other Benefits In thousands 2015 2014 2013 2015 2014 2013 2015 2014 2013 Service cost $ 11,403 $ 10,865 $ 12,005 $ — $ — $ — $ 1,182 $ 1,109 $ 1,327 Interest cost 12,018 11,781 9,946 209 200 157 1,475 1,448 1,130 Expected return on plan assets (23,614 ) (22,530 ) (21,105 ) — — — (1,837 ) (1,782 ) (1,663 ) Amortization of transition obligation — — — — — — — — 667 Amortization of prior service cost (credit) (2,198 ) (2,198 ) (2,198 ) 231 243 81 — — — Amortization of net loss 8,676 7,685 11,202 85 31 161 29 — — Net periodic benefit cost 6,285 5,603 9,850 525 474 399 849 775 1,461 Other changes in plan assets and benefit obligation recognized through regulatory asset or liability: Prior service cost (credit) — — — — 485 — (1,877 ) — — Net loss (gain) 26,179 14,385 (30,094 ) (100 ) 956 (540 ) 3,219 3,641 (2,278 ) Amounts recognized as a component of net periodic benefit cost: Transition obligation — — — — — — — — (667 ) Amortization of net loss (8,676 ) (7,685 ) (11,202 ) (85 ) (31 ) (161 ) (29 ) — — Prior service (cost) credit 2,198 2,198 2,198 (231 ) (243 ) (81 ) — — — Total recognized in regulatory asset (liability) 19,701 8,898 (39,098 ) (416 ) 1,167 (782 ) 1,313 3,641 (2,945 ) Total recognized in net periodic benefit and regulatory asset (liability) $ 25,986 $ 14,501 $ (29,248 ) $ 109 $ 1,641 $ (383 ) $ 2,162 $ 4,416 $ (1,484 ) Weighted average assumptions used to determine the net periodic benefit cost: Discount rate 4.13 % 4.55 % 3.51 % 3.69 % 3.98 % 2.95 % 4.03 % 4.44 % 3.34 % Expected long-term rate of return on plan assets 7.50 % 7.75 % 8.00 % N/A N/A N/A 7.50 % 7.75 % 8.00 % Rate of compensation increase 3.68 % 3.72 % 3.76 % N/A N/A N/A N/A N/A N/A The 2016 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 ) $ 208 $ (332 ) Amortization of unrecognized actuarial loss 8,164 81 459 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, 2015 , the benchmark by plan was as follows. Qualified pension plan 4.34 % NCNG SERP 3.78 % Directors’ SERP 3.91 % Piedmont SERP 3.17 % OPEB 4.38 % 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. 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. Our assumed mortality rates incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014. We also applied the updated projection scale issued by the Society of Actuaries in October 2015. We anticipate that we will contribute the following amounts to our plans in 2016 . In thousands Qualified pension plan * $ 10,000 Nonqualified pension plans 520 MPP plan 1,650 OPEB plan 1,300 * Funded in November 2015. The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. We are in compliance with the 100% funding target established in the PPA. 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 2016 $ 28,147 $ 520 $ 1,987 2017 19,911 504 2,145 2018 20,413 482 2,301 2019 21,348 510 2,421 2020 21,829 491 2,494 2021 - 2025 114,267 2,100 13,379 Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2015. 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 is presented below. 2014 Health care cost trend rate assumed for next year 7.40 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.00 % Year that the rate reaches the ultimate trend rate 2027 The health care cost trend rate assumptions could have a significant effect on amounts reported as benefit cost. A change of 1% would have the following effect. 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, 2015 $ 34 $ (35 ) Beginning in 2016, we will change the method we use to estimate the service and interest cost components of net periodic benefit costs for our plans from using a developed zero-coupon spot rate yield curve as discussed above. We have elected to use a full yield curve approach in the estimation of these components of benefit costs by applying the specific spot rates along the yield curve used in the determination of the benefit obligations to the relevant projected cash flows. We will make this change to improve the correlation between projected benefit cash flows and the corresponding yield curve spot rates and to provide a more precise measurement of service and interest costs. This change will not affect the measurement of our total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We will account for this change as a change in estimate and, accordingly, will account for it prospectively beginning in 2016. Fair Value Measurements 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 are valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund. Fixed income securities – These assets include: • 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. • 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. • Derivatives – The Level 1 assets are valued using a compilation of observable market information on an active market. The Level 2 assets are valued using broker quotes on a non-active market. Equity securities – These are level 1 assets valued at the market price of the active market on which the individual security is traded. Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2. Common trust fund – These are Level 2 assets held in a common trust fund 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 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; $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 Standard & Poor's 500 Stock 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. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance. Hedge fund of funds – 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. Commodities fund of funds – 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. High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund. 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 - International growth Monthly None 30 days 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, 2015. 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 as of October 31, 2015 and 2014 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, 2015 In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents $ 2,782 $ 89 $ — $ 2,871 Fixed income securities — 84,135 — 84,135 Equity securities 44,738 — — 44,738 Mutual funds 78,853 42,890 — 121,743 Common trust fund — 23,571 — 23,571 Private equity fund of funds — — 8,344 8,344 Other Investments: Hedge fund of funds 19,809 (1) Commodities fund of funds 7,688 (1) High yield debt (bank loans) 16,408 (1) Total assets at fair value $ 126,373 $ 150,685 $ 8,344 $ 329,307 Qualified Pension Plan as of October 31, 2014 In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents $ 27,932 $ 435 $ — $ 28,367 Fixed income securities 48 78,026 — 78,074 Equity securities 51,266 — — 51,266 Mutual funds 54,502 48,049 — 102,551 Common trust fund — 22,877 — 22,877 Private equity fund of funds — — 7,158 7,158 Other Investments: Hedge fund of funds 19,829 (1) Commodities fund of funds 10,134 (1) High yield debt (bank loans) 16,187 (1) Total assets at fair value $ 133,748 $ 149,387 $ 7,158 $ 336,443 (1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. 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, 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 Actual return on plan assets: Relating to assets still held at the reporting date 413 Relating to assets sold during the period 618 Purchases, sales and settlements (net) 155 Transfer in/out of Level 3 — Balance, October 31, 2015 $ 8,344 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 use

Employee Share Based Plans

Employee Share Based Plans	12 Months Ended
	Oct. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Share-Based Plans	Employee Share-Based Plans Liability 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, 2015 , 2014 and 2013 , we recorded compensation expense, and as of October 31, 2015 and 2014 , 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 each quarter and at the settlement date. We have granted three series of awards under the approved ICP, one with a three -year performance period that ended October 31, 2015 (2015 plan) and two other awards ending on October 31, 2016 (2016 plan) and October 31, 2017 (2017 plan). For each of these performance periods, awards are weighted and based on achievement relative to: • a target annual compounded increase in basic EPS ( 37.5% weight), • total shareholder returns compared 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 ( 37.5% weight), and • an actual average return on equity compared to the weighted average return on equity allowed by our regulatory commissions ( 25% weight). 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 our common stock and withholdings for payment of applicable taxes on the compensation. Also under our approved ICP, 64,700 unvested retention stock units (RSUs) were granted to our President and Chief Executive Officer (CEO) 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 RSUs 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, 2015 , 2014 and 2013 , we recorded compensation expense, and as of October 31, 2015 and 2014 , we accrued a liability for this award based on the fair market value of our common stock at the end of each quarter. The liability is re-measured to market value each quarter and at the settlement date. The December 15, 2014 vesting covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of our common stock. After withholdings of $.3 million for federal and state income taxes, our President and CEO received 7,231 shares of our common stock at the NYSE composite closing price on December 12, 2014 of $37.89 per share. The December 15, 2015 vesting covers 30% of the grant, including accrued dividends, for a total of 22,434 shares of our common stock. After withholdings of $.6 million for federal and state income taxes, our President and CEO received 11,732 shares of our common stock at the NYSE composite closing price on December 14, 2015 of $56.85 per share. At the time of distribution of any award under the ICP, the number of shares of common stock 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 the net shares issued in the Consolidated Statements of Stockholders’ Equity and in Note 7 to the consolidated financial statements. The compensation expense related to the awards under the ICP for the years ended October 31, 2015 , 2014 and 2013 , 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, 2015 and 2014 are presented below. In thousands 2015 2014 2013 Compensation expense $ 14,173 $ 8,496 $ 4,526 Tax benefit 3,966 2,476 1,538 Liability 22,037 15,130 Based on current accrual assumptions as of October 31, 2015 , the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years with the 2015 plan paying out in fiscal year 2016, the 2016 plan paying out in fiscal year 2017 and the 2017 plan paying out in fiscal year 2018. Payouts as currently accrued are presented net of estimated federal and state withholding payments. In thousands 2016 2017 2018 Amount of payout $ 10,866 $ 8,179 $ 2,992 The Merger Agreement provides for the conversion of the shares subject to the RSUs and ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the RSUs for our President and CEO (accelerated RSUs) and the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at his and their elections to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration of the vesting and payment of these awards will mitigate the effects of Section 280G of the Tax Code, including increasing the deductibility of such payments for the Company. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, and the RSUs, per the election of our President and CEO, occurred on December 15, 2015. In connection with the election to accelerate the ICP awards and the RSUs, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of common stock resulting from the reinvestment of dividends paid with respect to these shares of common stock that are required to be reinvested in additional shares of common stock, to the extent the shares of common stock would not otherwise have been earned or payable absent the acceleration. Under the share repayment agreements, the shares of common stock delivered to the participants, including dividends paid by the Company and reinvested as discussed above, may not be transferred or encumbered until such shares of common stock are no longer subject to repayment under the applicable repayment agreement. The restricted shares of common stock and dividends earned on those shares of common stock are subject to full or partial cancellation if the Acquisition is not consummated or the participant leaves the Company prior to consummation of the Acquisition. The participants otherwise have all rights of shareholders with respect to the restricted shares of common stock. The accelerated ICP awards and the accelerated RSUs were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes. The gross value of the shares issued for the accelerated ICP awards was $17.4 million , or $9.2 million net of federal and state tax withholdings. Under the accelerated RSUs, 19,554 restricted shares of our common stock were issued to our President and CEO, net of shares withheld for applicable federal and state income taxes. The gross value of the shares for the accelerated RSUs was $2.1 million , or $1.1 million net of federal and state tax withholdings. Equity Plan 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 the fair 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, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of income tax expense for the years ended October 31, 2015 , 2014 and 2013 are presented below. 2015 2014 2013 In thousands Federal State Federal State Federal State Charged (Credited) to operating income: Current $ (10,449 ) $ (289 ) $ (1,653 ) $ 950 $ (3,032 ) $ 919 Deferred (1) (2) 75,644 12,195 70,654 13,434 67,885 11,829 Tax Credits: Amortization (167 ) — (209 ) — (267 ) — Total 65,028 11,906 68,792 14,384 64,586 12,748 Charged (Credited) to other income (expense): Current 9,709 1,449 4,233 870 6,049 984 Deferred (1) (2) 2,249 (119 ) 5,811 728 2,225 (646 ) Total 11,958 1,330 10,044 1,598 8,274 338 Total $ 76,986 $ 13,236 $ 78,836 $ 15,982 $ 72,860 $ 13,086 (1) Includes benefits from net operating loss (NOL) and tax carryforwards of $64.3 million and $62.3 million for the years ended October 31, 2015 and 2013, respectively. (2) Includes the utilization of NOL carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively. The Tax Increase Prevention Act of 2014 (the Act), enacted December 19, 2014, retroactively extended the 50% bonus depreciation that expired December 2013 for a year to December 2014. Under the Act, we were able to claim additional depreciation deductions on our tax return for the year ended October 31, 2014. As a result of this additional depreciation, we generated a NOL for our tax year ended October 31, 2014. Prior to the Act's retroactive extension to 2014, we had anticipated utilizing NOL carryforwards to offset taxable income generated in our fiscal year 2014. The benefit from NOL and tax carryforwards for the year ended October 31, 2015 includes $61.1 million to record the retroactive impact of the Act. A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 Federal taxes at 35% $ 79,532 $ 83,517 $ 77,127 State income taxes, net of federal benefit 8,604 10,389 8,506 Amortization of investment tax credits (167 ) (209 ) (267 ) Other, net 2,253 1,121 580 Total $ 90,222 $ 94,818 $ 85,946 As of October 31, 2015 and 2014 , deferred income taxes consisted of the following temporary differences. In thousands 2015 2014 Deferred tax assets: Benefit of loss carryforwards $ 84,025 $ 39,532 Revenues and cost of gas 3,495 4,960 Employee benefits and compensation 22,134 16,547 Revenue requirement 26,088 20,320 Utility plant 7,481 5,631 Other 10,461 12,869 Total deferred tax assets 153,684 99,859 Valuation allowance (848 ) (505 ) Total deferred tax assets, net 152,836 99,354 Deferred tax liabilities: Utility plant 849,835 724,172 Revenues and cost of gas — 4,340 Equity method investments 44,778 42,998 Deferred costs 73,903 65,828 Other 13,543 18,065 Total deferred tax liabilities 982,059 855,403 Net deferred income tax liabilities $ 829,223 $ 756,049 As of October 31, 2015 and 2014 , 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, 2015 and 2014 , we have federal NOL carryforwards of $219.7 million and $97 million , respectively, which expire in 2033 through 2034 . We also have $5.9 million of federal NOL carryforwards as of October 31, 2015 and 2014 that expire in 2023 through 2025 and are subject to an annual limitation of $.3 million . As of October 31, 2015 , we have a capital loss carryforward of $1 million which expires in 2019 . We believe that it is more likely than not that the benefit from the capital loss carryforward will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the capital loss carryforward, we recorded a valuation allowance of $.3 million during fiscal year ended October 31, 2015 . As of October 31, 2015 , we have a $1.1 million alternative minimum tax credit carryforward. As of October 31, 2015 and 2014 , we have state NOL carryforwards of $115.1 million and $7.2 million , respectively, which expire from 2018 through 2030 . 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, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 Balance at beginning of year $ 505 $ 505 $ 505 Charged to income tax expense 343 — — Balance at end of year $ 848 $ 505 $ 505 There were no unrecognized tax benefits for the years ended October 31, 2015 and 2014 . 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. In July 2015, the provision for a 1% state income tax rate reduction based on state tax collections exceeding certain thresholds under the North Carolina tax statutes was announced. Accordingly, the statutory income tax rate for North Carolina will decrease to 4% for our fiscal year 2017. We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the state income tax rate reductions announced in July 2015, we adjusted our noncurrent deferred income tax balances during fiscal year 2015 by approximately $17.5 million for temporary differences expected to reverse at the lower future rate. We recognized a tax benefit in net income of approximately $.5 million , largely related to our regulated non-utility activities segment, and recorded the remainder of approximately $17 million as regulatory deferred income taxes as presented in noncurrent "Regulatory Liabilities" in Note 3 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. As of October 31, 2015 , we have approximately $44 million related to the North Carolina tax rate change included in our deferred income taxes recorded in “Regulatory Liabilities,” which would have been an increase to net income predominately in fiscal years 2013 and 2015 without our utility regulation. The NCUC will determine the recovery period of this regulatory liability in future proceedings. In fiscal 2013, we recognized a tax benefit in net income of approximately $1 million related to the corporate income tax reduction.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Oct. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	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, 2015 , there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings. Ownership Interests We have the following membership interests in these companies as of October 31, 2015 and 2014 . Entity Name Interest Activity Cardinal Pipeline Company, LLC (Cardinal) 21.49% Intrastate pipeline located in North Carolina; regulated by the NCUC Pine Needle LNG Company, LLC (Pine Needle) 45% Interstate LNG storage facility located in North Carolina; regulated by the FERC SouthStar Energy Services, LLC (SouthStar) 15% Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois Hardy Storage Company (Hardy Storage) 50% Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC Constitution Pipeline Company LLC (Constitution) 24% To develop, construct, own and operate 124 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC Atlantic Coast Pipeline, LLC (ACP) 10% To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC Accumulated Other Comprehensive Income (Loss) As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. SouthStar uses financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts is based on selected market indices. Retirement benefits are allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. For these transactions with these equity method investees, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in “ Accumulated other comprehensive loss ” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments and the retirement benefits are presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Related Party Transactions We have related party transactions as a customer of our investments. For the years ended October 31, 2015 , 2014 and 2013 , these gas costs and the amounts we owed to our equity method investees, as of October 31, 2015 and 2014 , are as follows. Related Party Type of Expense Cost of Gas (1) Trade accounts payable (2) In thousands 2015 2014 2013 2015 2014 Cardinal Transportation costs $ 8,763 $ 8,825 8,775 $ 744 $ 747 Pine Needle Gas storage costs 11,441 11,364 11,098 955 989 Hardy Storage Gas storage costs 9,290 9,461 9,702 774 774 Totals $ 29,494 $ 29,650 $ 29,575 $ 2,473 $ 2,510 (1) In the Consolidated Statements of Comprehensive Income. (2) In the Consolidated Balance Sheets. We have related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended October 31, 2015 , 2014 and 2013 , our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2015 and 2014 , are as follows. Operating Revenues (1) Trade accounts receivable (2) In thousands 2015 2014 2013 2015 2014 Operating revenues $ 1,568 $ 3,541 $ 3,291 $ 183 $ 460 (1) In the Consolidated Statements of Comprehensive Income. (2) In the Consolidated Balance Sheets. Information on Our Equity Method Investments Cardinal Cardinal is a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc. and SCANA Corporation. 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. Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2015 and 2014 , and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 9,451 $ 8,856 Noncurrent assets 106,444 111,881 Current liabilities 1,228 1,468 Noncurrent liabilities 45,446 45,402 Revenues 16,629 16,705 $ 17,649 Gross profit 16,629 16,705 17,649 Income before income taxes 7,742 8,042 9,361 Pine Needle Pine Needle is a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million , increasing our membership interest from 40% to 45% . Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64% . We are dependent on the Williams – Transco pipeline system for redelivery of Pine Needle volumes to our system for service to our customers. Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2015 and 2014 , and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 9,863 $ 8,812 Noncurrent assets 71,586 70,837 Current liabilities 5,377 38,029 Noncurrent liabilities 35,112 — Revenues 16,913 18,025 $ 16,810 Gross profit 16,913 18,025 16,810 Income before income taxes 6,002 6,011 5,804 SouthStar SouthStar is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL) who is subject to being acquired by The Southern Company. On September 4, 2015, under the terms of the SouthStar limited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to remain a member of SouthStar. In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar. GNGC’s election to purchase our entire 15% interest in SouthStar is subject to and effective with the consummation of the Acquisition. 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. Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2015 and 2014, and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014* 2013 Current assets $ 204,237 $ 192,151 Noncurrent assets 132,315 143,958 Current liabilities 45,953 47,923 Noncurrent liabilities — — Revenues 769,295 845,695 $ 639,426 Gross profit 224,612 234,581 174,993 Income before income taxes 129,340 136,569 102,805 * Balance sheet amounts have been changed to reflect SouthStar's reclassification of cash collateral under accounting guidance. Hardy Storage Hardy Storage is a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. 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 are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for redelivery of Hardy Storage volumes to our system for service to our customers. Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2015 and 2014 , and for the twelve months ended October 31, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 11,658 $ 12,644 Noncurrent assets 156,803 157,861 Current liabilities 19,078 17,316 Noncurrent liabilities 69,971 78,830 Revenues 23,350 23,804 $ 24,375 Gross profit 23,350 23,804 24,375 Income before income taxes 10,403 10,497 10,582 Constitution Constitution is 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 will be the operator of the pipeline. 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 $834 million , excluding AFUDC, in total. Our total anticipated contributions are approximately $200.2 million . As of October 31, 2015 , our fiscal year contributions were $19.1 million , with our total equity contributions for the project totaling $72.7 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 the fourth quarter of 2016 , which has been extended due to a longer than expected regulatory and permitting process. 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, 2015 and 2014 , and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 6,163 $ 11,273 Noncurrent assets 330,152 219,208 Current liabilities 4,398 7,667 Noncurrent liabilities — — Revenues — — $ — Gross profit — — — Income before income taxes 24,604 10,091 3,459 ACP On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary will be the operator of the pipeline. The pipeline will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018 , subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty -year contracts. The total cost for the project is expected to be between $4.5 billion to $5 billion , excluding financing costs. Members anticipate obtaining project financing for 60% of the total costs during the construction period, and a project capitalization ratio of 50% debt and 50% equity when operational. As of October 31, 2015 , our fiscal year contributions were $10.6 million , with contributions to the project beginning November 2014. In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015 and expects to receive the FERC certificate of public convenience and necessity in the summer of 2016 and begin construction thereafter. On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI has informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. This commitment is capped at $15.2 million . This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP. On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company. On October 24, 2015, Piedmont entered into a Merger Agreement with Duke Energy. The ACP limited liability company agreement includes provisions to allow Dominion an option to purchase additional ownership interests in ACP to maintain a majority ownership percentage relative to all other members. After consummation of the Acquisition, Duke, together with our ownership, would have a 50% membership interest unless Dominion exercises its option. Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2015 , and for the twelve months ended September 30, 2015 , is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014. In thousands 2015 Current assets $ 23,422 Noncurrent assets 86,109 Current liabilities 9,105 Noncurrent liabilities — Revenues — Gross profit — (Loss) before income taxes (5,205 )

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Oct. 31, 2015
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Variable Interest Entities	Variable Interest Entities On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. As of October 31, 2015 , 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 13 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, and we will continue to apply equity method accounting to these investments. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. As of October 31, 2015 and 2014 , our investment balances are as follows. October 31, October 31, In thousands 2015 2014 Cardinal $ 15,083 $ 16,073 Pine Needle 18,396 18,689 SouthStar 41,325 40,965 Hardy Storage 39,706 37,179 Constitution 82,403 57,255 ACP 10,043 10 Total equity method investments in non-utility activities $ 206,956 $ 170,171 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, 2015
Segment Reporting [Abstract]
Business Segments	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. 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. 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, 2015 , 2014 and 2013 , and as of October 31, 2015 , 2014 and 2013 , are presented below. Regulated Unregulated Regulated Non-Utility Non-Utility In thousands Utility Activities Activities Total 2015 Revenues from external customers $ 1,371,718 $ — $ — $ 1,371,718 Margin 727,294 — — 727,294 Operations and maintenance expenses 294,517 81 105 294,703 Depreciation 128,704 — 18 128,722 Operating income (loss) before income taxes 261,963 (152 ) (217 ) 261,594 Income from equity method investments — 15,060 19,401 34,461 Interest charges 68,631 — — 68,631 Income before income taxes 193,140 14,909 19,184 227,233 Total assets 4,742,284 165,630 41,682 4,949,596 Equity method investments in non-utility activities — 165,630 41,326 206,956 Construction expenditures 443,654 — — 443,654 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 charges 54,686 — — 54,686 Income before income taxes 206,253 12,135 20,231 238,619 Total assets (1) 4,432,239 129,206 41,309 4,602,754 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 charges 24,938 — — 24,938 Income before income taxes 194,659 10,434 15,270 220,363 Total assets (1) 4,045,259 90,097 38,735 4,174,091 Equity method investments in non-utility activities — 90,097 38,372 128,469 Construction expenditures 599,999 — — 599,999 (1) Regulated utility total assets have been adjusted in 2014 and 2013 to reflect the netting of debt issuance costs with its debt carrying value in accordance with the 2015 adoption of new accounting guidance related to this balance sheet presentation. Reconciliations to the consolidated financial statements for the years ended October 31, 2015 , 2014 and 2013 , and as of October 31, 2015 and 2014 are as follows. In thousands 2015 2014 2013 Operating Income: Segment operating income before income taxes $ 261,594 $ 262,655 $ 221,176 Utility income taxes (76,934 ) (83,176 ) (77,334 ) Regulated non-utility activities operating loss before income taxes 152 183 150 Unregulated non-utility activities operating loss before income taxes 217 203 202 Total $ 185,029 $ 179,865 $ 144,194 Net Income: Income before income taxes for reportable segments $ 227,233 $ 238,619 $ 220,363 Income taxes (90,222 ) (94,818 ) (85,946 ) Total $ 137,011 $ 143,801 $ 134,417 In thousands 2015 2014 Consolidated Assets: Total assets for reportable segments $ 4,949,596 $ 4,602,754 Eliminations/Adjustments 161,154 171,553 Total $ 5,110,750 $ 4,774,307

Subsequent Events

Subsequent Events	12 Months Ended
	Oct. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	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, short-term debt instruments, employee share-based plans and equity method investments, see Note 3 , Note 6 , Note 11 and Note 13 , respectively, to the consolidated financial statements.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Oct. 31, 2015
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data	Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited) Earnings (Loss) Operating Net Per Share of Operating Income Income Common Stock Revenues Margin (Loss) (Loss) Basic Diluted Fiscal Year 2015 January 31 $ 607,271 $ 270,070 $ 105,758 $ 92,978 $ 1.18 $ 1.18 April 30 424,924 225,621 75,123 66,402 0.84 0.84 July 31 158,266 111,572 5,233 (8,260 ) (0.10 ) (0.10 ) October 31 181,257 120,031 (1,085 ) (14,109 ) (0.18 ) (0.18 ) Fiscal Year 2014 January 31 $ 657,733 $ 261,512 $ 102,319 $ 97,572 $ 1.27 $ 1.26 April 30 462,247 211,523 67,299 62,540 0.80 0.80 July 31 164,187 104,847 3,254 (7,344 ) (0.09 ) (0.09 ) October 31 185,821 112,326 6,993 (8,967 ) (0.11 ) (0.11 ) 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.

Summary Of Significant Accoun26

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Oct. 31, 2015
Accounting Policies [Abstract]
Consolidation, Policy	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). 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. 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. 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.
Subsequent Events, Policy	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.
Use of Estimates, Policy	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	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 (CODM) in deciding how to allocate resources and in assessing performance. Our CODM 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 our cash flows in the ventures.
Rate-Regulated Basis of Accounting, Policy	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	We compute depreciation expense using the straight-line method 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. 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 Depreciation rates for utility plant are approved by our regulatory commissions.
Allowance for Funds Used During Construction, Policy	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.
Cash and Cash Equivalents, Policy	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	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. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the PSCSC and the Tennessee Regulatory Authority (TRA), we are authorized to recover actual uncollected gas costs through the purchased gas adjustment (PGA).
Inventories, Policy	Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost. 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.
Fair Value Measurements, Policy	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. 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. 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. 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.
Goodwill, Policy	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. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 15 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, 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.
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	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.
Issuances and Repurchases of Common Stock, 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	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
Unamortized Debt Expense, Policy	We amortize bank debt expense over the life of the syndicated revolving credit facility 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 as a regulatory asset or liability 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
Revenue Recognition, Policy	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. 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. 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. 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. Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. 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.
Cost of Gas and Deferred Purchased Gas Adjustments, Policy	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	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. 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 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. 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.
Earnings Per Share, Policy	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 and forward sale agreements (FSAs) 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.
Variable Interest Entities, Policy	On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. 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, and we will continue to apply equity method accounting to these investments. 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.

Summary Of Significant Accoun27

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Oct. 31, 2015
Accounting Policies [Abstract]
Schedule of Public Utility Property, Plant, and Equipment	The classification of total utility plant, net, for the years ended October 31, 2015 and 2014 is presented below. In thousands 2015 2014 Intangible plant $ 3,374 $ 3,374 Other storage plant 180,960 180,058 Transmission plant 2,024,264 1,787,990 Distribution plant 2,766,871 2,623,560 General plant 452,301 421,763 Asset retirement cost 4,159 11 Contributions in aid of construction (5,345 ) (5,259 ) Total utility plant in service 5,426,584 5,011,497 Less accumulated depreciation (1,251,940 ) (1,166,922 ) Total utility plant in service, net 4,174,644 3,844,575 Construction work in progress 170,250 141,693 Plant held for future use 3,155 3,155 Total utility plant, net $ 4,348,049 $ 3,989,423 AFUDC for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 AFUDC $ 11,106 $ 16,427 $ 30,975
Schedule of Trade Account Receivables	As of October 31, 2015 and 2014 , our trade accounts receivable consisted of the following. In thousands 2015 2014 Gas receivables $ 57,759 $ 64,400 Non-regulated merchandise and service work receivables 3,137 3,012 Allowance for doubtful accounts (1,648 ) (2,152 ) Trade accounts receivable $ 59,248 $ 65,260
Schedule of Changes in Allowance for Doubtful Accounts	A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 Balance at beginning of year $ 2,152 $ 1,604 $ 1,579 Additions charged to uncollectibles expense 5,095 6,959 5,314 Accounts written off, net of recoveries (5,599 ) (6,411 ) (5,289 ) Balance at end of year $ 1,648 $ 2,152 $ 1,604
Schedule of Marketable Securities	The composition of these securities as of October 31, 2015 and 2014 is as follows. 2015 2014 In thousands Cost Fair Value Cost Fair Value Current trading securities: Money markets $ 51 $ 51 $ 22 $ 22 Mutual funds 114 185 106 192 Total current trading securities 165 236 128 214 Noncurrent trading securities: Money markets 465 465 447 447 Mutual funds 3,625 4,201 2,598 3,280 Total noncurrent trading securities 4,090 4,666 3,045 3,727 Total trading securities $ 4,255 $ 4,902 $ 3,173 $ 3,941
Schedule of Asset Retirement Obligations	The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2015 and 2014 are presented below. In thousands 2015 2014 Regulatory non-legal AROs $ 521,478 $ 506,574 Conditional AROs 19,712 14,647 Total cost of removal obligations $ 541,190 $ 521,221
Schedule of Change in Asset Retirement Obligation	A reconciliation of the changes in conditional AROs for the year ended October 31, 2015 and 2014 is presented below. In thousands 2015 2014 Beginning of period $ 14,647 $ 27,016 Liabilities incurred during the period 4,663 2,108 Liabilities settled during the period (5,563 ) (3,576 ) Accretion 924 1,548 Adjustment to estimated cash flows 5,041 (12,449 ) End of period $ 19,712 $ 14,647
Schedule of New Accounting Pronouncements	Accounting Standards Update (ASU) - Guidance Adopted in Fiscal Year 2015 Guidance Description Effective date Effect on the financial statements or other significant matters ASU 2015-03, April 2015, Interest: Imputation of Interest - Simplifying the Presentation of Debt Issuance Costs (Subtopic 835-30) The guidance is part of the Financial Accounting Standards Board's (FASB) simplification initiative to reduce complexity in accounting standards. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this amendment. Annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted for financial statements that have not been previously issued. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015. The adoption of this guidance had no impact on our results of operations or cash flows. We retrospectively changed the presentation of the balance sheet line items current and noncurrent "Regulatory assets," "Other noncurrent assets" and "Long-term debt, net." ASU 2015-15, August 2015, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting The guidance provides clarification to ASU 2015-03 for debt issuance costs for line-of-credit arrangements, specifically that the SEC would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Effective upon adoption of ASU 2015-03, as adopted August 1, 2015. The adoption of this guidance had no impact on our results of operations or cash flows. ASU 2015-07, May 2015, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (Topic 820) The guidance amends the required disclosure of investments for which fair value is measured at NAV per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the NAV per share practical expedient. Annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with retrospective application to all periods presented and early adoption permitted. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015. The adoption of this guidance had no impact on our financial position, results of operations or cash flows. We have disclosed certain benefit plan assets under the new guidance. Guidance Description Effective date Effect on the financial statements or other significant matters ASU 2015-12, July 2015, Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965) The FASB issued a three-part standard providing guidance on certain aspects of the accounting by employee benefit plans. The ASU: (1) requires a pension plan to use contract value as the only measure for fully benefit-responsive investment contracts; (2) simplifies and increases the effectiveness of the investment disclosure requirements for employee benefit plans by grouping investments by general type; and (3) provides benefit plans with a measurement-date practical expedient on a month-end date nearest to the employer's fiscal year end. Annual periods beginning after December 15, 2015 with early adoption permitted. The amendments in parts (1) and (2) are retrospectively applied to all periods presented, while the amendment in part (3) is applied prospectively. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015. The adoption of this guidance had no impact on our financial position, results of operations or cash flows. We have disclosed certain benefit plan assets under the new guidance of part (2). Parts (1) and (2) are applicable to our future Form 11-K filing; part (3) is not applicable to us. Recently Issued Accounting Guidance Guidance Description Effective date Effect on the financial statements or other significant matters ASU 2014-09, May 2014 , Revenue from Contracts with Customers (Topic 606) 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. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of the first period of adoption. Annual periods beginning after December 15, 2017 (beginning November 1, 2018 for us) and interim periods within that period, with early adoption permitted for annual periods beginning after December 15, 2016. We are currently evaluating the effect on our financial position, results of operations and cash flows, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are following the efforts of an accounting utility subgroup and its issuance of a revenue implementation guide. ASU 2014-15, August 2014 , Presentation of Financial Statements - Going Concern (Subtopic 205-40) The amendment provides 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." Annual periods ending after December 15, 2016 (October 31, 2017 for us), and interim and annual periods thereafter; early adoption is permitted. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. It will require establishing a going concern assessment process to meet the standard. Guidance Description Effective date Effect on the financial statements or other significant matters ASU 2015-05, April 2015, Intangibles -Goodwill and Other - Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40) The guidance amends ASC 350-40 to provide customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software. Annual periods (and interim periods within those periods) beginning after December 15, 2015 (November 1, 2016 for us), with early adoption permitted. Entities may adopt the guidance retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date. We are currently evaluating the effect on our financial position, results of operations and cash flows. ASU 2015-17, November 2015, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes The guidance eliminates the current requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax liabilities and assets be classified as noncurrent. The current requirement that deferred tax liabilities and assets be presented as a single amount remains unchanged. Annual periods (and interim periods within those periods) beginning after December 15, 2016, early adoption is permitted. The adoption of this guidance will have no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent will affect presentation of our financial position.

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Tables)	12 Months Ended
	Oct. 31, 2015
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2015 and 2014 are as follows. In thousands 2015 2014 Regulatory Assets: Current: Unamortized debt expense on reacquired debt $ 238 $ 239 Amounts due from customers — 16,108 Environmental costs 1,513 1,568 Deferred operations and maintenance expenses 847 916 Deferred pipeline integrity expenses 3,470 3,470 Deferred pension and other retirement benefit costs 2,757 2,769 Robeson LNG development costs 381 917 Other 1,730 1,850 Total current 10,936 27,837 Noncurrent: Unamortized debt expense on reacquired debt 4,666 4,904 Environmental costs 5,107 6,470 Deferred operations and maintenance expenses 3,997 4,721 Deferred pipeline integrity expenses 29,824 24,694 Deferred pension and other retirement benefits costs 17,861 18,799 Amounts not yet recognized as a component of pension and other retirement benefit costs 114,854 94,265 Regulatory cost of removal asset 19,087 18,275 Robeson LNG development costs 127 509 Other 1,203 1,644 Total noncurrent 196,726 174,281 Total $ 207,662 $ 202,118
Schedule of Regulatory Liabilities	Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2015 and 2014 are as follows. Regulatory Liabilities: Current: Amounts due to customers $ 13,367 $ 46,231 Noncurrent: Regulatory cost of removal obligations 521,478 506,574 Deferred income taxes 68,738 51,930 Amounts not yet recognized as a component of pension and other retirement benefit costs 85 94 Total noncurrent 590,301 558,598 Total $ 603,668 $ 604,829
Schedule of Secondary Market Activity	This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2015, 2014 and 2013 is presented below. In millions 2015 2014 2013 Allocated to customers as gas cost reductions $ 60.1 $ 72.2 $ 26.9 Margin allocated to us 21.1 25.4 9.0 Margin from secondary market activity $ 81.2 $ 97.6 $ 35.9

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Oct. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest and FSAs settle, for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands, except per share amounts 2015 2014 2013 Net Income $ 137,011 $ 143,801 $ 134,417 Average shares of common stock outstanding for basic earnings per share 78,942 77,883 74,884 Contingently issuable shares under incentive compensation plans 289 310 289 Contingently issuable shares under forward sale agreements — — 160 Average shares of dilutive stock 79,231 78,193 75,333 Earnings Per Share of Common Stock: Basic $ 1.74 $ 1.85 $ 1.80 Diluted $ 1.73 $ 1.84 $ 1.78

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Oct. 31, 2015
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments	As of October 31, 2015 , we early adopted the accounting standard requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt, consistent with the presentation of debt discounts. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2015 and 2014 . Long-Term Debt as of October 31, 2015 In thousands Principal Unamortized Debt Issuance Expenses and Discounts Total Senior Notes: 2.92%, due June 6, 2016 $ 40,000 $ (40 ) $ 39,960 8.51%, due September 30, 2017 35,000 — 35,000 4.24%, due June 6, 2021 160,000 (752 ) 159,248 3.47%, due July 16, 2027 100,000 (638 ) 99,362 3.57%, due July 16, 2027 200,000 (1,307 ) 198,693 4.10%, due September 18, 2034 250,000 (2,644 ) 247,356 4.65%, due August 1, 2043 300,000 (3,040 ) 296,960 3.60%, due September 1, 2025 150,000 (1,382 ) 148,618 Medium-Term Notes: 6.87%, due October 6, 2023 45,000 (115 ) 44,885 8.45%, due September 19, 2024 40,000 (115 ) 39,885 7.40%, due October 3, 2025 55,000 (171 ) 54,829 7.50%, due October 9, 2026 40,000 (126 ) 39,874 7.95%, due September 14, 2029 60,000 (273 ) 59,727 6.00%, due December 19, 2033 100,000 (720 ) 99,280 Total 1,575,000 (11,323 ) 1,563,677 Less current maturities 40,000 — 40,000 Total $ 1,535,000 $ (11,323 ) $ 1,523,677 Long-Term Debt as of October 31, 2014 In thousands Principal Unamortized Debt Issuance Expenses and Discounts Total Senior Notes: 2.92%, due June 6, 2016 $ 40,000 $ (107 ) $ 39,893 8.51%, due September 30, 2017 35,000 — 35,000 4.24%, due June 6, 2021 160,000 (887 ) 159,113 3.47%, due July 16, 2027 100,000 (693 ) 99,307 3.57%, due July 16, 2027 200,000 (1,418 ) 198,582 4.10%, due September 18, 2034 250,000 (2,644 ) 247,356 4.65%, due August 1, 2043 300,000 (3,132 ) 296,868 Medium-Term Notes: 6.87%, due October 6, 2023 45,000 (129 ) 44,871 8.45%, due September 19, 2024 40,000 (127 ) 39,873 7.40%, due October 3, 2025 55,000 (189 ) 54,811 7.50%, due October 9, 2026 40,000 (138 ) 39,862 7.95%, due September 14, 2029 60,000 (292 ) 59,708 6.00%, due December 19, 2033 100,000 (760 ) 99,240 Total 1,425,000 (10,516 ) 1,414,484 Less current maturities — — — Total $ 1,425,000 $ (10,516 ) $ 1,414,484
Schedule of Maturities of Long-term Debt	Current maturities for the next five years ending October 31 and thereafter are as follows. In thousands 2016 $ 40,000 2017 35,000 2018 — 2019 — 2020 — Thereafter 1,500,000 Total $ 1,575,000

Short Term Debt (Tables)

Short Term Debt (Tables)	12 Months Ended
	Oct. 31, 2015
Line of Credit Facility [Abstract]
Schedule of Short-term Debt Activities	A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2015 is as follows. In thousands Minimum amount outstanding $ 230,000 Maximum amount outstanding $ 580,000 Minimum interest rate .15 % Maximum interest rate .30 % Weighted average interest rate .21 %

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Oct. 31, 2015
Stockholders' Equity Note [Abstract]
Schedule of Common Stock Outstanding Roll Forward	Changes in common stock for the years ended October 31, 2015 , 2014 and 2013 are as follows. In thousands Shares Amount Balance, October 31, 2012 72,250 $ 442,461 Issued to participants in the Employee Stock Purchase Plan (ESPP) 33 1,056 Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) 720 22,791 Issued to participants in the Incentive Compensation Plan (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 Issued to ESPP 31 1,239 Issued to DRIP 669 24,679 Issued to ICP 130 4,964 Issuance of common stock through forward sale agreements, net of expenses 1,522 53,702 Balance, October 31, 2015 80,883 $ 721,419
Schedule of Stock by Class	As of October 31, 2015 , shares of common stock reserved for future issuance under various plans are as follows. In thousands ESPP 145 DRIP 171 ICP 820 Total 1,136
Schedule of Accumulated Other Comprehensive Income (Loss)	Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2015 and 2014 . Changes in Accumulated OCIL (1) In thousands 2015 2014 Accumulated OCIL beginning balance, net of tax $ (237 ) $ (284 ) Hedging activities of equity method investments: OCIL before reclassifications, net of tax (1,601 ) 355 Amounts reclassified from accumulated OCIL, net of tax 1,018 (284 ) Total current period activity of hedging activities of equity method investments, net of tax (583 ) 71 Net current period benefit activities of equity method investments, net of tax (35 ) (24 ) Accumulated OCIL ending balance, net of tax $ (855 ) $ (237 ) (1) Amounts in parentheses indicate debits to accumulated OCIL.
Reclassification out of Accumulated Other Comprehensive Income	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, 2015 and 2014 . Reclassification Out of Accumulated OCIL (1) Years Ended October 31 Affected Line Items on Statement of Comprehensive Income In thousands 2015 2014 Hedging activities of equity method investments $ 1,670 $ (461 ) Income from equity method investments Income tax expense (652 ) 177 Income taxes Net hedging activities 1,018 $ (284 ) Net benefit activities of equity method investments (58 ) (40 ) Income from equity method investments Income tax expense 23 16 Income taxes Net benefit activities (35 ) (24 ) Total reclassification for the period, net of tax $ 983 $ (308 ) (1) Amounts in parentheses indicate debits to accumulated OCIL.

Financial Instruments & Relat33

Financial Instruments & Related Fair Value (Tables)	12 Months Ended
	Oct. 31, 2015
Financial Instruments And Related Fair Value Detail [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	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, 2015 and 2014 . We have had no transfers between any level during the years ended October 31, 2015 and 2014 . Recurring Fair Value Measurements as of October 31, 2015 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 $ 1,343 $ — $ — $ — $ 1,343 Debt and equity securities held as trading securities: Money markets 516 — — — 516 Mutual funds 4,386 — — — 4,386 Total fair value assets $ 6,245 $ — $ — $ — $ 6,245 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
Fair Value, by Balance Sheet Grouping	The principal and fair value of our long-term debt, which is classified within Level 2, are shown below. In thousands Principal Fair Value As of October 31, 2015 $ 1,575,000 $ 1,720,586 As of October 31, 2014 1,425,000 1,617,453 The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2015 and 2014 . Fair Value of Derivative Instruments In thousands 2015 2014 Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: Asset Financial Instruments: Current Assets - Gas purchase derivative assets (December 2015 - October 2016) $ 1,343 Current Assets - Gas purchase derivative assets (December 2014 - November 2015) $ 4,898
Amount Of Gain Loss Recognized On Derivatives And Deferred Under PGA Procedures	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, 2015 and 2014 , 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 2015 2014 2015 2014 Gas purchase options $ (4,423 ) $ 6,162 $ (4,423 ) $ 6,162 Cost of Gas

Commitments & Contingent Liab34

Commitments & Contingent Liabilities (Tables)	12 Months Ended
	Oct. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Operating Lease Payments	Operating lease payments for the years ended October 31, 2015 , 2014 and 2013 are as follows. In thousands 2015 2014 2013 Operating lease payments (1) $ 5,024 $ 4,701 $ 4,729 (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	Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows. In thousands 2016 $ 5,052 2017 4,706 2018 4,609 2019 4,433 2020 4,477 Thereafter 24,413 Total $ 47,690
Schedule of Future Unconditional Purchase Obligations	As of October 31, 2015 , future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows. Pipeline Gas Supply Gas Supply Telecommunications and Storage Reservation Purchase and Information In thousands Capacity Fees Commitments Technology Other Total 2016 $ 178,594 $ 4,577 $ 65,286 $ 6,164 $ 45,577 $ 300,198 2017 163,806 165 89,784 1,639 — 255,394 2018 143,728 — 69,569 669 — 213,966 2019 132,259 — 69,569 610 — 202,438 2020 114,400 — 69,759 — — 184,159 Thereafter 516,333 — 707,698 — — 1,224,031 Total $ 1,249,120 $ 4,742 $ 1,071,665 $ 9,082 $ 45,577 $ 2,380,186

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Oct. 31, 2015
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures	We anticipate that we will contribute the following amounts to our plans in 2016 . In thousands Qualified pension plan * $ 10,000 Nonqualified pension plans 520 MPP plan 1,650 OPEB plan 1,300 * Funded in November 2015. The target and actual allocations of the OPEB plan's assets are as follows: Target Assets at October 31 Asset Allocations Allocation 2015 2014 Fixed income securities 45 % (1) 47 % 44 % Equity securities 47 % 44 % 42 % Real estate 5 % 5 % 5 % Cash and cash equivalents 3 % 4 % 9 % Total 100 % 100 % 100 % (1) Includes 5% target allocation to high yield fixed income. The 2016 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 ) $ 208 $ (332 ) Amortization of unrecognized actuarial loss 8,164 81 459 The target and actual allocations of the qualified pension plan's assets are as follows: Target Assets at October 31 Asset Allocations Allocation 2015 2014 Fixed income securities 45 % 46 % 45 % Equity securities 35 % 34 % 31 % Real estate 5 % 5 % 5 % Cash and cash equivalents — % 1 % 8 % Other investments 15 % 14 % 11 % Total 100 % 100 % 100 % A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2015 and 2014 , a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2015 and 2014 , and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2015 and 2014 are presented below. Qualified Pension Nonqualified Pension Other Benefits In thousands 2015 2014 2015 2014 2015 2014 Accumulated benefit obligation at year end $ 263,120 $ 252,706 $ 5,527 $ 5,925 N/A N/A Change in projected benefit obligation: Obligation at beginning of year $ 302,686 $ 272,403 $ 5,925 $ 4,736 $ 37,817 $ 33,678 Service cost 11,403 10,865 — — 1,182 1,109 Interest cost 12,018 11,781 209 200 1,475 1,448 Plan amendments — — — 485 (1,877 ) — Actuarial (gain) loss 3,524 23,646 (100 ) 956 1,697 3,734 Participant contributions — — — — 611 805 Administrative expenses (590 ) (465 ) — — — — Benefit payments (17,504 ) (15,544 ) (507 ) (452 ) (3,348 ) (2,957 ) Obligation at end of year 311,537 302,686 5,527 5,925 37,557 37,817 Change in fair value of plan assets: Fair value at beginning of year 336,443 300,661 — — 27,747 25,961 Actual return on plan assets 958 31,791 — — 315 1,874 Employer contributions 10,000 20,000 507 452 2,221 2,064 Participant contributions — — — — 611 805 Administrative expenses (590 ) (465 ) — — — — Benefit payments (17,504 ) (15,544 ) (507 ) (452 ) (3,348 ) (2,957 ) Fair value at end of year 329,307 336,443 — — 27,546 27,747 Funded status at year end - over (under) $ 17,770 $ 33,757 $ (5,527 ) $ (5,925 ) $ (10,011 ) $ (10,070 ) Noncurrent assets $ 17,770 $ 33,757 $ — $ — $ — $ — Current liabilities — — (520 ) (521 ) — — Noncurrent liabilities — — (5,007 ) (5,404 ) (10,011 ) (10,070 ) Net amount recognized $ 17,770 $ 33,757 $ (5,527 ) $ (5,925 ) $ (10,011 ) $ (10,070 ) Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account: Unrecognized prior service credit (cost) $ 12,848 $ 15,046 $ (208 ) $ (439 ) $ 1,877 $ — Unrecognized actuarial loss (120,541 ) (103,038 ) (1,560 ) (1,745 ) (7,185 ) (3,995 ) Regulatory asset (107,693 ) (87,992 ) (1,768 ) (2,184 ) (5,308 ) (3,995 ) Cumulative employer contributions in excess of cost 125,463 121,749 (3,759 ) (3,741 ) (4,703 ) (6,075 ) Net amount recognized $ 17,770 $ 33,757 $ (5,527 ) $ (5,925 ) $ (10,011 ) $ (10,070 ) Weighted average assumptions used in the measurement of the benefit obligations: Discount rate 4.34 % 4.13 % 3.85 % 3.69 % 4.38 % 4.03 % Rate of compensation increase 4.07 % 3.68 % N/A N/A N/A N/A As of October 31, 2015 , the benchmark by plan was as follows. Qualified pension plan 4.34 % NCNG SERP 3.78 % Directors’ SERP 3.91 % Piedmont SERP 3.17 % OPEB 4.38 %
Supplemental Executive Retirement Plans	Our funding to the DCR plan account for the years ended October 31, 2015 and 2014 , and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2015 and 2014 , are presented below. In thousands 2015 2014 Funding $ 548 $ 524 Liability: Current 236 214 Noncurrent 5,089 4,248
Term Life Insurance Premiums	The cost of these premiums is presented below. In thousands 2015 2014 2013 Term life policies of certain officers at the vice president level and above $ 35 $ 30 $ 27 Officers and director-level employees 30 32 28
Components Of Net Periodic Benefit Cost	Net periodic benefit cost components for the years ended October 31, 2015 , 2014 and 2013 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2015 , 2014 and 2013 are presented below. Qualified Pension Nonqualified Pension Other Benefits In thousands 2015 2014 2013 2015 2014 2013 2015 2014 2013 Service cost $ 11,403 $ 10,865 $ 12,005 $ — $ — $ — $ 1,182 $ 1,109 $ 1,327 Interest cost 12,018 11,781 9,946 209 200 157 1,475 1,448 1,130 Expected return on plan assets (23,614 ) (22,530 ) (21,105 ) — — — (1,837 ) (1,782 ) (1,663 ) Amortization of transition obligation — — — — — — — — 667 Amortization of prior service cost (credit) (2,198 ) (2,198 ) (2,198 ) 231 243 81 — — — Amortization of net loss 8,676 7,685 11,202 85 31 161 29 — — Net periodic benefit cost 6,285 5,603 9,850 525 474 399 849 775 1,461 Other changes in plan assets and benefit obligation recognized through regulatory asset or liability: Prior service cost (credit) — — — — 485 — (1,877 ) — — Net loss (gain) 26,179 14,385 (30,094 ) (100 ) 956 (540 ) 3,219 3,641 (2,278 ) Amounts recognized as a component of net periodic benefit cost: Transition obligation — — — — — — — — (667 ) Amortization of net loss (8,676 ) (7,685 ) (11,202 ) (85 ) (31 ) (161 ) (29 ) — — Prior service (cost) credit 2,198 2,198 2,198 (231 ) (243 ) (81 ) — — — Total recognized in regulatory asset (liability) 19,701 8,898 (39,098 ) (416 ) 1,167 (782 ) 1,313 3,641 (2,945 ) Total recognized in net periodic benefit and regulatory asset (liability) $ 25,986 $ 14,501 $ (29,248 ) $ 109 $ 1,641 $ (383 ) $ 2,162 $ 4,416 $ (1,484 ) Weighted average assumptions used to determine the net periodic benefit cost: Discount rate 4.13 % 4.55 % 3.51 % 3.69 % 3.98 % 2.95 % 4.03 % 4.44 % 3.34 % Expected long-term rate of return on plan assets 7.50 % 7.75 % 8.00 % N/A N/A N/A 7.50 % 7.75 % 8.00 % Rate of compensation increase 3.68 % 3.72 % 3.76 % N/A N/A N/A N/A N/A N/A
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 2016 $ 28,147 $ 520 $ 1,987 2017 19,911 504 2,145 2018 20,413 482 2,301 2019 21,348 510 2,421 2020 21,829 491 2,494 2021 - 2025 114,267 2,100 13,379
Assumed Health Care Cost Trend Rates	Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2015. 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 is presented below. 2014 Health care cost trend rate assumed for next year 7.40 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.00 % Year that the rate reaches the ultimate trend rate 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 amounts reported as benefit cost. A change of 1% would have the following effect. 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, 2015 $ 34 $ (35 )
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 - International growth Monthly None 30 days 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, 2015. 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 as of October 31, 2015 and 2014 are presented below. Qualified Pension Plan as of October 31, 2014 In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents $ 27,932 $ 435 $ — $ 28,367 Fixed income securities 48 78,026 — 78,074 Equity securities 51,266 — — 51,266 Mutual funds 54,502 48,049 — 102,551 Common trust fund — 22,877 — 22,877 Private equity fund of funds — — 7,158 7,158 Other Investments: Hedge fund of funds 19,829 (1) Commodities fund of funds 10,134 (1) High yield debt (bank loans) 16,187 (1) Total assets at fair value $ 133,748 $ 149,387 $ 7,158 $ 336,443 (1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. The qualified pension plan’s asset allocations by level within the fair value hierarchy as of October 31, 2015 and 2014 are presented below. Qualified Pension Plan as of October 31, 2015 In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents $ 2,782 $ 89 $ — $ 2,871 Fixed income securities — 84,135 — 84,135 Equity securities 44,738 — — 44,738 Mutual funds 78,853 42,890 — 121,743 Common trust fund — 23,571 — 23,571 Private equity fund of funds — — 8,344 8,344 Other Investments: Hedge fund of funds 19,809 (1) Commodities fund of funds 7,688 (1) High yield debt (bank loans) 16,408 (1) Total assets at fair value $ 126,373 $ 150,685 $ 8,344 $ 329,307 Other Benefits as of October 31, 2015 In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents $ 1,164 $ — $ — $ 1,164 Mutual funds 26,382 — — 26,382 Total assets at fair value $ 27,546 $ — $ — $ 27,546 Other Benefits as of October 31, 2014 In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents $ 2,590 $ — $ — $ 2,590 Mutual funds 25,157 — — 25,157 Total assets at fair value $ 27,747 $ — $ — $ 27,747
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, 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 Actual return on plan assets: Relating to assets still held at the reporting date 413 Relating to assets sold during the period 618 Purchases, sales and settlements (net) 155 Transfer in/out of Level 3 — Balance, October 31, 2015 $ 8,344
401(k) Matching Contributions	For the years ended October 31, 2015 , 2014 and 2013 , we made matching contributions to participant accounts as follows. In thousands 2015 2014 2013 401(k) matching contributions $ 6,584 $ 6,134 $ 5,688

Employee Share Based Plans (Tab

Employee Share Based Plans (Tables)	12 Months Ended
	Oct. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	The compensation expense related to the awards under the ICP for the years ended October 31, 2015 , 2014 and 2013 , 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, 2015 and 2014 are presented below. In thousands 2015 2014 2013 Compensation expense $ 14,173 $ 8,496 $ 4,526 Tax benefit 3,966 2,476 1,538 Liability 22,037 15,130
Expected Payout For Approved Incentive Compensation Plans	Based on current accrual assumptions as of October 31, 2015 , the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years with the 2015 plan paying out in fiscal year 2016, the 2016 plan paying out in fiscal year 2017 and the 2017 plan paying out in fiscal year 2018. Payouts as currently accrued are presented net of estimated federal and state withholding payments. In thousands 2016 2017 2018 Amount of payout $ 10,866 $ 8,179 $ 2,992

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Oct. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of income tax expense for the years ended October 31, 2015 , 2014 and 2013 are presented below. 2015 2014 2013 In thousands Federal State Federal State Federal State Charged (Credited) to operating income: Current $ (10,449 ) $ (289 ) $ (1,653 ) $ 950 $ (3,032 ) $ 919 Deferred (1) (2) 75,644 12,195 70,654 13,434 67,885 11,829 Tax Credits: Amortization (167 ) — (209 ) — (267 ) — Total 65,028 11,906 68,792 14,384 64,586 12,748 Charged (Credited) to other income (expense): Current 9,709 1,449 4,233 870 6,049 984 Deferred (1) (2) 2,249 (119 ) 5,811 728 2,225 (646 ) Total 11,958 1,330 10,044 1,598 8,274 338 Total $ 76,986 $ 13,236 $ 78,836 $ 15,982 $ 72,860 $ 13,086 (1) Includes benefits from net operating loss (NOL) and tax carryforwards of $64.3 million and $62.3 million for the years ended October 31, 2015 and 2013, respectively. (2) Includes the utilization of NOL carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 Federal taxes at 35% $ 79,532 $ 83,517 $ 77,127 State income taxes, net of federal benefit 8,604 10,389 8,506 Amortization of investment tax credits (167 ) (209 ) (267 ) Other, net 2,253 1,121 580 Total $ 90,222 $ 94,818 $ 85,946
Schedule of Deferred Tax Assets and Liabilities	As of October 31, 2015 and 2014 , deferred income taxes consisted of the following temporary differences. In thousands 2015 2014 Deferred tax assets: Benefit of loss carryforwards $ 84,025 $ 39,532 Revenues and cost of gas 3,495 4,960 Employee benefits and compensation 22,134 16,547 Revenue requirement 26,088 20,320 Utility plant 7,481 5,631 Other 10,461 12,869 Total deferred tax assets 153,684 99,859 Valuation allowance (848 ) (505 ) Total deferred tax assets, net 152,836 99,354 Deferred tax liabilities: Utility plant 849,835 724,172 Revenues and cost of gas — 4,340 Equity method investments 44,778 42,998 Deferred costs 73,903 65,828 Other 13,543 18,065 Total deferred tax liabilities 982,059 855,403 Net deferred income tax liabilities $ 829,223 $ 756,049
Summary of Valuation Allowance	A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2015 , 2014 and 2013 is presented below. In thousands 2015 2014 2013 Balance at beginning of year $ 505 $ 505 $ 505 Charged to income tax expense 343 — — Balance at end of year $ 848 $ 505 $ 505

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Oct. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Method Investments	Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2015 , and for the twelve months ended September 30, 2015 , is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014. In thousands 2015 Current assets $ 23,422 Noncurrent assets 86,109 Current liabilities 9,105 Noncurrent liabilities — Revenues — Gross profit — (Loss) before income taxes (5,205 ) Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2015 and 2014 , and for the twelve months ended October 31, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 11,658 $ 12,644 Noncurrent assets 156,803 157,861 Current liabilities 19,078 17,316 Noncurrent liabilities 69,971 78,830 Revenues 23,350 23,804 $ 24,375 Gross profit 23,350 23,804 24,375 Income before income taxes 10,403 10,497 10,582 Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2015 and 2014 , and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 9,451 $ 8,856 Noncurrent assets 106,444 111,881 Current liabilities 1,228 1,468 Noncurrent liabilities 45,446 45,402 Revenues 16,629 16,705 $ 17,649 Gross profit 16,629 16,705 17,649 Income before income taxes 7,742 8,042 9,361 We have the following membership interests in these companies as of October 31, 2015 and 2014 . Entity Name Interest Activity Cardinal Pipeline Company, LLC (Cardinal) 21.49% Intrastate pipeline located in North Carolina; regulated by the NCUC Pine Needle LNG Company, LLC (Pine Needle) 45% Interstate LNG storage facility located in North Carolina; regulated by the FERC SouthStar Energy Services, LLC (SouthStar) 15% Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois Hardy Storage Company (Hardy Storage) 50% Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC Constitution Pipeline Company LLC (Constitution) 24% To develop, construct, own and operate 124 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC Atlantic Coast Pipeline, LLC (ACP) 10% To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2015 and 2014 , and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 6,163 $ 11,273 Noncurrent assets 330,152 219,208 Current liabilities 4,398 7,667 Noncurrent liabilities — — Revenues — — $ — Gross profit — — — Income before income taxes 24,604 10,091 3,459 Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2015 and 2014, and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014* 2013 Current assets $ 204,237 $ 192,151 Noncurrent assets 132,315 143,958 Current liabilities 45,953 47,923 Noncurrent liabilities — — Revenues 769,295 845,695 $ 639,426 Gross profit 224,612 234,581 174,993 Income before income taxes 129,340 136,569 102,805 * Balance sheet amounts have been changed to reflect SouthStar's reclassification of cash collateral under accounting guidance. Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2015 and 2014 , and for the twelve months ended September 30, 2015 , 2014 and 2013 , is presented below. In thousands 2015 2014 2013 Current assets $ 9,863 $ 8,812 Noncurrent assets 71,586 70,837 Current liabilities 5,377 38,029 Noncurrent liabilities 35,112 — Revenues 16,913 18,025 $ 16,810 Gross profit 16,913 18,025 16,810 Income before income taxes 6,002 6,011 5,804 For the years ended October 31, 2015 , 2014 and 2013 , these gas costs and the amounts we owed to our equity method investees, as of October 31, 2015 and 2014 , are as follows. Related Party Type of Expense Cost of Gas (1) Trade accounts payable (2) In thousands 2015 2014 2013 2015 2014 Cardinal Transportation costs $ 8,763 $ 8,825 8,775 $ 744 $ 747 Pine Needle Gas storage costs 11,441 11,364 11,098 955 989 Hardy Storage Gas storage costs 9,290 9,461 9,702 774 774 Totals $ 29,494 $ 29,650 $ 29,575 $ 2,473 $ 2,510 (1) In the Consolidated Statements of Comprehensive Income. (2) In the Consolidated Balance Sheets. For the years ended October 31, 2015 , 2014 and 2013 , our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2015 and 2014 , are as follows. Operating Revenues (1) Trade accounts receivable (2) In thousands 2015 2014 2013 2015 2014 Operating revenues $ 1,568 $ 3,541 $ 3,291 $ 183 $ 460 (1) In the Consolidated Statements of Comprehensive Income. (2) In the Consolidated Balance Sheets.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Oct. 31, 2015
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Schedule of Variable Interest Entities Investment Balances	As of October 31, 2015 and 2014 , our investment balances are as follows. October 31, October 31, In thousands 2015 2014 Cardinal $ 15,083 $ 16,073 Pine Needle 18,396 18,689 SouthStar 41,325 40,965 Hardy Storage 39,706 37,179 Constitution 82,403 57,255 ACP 10,043 10 Total equity method investments in non-utility activities $ 206,956 $ 170,171

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Oct. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Operations by segment for the years ended October 31, 2015 , 2014 and 2013 , and as of October 31, 2015 , 2014 and 2013 , are presented below. Regulated Unregulated Regulated Non-Utility Non-Utility In thousands Utility Activities Activities Total 2015 Revenues from external customers $ 1,371,718 $ — $ — $ 1,371,718 Margin 727,294 — — 727,294 Operations and maintenance expenses 294,517 81 105 294,703 Depreciation 128,704 — 18 128,722 Operating income (loss) before income taxes 261,963 (152 ) (217 ) 261,594 Income from equity method investments — 15,060 19,401 34,461 Interest charges 68,631 — — 68,631 Income before income taxes 193,140 14,909 19,184 227,233 Total assets 4,742,284 165,630 41,682 4,949,596 Equity method investments in non-utility activities — 165,630 41,326 206,956 Construction expenditures 443,654 — — 443,654 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 charges 54,686 — — 54,686 Income before income taxes 206,253 12,135 20,231 238,619 Total assets (1) 4,432,239 129,206 41,309 4,602,754 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 charges 24,938 — — 24,938 Income before income taxes 194,659 10,434 15,270 220,363 Total assets (1) 4,045,259 90,097 38,735 4,174,091 Equity method investments in non-utility activities — 90,097 38,372 128,469 Construction expenditures 599,999 — — 599,999 (1) Regulated utility total assets have been adjusted in 2014 and 2013 to reflect the netting of debt issuance costs with its debt carrying value in accordance with the 2015 adoption of new accounting guidance related to this balance sheet presentation.
Reconciliation of Operating Profit (Loss) from Segments to Consolidated	Reconciliations to the consolidated financial statements for the years ended October 31, 2015 , 2014 and 2013 , and as of October 31, 2015 and 2014 are as follows. In thousands 2015 2014 2013 Operating Income: Segment operating income before income taxes $ 261,594 $ 262,655 $ 221,176 Utility income taxes (76,934 ) (83,176 ) (77,334 ) Regulated non-utility activities operating loss before income taxes 152 183 150 Unregulated non-utility activities operating loss before income taxes 217 203 202 Total $ 185,029 $ 179,865 $ 144,194 Net Income: Income before income taxes for reportable segments $ 227,233 $ 238,619 $ 220,363 Income taxes (90,222 ) (94,818 ) (85,946 ) Total $ 137,011 $ 143,801 $ 134,417
Reconciliation of Assets from Segment to Consolidated	In thousands 2015 2014 Consolidated Assets: Total assets for reportable segments $ 4,949,596 $ 4,602,754 Eliminations/Adjustments 161,154 171,553 Total $ 5,110,750 $ 4,774,307 Reconciliations to the consolidated financial statements for the years ended October 31, 2015 , 2014 and 2013 , and as of October 31, 2015 and 2014 are as follows.

Selected Quarterly Financial 41

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Oct. 31, 2015
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited) Earnings (Loss) Operating Net Per Share of Operating Income Income Common Stock Revenues Margin (Loss) (Loss) Basic Diluted Fiscal Year 2015 January 31 $ 607,271 $ 270,070 $ 105,758 $ 92,978 $ 1.18 $ 1.18 April 30 424,924 225,621 75,123 66,402 0.84 0.84 July 31 158,266 111,572 5,233 (8,260 ) (0.10 ) (0.10 ) October 31 181,257 120,031 (1,085 ) (14,109 ) (0.18 ) (0.18 ) Fiscal Year 2014 January 31 $ 657,733 $ 261,512 $ 102,319 $ 97,572 $ 1.27 $ 1.26 April 30 462,247 211,523 67,299 62,540 0.80 0.80 July 31 164,187 104,847 3,254 (7,344 ) (0.09 ) (0.09 ) October 31 185,821 112,326 6,993 (8,967 ) (0.11 ) (0.11 )

Summary Of Significant Accoun42

Summary Of Significant Accounting Policies (Details)		1 Months Ended	12 Months Ended
		Apr. 30, 2014USD ($)	Oct. 31, 2015USD ($)segment	Oct. 31, 2014USD ($)	Oct. 31, 2013USD ($)	Oct. 31, 2015USD ($)	Oct. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 31, 2012USD ($)
Segment Reporting [Abstract]
Number of Reportable Segments | segment			3
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Intangible plant						$ 3,374,000	$ 3,374,000
Other storage plant						180,960,000	180,058,000
Transmission plant						2,024,264,000	1,787,990,000
Distribution plant						2,766,871,000	2,623,560,000
General plant						452,301,000	421,763,000
Asset retirement cost						4,159,000	11,000
Contributions in aid of construction						(5,345,000)	(5,259,000)
Total utility plant in service						5,426,584,000	5,011,497,000
Less accumulated depreciation						(1,251,940,000)	(1,166,922,000)
Utility plant in service, net						4,174,644,000	3,844,575,000
Construction work in progress						170,250,000	141,693,000
Plant held for future use						3,155,000	3,155,000
Total utility plant, net						4,348,049,000	3,989,423,000
Public Utilities, Property, Plant and Equipment [Abstract]
Allowance for borrowed funds used during construction			$ 11,106,000	$ 16,427,000	$ 30,975,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use						3,155,000	3,155,000
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment					$ 1,800,000
Composite weighted-average depreciation rates			2.48%	2.54%	2.77%
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						207,662,000	202,118,000
Regulatory Assets, Current						10,936,000	27,837,000
Accounts, Notes, Loans and Financing Receivable, Net, Current [Abstract]
Gas receivables						57,759,000	64,400,000
Non-regulated merchandise and service work receivables						3,137,000	3,012,000
Allowance for doubtful accounts			$ (2,152,000)	$ (1,604,000)	$ (1,579,000)	(1,648,000)	(2,152,000)		$ (1,579,000)
Trade accounts receivable	[1]					59,248,000	65,260,000
Customers Payment Due Date			30 days
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year			$ 2,152,000	1,604,000	1,579,000
Additions charged to uncollectibles expense			5,095,000	6,959,000	5,314,000
Accounts written off, net of recoveries			(5,599,000)	(6,411,000)	(5,289,000)
Balance at end of year			1,648,000	2,152,000	1,604,000
Inventory, Net [Abstract]
Natural Gas Inventories Not Available For Sale Held by Asset Manager			$ 24,800,000	35,000,000
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Near Term Redemption			180 days
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill, Impairment Loss			$ 0	0	0
Asset Impairment Charges		$ 2,000,000	0		0
Schedule of Trading Securities and Other Trading Assets [Line Items]
Current trading securities (cost)						165,000	128,000
Noncurrent trading securities(cost)						4,090,000	3,045,000
Current trading securities (fair value)						236,000	214,000
Noncurrent trading securities (fair value)						4,666,000	3,727,000
Total trading securities (cost)						4,255,000	3,173,000
Total trading securities (fair value)						4,902,000	3,941,000
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Conditional AROs						19,712,000	14,647,000
Total cost of removal obligations						541,190,000	521,221,000
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of period			14,647,000	27,016,000
Liabilities incurred during the period			4,663,000	2,108,000
Liabilities settled during the period			(5,563,000)	(3,576,000)
Accretion			924,000	1,548,000
Adjustment to estimated cash flows			5,041,000	(12,449,000)
End of period			$ 19,712,000	$ 14,647,000	$ 27,016,000
Regulatory Liabilities [Line Items]
Regulatory liabilities						590,301,000	558,598,000
Deferred Finance Costs [Abstract]
Long Term Debt Expense Amortization Period			5 to 30 years
Short Term Debt Expense Amortization Period			5 years
North Carolina Utilities Commission
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Study Requirement			5 years
Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			5 years
Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			80 years
Asset Retirement Obligation
Regulatory Liabilities [Line Items]
Regulatory liabilities						521,478,000	506,574,000
Robeson LNG development costs
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Current						381,000	917,000
Robeson LNG development costs | General Rate Application Settlement 2013 | North Carolina Utilities Commission
Public Utilities, General Disclosures [Line Items]
Regulatory Assets								$ 1,200,000
Regulatory Asset, Amortization Period			38 months
Regulatory Noncurrent Asset, End Date for Recovery			Feb. 28, 2017
Robeson LNG development costs | Settlement With Office of Regulatory Staff October 2014 | Public Service Commission of South Carolina
Public Utilities, General Disclosures [Line Items]
Regulatory Asset, Amortization Period			12 months
Regulatory Assets, Current							500,000
Land
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant held for future use									3,200,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use									3,200,000
Non-real Estate Costs
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant held for future use									3,500,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use									$ 3,500,000
Asset Retirement Obligation | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value Assumptions, Risk Free Interest Rate			4.62%
Asset Retirement Obligation | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value Assumptions, Risk Free Interest Rate			5.89%
Asset Retirement Obligation | Weighted Average
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value Assumptions, Risk Free Interest Rate			5.69%
Money Market Funds
Schedule of Trading Securities and Other Trading Assets [Line Items]
Current trading securities (cost)						51,000	22,000
Noncurrent trading securities(cost)						465,000	447,000
Current trading securities (fair value)						51,000	22,000
Noncurrent trading securities (fair value)						465,000	447,000
Equity Funds
Schedule of Trading Securities and Other Trading Assets [Line Items]
Current trading securities (cost)						114,000	106,000
Noncurrent trading securities(cost)						3,625,000	2,598,000
Current trading securities (fair value)						185,000	192,000
Noncurrent trading securities (fair value)						$ 4,201,000	$ 3,280,000
[1]	See Note 13 for amounts attributable to affiliates.

Proposed Acquisition by Duke 43

Proposed Acquisition by Duke Energy Corporation (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Oct. 31, 2015	Oct. 24, 2015
Business Combinations [Abstract]
Business Acquisition, Date of Acquisition Agreement	Oct. 24, 2015
Business Acquisition, Share Price		$ 60
Business Acquisition, Acquiree Termination Fee	$ 125
Business Acquisition, Acquirer Termination Fee	$ 250
Maximum Annual Dividend Increase Per Share	$ 0.04
Business Acquisition, Transaction Costs	$ 8.6
Business Acquisition, Incremental Share Based Compensation	$ 7.2

Regulatory Matters Regulatory44

Regulatory Matters Regulatory Matters - Assets and Liabilities (Details) - USD ($) $ in Thousands	Oct. 31, 2015	Oct. 31, 2014
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 10,936	$ 27,837
Regulatory Assets, Noncurrent	196,726	174,281
Total Regulatory Assets	207,662	202,118
Other Regulatory Assets On Which We Do Not Earn a Return	117,000
Regulatory Liabilities [Line Items]
Regulatory liabilities, Current	13,367	46,231
Regulatory liabilities, Noncurrent	590,301	558,598
Regulatory Liabilities, Total	603,668	604,829
Amounts due to customers
Regulatory Liabilities [Line Items]
Regulatory liabilities, Current	13,367	46,231
Regulatory cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities, Noncurrent	521,478	506,574
Deferred income taxes
Regulatory Liabilities [Line Items]
Regulatory liabilities, Noncurrent	68,738	51,930
Amounts not yet recognized as a component of pension and other retirement benefit costs
Regulatory Liabilities [Line Items]
Regulatory liabilities, Noncurrent	85	94
Unamortized debt expense on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets, Current	238	239
Regulatory Assets, Noncurrent	4,666	4,904
Amounts due from customers
Regulatory Assets [Line Items]
Regulatory Assets, Current	0	16,108
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets, Current	1,513	1,568
Regulatory Assets, Noncurrent	5,107	6,470
Total Regulatory Assets	6,600
Deferred operations and maintenance expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current	847	916
Regulatory Assets, Noncurrent	3,997	4,721
Deferred pipeline integrity expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current	3,470	3,470
Regulatory Assets, Noncurrent	29,824	24,694
Deferred pension and other retirement benefit costs
Regulatory Assets [Line Items]
Regulatory Assets, Current	2,757	2,769
Regulatory Assets, Noncurrent	17,861	18,799
Amounts not yet recognized as a component of pension and other retirement benefit costs
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	114,854	94,265
Regulatory cost of removal
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	19,087	18,275
Amount Of Regulatory Costs Approved To Be Accrued Not Included In Rate Base	19,100
Robeson LNG development costs
Regulatory Assets [Line Items]
Regulatory Assets, Current	381	917
Regulatory Assets, Noncurrent	127	509
Other
Regulatory Assets [Line Items]
Regulatory Assets, Current	1,730	1,850
Regulatory Assets, Noncurrent	$ 1,203	1,644
New Accounting Pronouncement, Early Adoption, Effect | Current Regulatory Asset [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Unamortized debt expense		(900)
New Accounting Pronouncement, Early Adoption, Effect | Non-current Regulatory Asset
New Accounting Pronouncement, Early Adoption [Line Items]
Unamortized debt expense		(9,000)
New Accounting Pronouncement, Early Adoption, Effect | Long Term Debt
New Accounting Pronouncement, Early Adoption [Line Items]
Unamortized debt expense		$ 9,900

Regulatory Matters (Details)

Regulatory Matters (Details)

1 Months Ended

2 Months Ended

11 Months Ended

12 Months Ended

24 Months Ended

Dec. 31, 2015USD ($)

Nov. 30, 2015USD ($)

Apr. 30, 2015USD ($)

Oct. 31, 2014USD ($)

Sep. 30, 2014USD ($)

Apr. 30, 2014USD ($)

Dec. 31, 2015

Sep. 30, 2015USD ($)

Oct. 31, 2015USD ($)Integer

Oct. 31, 2014USD ($)

Oct. 31, 2013USD ($)

Dec. 31, 2001USD ($)

Dec. 31, 2000USD ($)

Dec. 31, 1998USD ($)

Dec. 31, 2001USD ($)

Jan. 01, 2014USD ($)

Dec. 31, 2013USD ($)

Aug. 31, 2013USD ($)

Oct. 31, 2012USD ($)

Mar. 01, 2012USD ($)

Feb. 29, 2012

Oct. 31, 2008USD ($)

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 202,118,000

$ 207,662,000

$ 202,118,000

Regulatory Assets, Current

27,837,000

10,936,000

27,837,000

Operations and maintenance

294,517,000

270,877,000

$ 253,120,000

Increase (Decrease) in Regulatory Liabilities

$ (16,065,000)

49,468,000

23,429,000

Percentage Of Net Secondary Market Margins Flowed Through To Customers

75.00%

Percentage Of Net Secondary Market Margins Retained

25.00%

Allocated to customers as gas cost reductions

$ 60,100,000

72,200,000

26,900,000

Margin allocated to us

21,100,000

25,400,000

9,000,000

Margin from secondary market activity

81,200,000

97,600,000

35,900,000

North Carolina Utilities Commission

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Debt Equity Securities Limit, Amount

$ 1,000,000,000

Public Utilities, Rate Matters, Requested [Abstract]

Request Transfer Plant Held For Future Use To Deferred Regulatory Asset

$ 6,700,000

North Carolina Utilities Commission | Maximum

Public Utilities, Rate Matters, Requested [Abstract]

Target Percentage Range Normalized Sales

45.00%

North Carolina Utilities Commission | EasternNC Exclusive Franchise Rights

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

North Carolina Utilities Commission | North Carolina IMR Adjustment 2014

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 800,000

North Carolina Utilities Commission | General Rate Application Settlement 2013

Public Utilities, Rate Matters, Approved [Abstract]

Overall Rate Base With Approved Rates And Charges

$ 1,800,000,000

Public Utilities, Approved Equity Capital Structure, Percentage

50.70%

Public Utilities, Approved Return on Equity, Percentage

10.00%

Public Utilities, Approved Return on Investment, Percentage

7.51%

Approved Annual Average Revenue Percentage Increase From Last Rate Case

0.70%

North Carolina Utilities Commission | General Rate Application Settlement 2013 | Sales

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%

North Carolina Utilities Commission | General Rate Application Settlement 2013 | Sales | Gas Utility Margin

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 16,800,000

North Carolina Utilities Commission | General Rate Application Settlement 2013 | Sales | Fixed Gas Costs

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

13,800,000

North Carolina Utilities Commission | General Rate Application Settlement 2013 | Revised Pre-Tax Income

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

24,200,000

North Carolina Utilities Commission | General Rate Application Settlement 2013 | Operating Expense

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (10,900,000)

North Carolina Utilities Commission | North Carolina Public Staff Audit 2013 Gas Cost Review Period

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

North Carolina Utilities Commission | North Carolina Public Staff Audit 2014 Gas Cost Review Period

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

North Carolina Utilities Commission | North Carolina Public Staff Audit 2015 Gas Cost Review Period | Subsequent Event

Public Utilities, Rate Matters, Approved [Abstract]

Percentage Of Allowed Recovery For Gas Costs

100.00%

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

North Carolina Utilities Commission | NCUC IMR Settlement Agreement November 2015 | Subsequent Event

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 13,400,000

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $13.4 million in annual IMR margin revenues, effective December 1, 2015, based on $161.9 million of IMR-eligible capital investments in integrity and safety projects over the eleven-month period ended September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase.

North Carolina Utilities Commission | NCUC Petition for IMR Rate Adjustment Filed December 2014

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 26,600,000

North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Transmission Integrity

Public Utilities, Rate Matters, Requested [Abstract]

Recovery Percentage Of System Integrity Expenditures Through IMR

85.00%

Recovery Percentage Of System Integrity Expenditures Through Rate Case

15.00%

North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Distribution Integrity

Public Utilities, Rate Matters, Requested [Abstract]

Recovery Percentage Of System Integrity Expenditures Through IMR

90.00%

Recovery Percentage Of System Integrity Expenditures Through Rate Case

10.00%

North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Right Of Way Clearing

Public Utilities, Rate Matters, Requested [Abstract]

Recovery Percentage Of System Integrity Expenditures Through IMR

15.00%

Recovery Percentage Of System Integrity Expenditures Through Rate Case

85.00%

North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Work and Asset Management System

Public Utilities, Rate Matters, Requested [Abstract]

Recovery Percentage Of System Integrity Expenditures Through IMR

68.00%

Recovery Percentage Of System Integrity Expenditures Through Rate Case

32.00%

North Carolina Utilities Commission | NCUC Petition Filed IMR November 2015 | Subsequent Event

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 13,400,000

North Carolina Utilities Commission | NCUC Petition for Limited Waiver 2014

Public Utilities, Rate Matters, Requested [Abstract]

Operations and maintenance

65,000

North Carolina Utilities Commission | NCUC Open Shelf Registration Statement April 2014

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Debt Equity Securities Limit, Amount

$ 1,000,000,000

North Carolina Utilities Commission | NCUC Approved Customer Bill Credit March 2015 | Amounts due to customers

Public Utilities, Rate Matters, Requested [Abstract]

Increase (Decrease) in Regulatory Liabilities

$ (45,500,000)

Public Service Commission of South Carolina

Public Utilities, Rate Matters, Requested [Abstract]

Maximum Utility Rate of Return Change Allowed Under RSA | Integer

50

Public Service Commission of South Carolina | Maximum

Public Utilities, Rate Matters, Requested [Abstract]

Target Percentage Range Normalized Sales

45.00%

Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2012

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

11.30%

Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2012 | Margin

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (1,100,000)

Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2013

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

11.30%

Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2013 | Margin

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (100,000)

Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

10.20%

Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014 | Margin

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (2,900,000)

Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2015

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Return on Equity, Percentage

10.20%

Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2015 | Margin

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 1,650,000

Tennessee Regulatory Authority

Public Utilities, Rate Matters, Requested [Abstract]

Annual Incentive Cap On Gains And Losses

1,600,000

Tennessee Regulatory Authority | Adjustment Filed August 2013

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 | TRA Settlement December 2014

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 2,000,000

Tennessee Regulatory Authority | Actual Cost Adjustment | Subsequent Event

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In November 2015, we filed an annual report for the twelve months ended June 30, 2014 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 | General Rate Application Settlement 2012

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 | General Rate Application Settlement 2012 | Sales

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 | Tennessee IMR Petition August 2013

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 13,100,000

Tennessee Regulatory Authority | Tennessee IMR Settlement 2013

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

13,100,000

Tennessee Regulatory Authority | TRA IMR Rate Adjustment Petition Filed December 2014

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

6,500,000

Tennessee Regulatory Authority | TRA Petition Filed IMR November 2015 | Subsequent Event

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 1,700,000

Public Utilities, Disclosure of Rate Matters

In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual IMR margin revenues effectIn November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016. We are waiting on the TRA's written order at this time.

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

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

(4,700,000)

Tennessee Regulatory Authority | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes | Subsequent Event

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (4,700,000)

Public Utilities, Rate Matters, Requested [Abstract]

Public Utilities, Disclosure of Rate Matters

In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we will begin refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. We are waiting on the TRA's written order at this time.

Tennessee Regulatory Authority | TRA IMR Order February 2015

Public Utilities, Rate Matters, Approved [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

6,500,000

Tennessee Regulatory Authority | Tennessee CNG Order October 2015

Public Utilities, Rate Matters, Requested [Abstract]

Deferral CNG Equipment In Utility Rate Base

4,700,000

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

North Carolina | NCUC Petition Filed IMR November 2015

Public Utilities, Rate Matters, Requested [Abstract]

Capital Investments In Integrity and Safety Projects

$ 161,900,000

Tennessee

Public Utilities, Rate Matters, Requested [Abstract]

Capital Investments In Integrity and Safety Projects

18,400,000

54,000,000

Deferred operations and maintenance expenses

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

916,000

$ 847,000

916,000

Deferred operations and maintenance expenses | North Carolina Utilities Commission

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

$ 4,800,000

5,600,000

Deferred operations and maintenance expenses | North Carolina Utilities Commission | General Rate Case Proceeding 2008

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

12 years

Interest Accrued On Deferred Expenses

7.84%

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 9,000,000

Deferred operations and maintenance expenses | North Carolina Utilities Commission | General Rate Application Settlement 2013

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

82 months

Interest Accrued On Deferred Expenses

6.55%

Regulatory Noncurrent Asset, End Date for Recovery

Oct. 31, 2020

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 6,300,000

Deferred pipeline integrity expenses

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

3,470,000

$ 3,470,000

3,470,000

Deferred pipeline integrity expenses | North Carolina Utilities Commission

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

28,200,000

$ 33,300,000

28,200,000

Deferred pipeline integrity expenses | North Carolina Utilities Commission | General Rate Application Settlement 2013

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

5 years

Regulatory Noncurrent Asset, End Date for Recovery

Dec. 31, 2018

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 17,300,000

Environmental costs

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 6,600,000

Regulatory Assets, Current

1,568,000

$ 1,513,000

1,568,000

Environmental costs | North Carolina Utilities Commission | General Rate Application Settlement 2013

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

5 years

Regulatory Noncurrent Asset, End Date for Recovery

Dec. 31, 2018

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

6,300,000

Environmental costs | Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2013

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

1 year

Regulatory Current Asset, End Date for Recovery

October 31, 2014

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

$ 200,000

Environmental costs | Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

1 year

Regulatory Current Asset, End Date for Recovery

October 31, 2015

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

100,000

100,000

Regulatory Assets, Current

100,000

100,000

Environmental costs | Tennessee Regulatory Authority | General Rate Application Settlement 2012

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

8 years

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 2,000,000

Robeson LNG development costs

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

917,000

$ 381,000

917,000

Robeson LNG development costs | North Carolina Utilities Commission | General Rate Application Settlement 2013

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

38 months

Regulatory Noncurrent Asset, End Date for Recovery

Feb. 28, 2017

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 1,200,000

Robeson LNG development costs | Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

12 months

Regulatory Current Asset, End Date for Recovery

October 31, 2015

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

500,000

500,000

Other

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets, Current

$ 1,850,000

$ 1,730,000

$ 1,850,000

Other | Tennessee Regulatory Authority | General Rate Application Settlement 2012

Public Utilities, Rate Matters, Approved [Abstract]

Regulatory Asset, Amortization Period

8 years

Regulatory Noncurrent Asset, End Date for Recovery

Feb. 28, 2020

Public Utilities, Rate Matters, Requested [Abstract]

Regulatory Assets

$ 1,000,000

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Jan. 31, 2015	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Earnings Per Share [Abstract]
Net income	$ (14,109)	$ (8,260)	$ 66,402	$ 92,978	$ (8,967)	$ (7,344)	$ 62,540	$ 97,572	$ 137,011	$ 143,801	$ 134,417
Average shares of common stock outstanding for basic earnings per share									78,942	77,883	74,884
Contingently issuable shares under incentive compensation plans									289	310	289
Contingently issuable shares under forward sale agreements									0	0	160
Average shares of dilutive stock									79,231	78,193	75,333
Basic (usd per share)	$ (0.18)	$ (0.10)	$ 0.84	$ 1.18	$ (0.11)	$ (0.09)	$ 0.80	$ 1.27	$ 1.74	$ 1.85	$ 1.80
Diluted (usd per share)	$ (0.18)	$ (0.10)	$ 0.84	$ 1.18	$ (0.11)	$ (0.09)	$ 0.80	$ 1.26	$ 1.73	$ 1.84	$ 1.78

Long Term Debt (Details)

Long Term Debt (Details)	Sep. 14, 2015USD ($)	Sep. 18, 2014USD ($)	Oct. 31, 2015USD ($)	Oct. 31, 2014USD ($)
Debt Instrument [Line Items]
Long-term debt, principal			$ 1,575,000,000	$ 1,425,000,000
Current maturities of long-term debt			40,000,000	0
Long-term debt, net excluding current maturities			1,523,677,000	1,414,484,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months			40,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Two			35,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three			0
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			1,500,000,000
Total Long-term Debt			1,575,000,000	1,425,000,000
Net Earnings Available For Restricted Payments			$ 1,200,000,000
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			3.96
Senior Debt Default Provision, Ratio of Indebtedness to Net Capital			0.7
Ratio of Indebtedness to Net Capital			0.57
Senior Debt Default Provision, Funded Debt of Subsidiaries			0.15
Funded Debt Of Subsidiaries			$ 0
North Carolina Utilities Commission
Long-term Debt, Fiscal Year Maturity [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount			$ 1,000,000,000
Debt and Equity Shelf Registration, Term			3 years
Public Utilities, Approved Debt Equity Securities Limit, Amount Remaining			$ 544,100,000
New Accounting Pronouncement, Early Adoption, Effect
Debt Instrument [Line Items]
Current maturities of long-term debt			40,000,000	0
Long-Term Debt, Gross less current maturities			1,535,000,000	1,425,000,000
Long-term debt, net excluding current maturities			1,523,677,000	1,414,484,000
New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			1,575,000,000	1,425,000,000
Unamortized Debt Issuance Expense			(11,323,000)	(10,516,000)
Long-term debt, net including current maturities			1,563,677,000	1,414,484,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 1,575,000,000	1,425,000,000
Senior Notes 2.92%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			2.92%
Debt Instrument, Maturity Date			Jun. 6, 2016
Senior Notes 2.92% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 40,000,000	40,000,000
Unamortized Debt Issuance Expense			(40,000)	(107,000)
Long-term debt, net including current maturities			39,960,000	39,893,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 40,000,000	40,000,000
Senior Notes 8.51%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.51%
Debt Instrument, Maturity Date			Sep. 30, 2017
Senior Notes 8.51% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 35,000,000	35,000,000
Unamortized Debt Issuance Expense			0	0
Long-term debt, net including current maturities			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%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.24%
Debt Instrument, Maturity Date			Jun. 6, 2021
Senior Notes 4.24% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 160,000,000	160,000,000
Unamortized Debt Issuance Expense			(752,000)	(887,000)
Long-term debt, net including current maturities			159,248,000	159,113,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 160,000,000	160,000,000
Senior Notes 3.47%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			3.47%
Debt Instrument, Maturity Date			Jul. 16, 2027
Senior Notes 3.47% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 100,000,000	100,000,000
Unamortized Debt Issuance Expense			(638,000)	(693,000)
Long-term debt, net including current maturities			99,362,000	99,307,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 100,000,000	100,000,000
Senior Notes 3.57%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			3.57%
Debt Instrument, Maturity Date			Jul. 16, 2027
Senior Notes 3.57% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 200,000,000	200,000,000
Unamortized Debt Issuance Expense			(1,307,000)	(1,418,000)
Long-term debt, net including current maturities			198,693,000	198,582,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 200,000,000	200,000,000
Senior Notes 4.10%
Debt Instrument [Line Items]
Discount on issuance of notes		$ 435,000
Debt Instrument, Interest Rate, Stated Percentage			4.10%
Debt Instrument, Maturity Date			Sep. 18, 2034
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Issuance Date			Sep. 18, 2014
Debt Instrument, Face Amount		$ 250,000,000
Debt Instrument, Term			20 years
Debt Issuance Discount Percentage		0.174%
Proceeds from Debt, Net of Issuance Costs		$ 247,700,000
Senior Notes 4.10% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 250,000,000	250,000,000
Unamortized Debt Issuance Expense			(2,644,000)	(2,644,000)
Long-term debt, net including current maturities			247,356,000	247,356,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 250,000,000	250,000,000
Senior Notes 4.10% | Debt Instrument, Redemption, Period One
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			Sep. 18, 2014
Debt Instrument, Redemption Period, End Date			Mar. 17, 2034
Debt Instrument, Redemption Price, Percentage			100.00%
Senior Notes 4.10% | Debt Instrument, Redemption, Period One | Base Rate
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate			0.15%
Senior Notes 4.10% | Debt Instrument, Redemption, Period Two
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			Mar. 18, 2034
Debt Instrument, Redemption Period, End Date			Sep. 18, 2034
Debt Instrument, Redemption Price, Percentage			100.00%
Senior Notes 4.65%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.65%
Debt Instrument, Maturity Date			Aug. 1, 2043
Senior Notes 4.65% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 300,000,000	300,000,000
Unamortized Debt Issuance Expense			(3,040,000)	(3,132,000)
Long-term debt, net including current maturities			296,960,000	296,868,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 300,000,000	300,000,000
Senior Notes 3.60%
Debt Instrument [Line Items]
Discount on issuance of notes	$ 97,500
Debt Instrument, Interest Rate, Stated Percentage			3.60%
Debt Instrument, Maturity Date			Sep. 1, 2025
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Issuance Date			Sep. 14, 2015
Debt Instrument, Face Amount	$ 150,000,000
Debt Instrument, Term			10 years
Debt Issuance Discount Percentage	0.065%
Proceeds from Debt, Net of Issuance Costs	$ 148,900,000
Senior Notes 3.60% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 150,000,000
Unamortized Debt Issuance Expense			(1,382,000)
Long-term debt, net including current maturities			148,618,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 150,000,000
Senior Notes 3.60% | Debt Instrument, Redemption, Period One
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 25 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date			Sep. 14, 2015
Debt Instrument, Redemption Period, End Date			May 31, 2025
Debt Instrument, Redemption Price, Percentage			100.00%
Senior Notes 3.60% | Debt Instrument, Redemption, Period One | Base Rate
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate			0.25%
Senior Notes 3.60% | Debt Instrument, Redemption, Period Two
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			Jun. 1, 2025
Debt Instrument, Redemption Period, End Date			Sep. 1, 2025
Debt Instrument, Redemption Price, Percentage			100.00%
Medium Term Notes 6.87%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.87%
Debt Instrument, Maturity Date			Oct. 6, 2023
Medium Term Notes 6.87% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 45,000,000	45,000,000
Unamortized Debt Issuance Expense			(115,000)	(129,000)
Long-term debt, net including current maturities			44,885,000	44,871,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 45,000,000	45,000,000
Medium Term Notes 8.45%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.45%
Debt Instrument, Maturity Date			Sep. 19, 2024
Medium Term Notes 8.45% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 40,000,000	40,000,000
Unamortized Debt Issuance Expense			(115,000)	(127,000)
Long-term debt, net including current maturities			39,885,000	39,873,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 40,000,000	40,000,000
Medium Term Notes 7.40%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.40%
Debt Instrument, Maturity Date			Oct. 3, 2025
Medium Term Notes 7.40% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 55,000,000	55,000,000
Unamortized Debt Issuance Expense			(171,000)	(189,000)
Long-term debt, net including current maturities			54,829,000	54,811,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 55,000,000	55,000,000
Medium Term Notes 7.50%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.50%
Debt Instrument, Maturity Date			Oct. 9, 2026
Medium Term Notes 7.50% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 40,000,000	40,000,000
Unamortized Debt Issuance Expense			(126,000)	(138,000)
Long-term debt, net including current maturities			39,874,000	39,862,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 40,000,000	40,000,000
Medium Term Notes 7.95%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.95%
Debt Instrument, Maturity Date			Sep. 14, 2029
Medium Term Notes 7.95% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 60,000,000	60,000,000
Unamortized Debt Issuance Expense			(273,000)	(292,000)
Long-term debt, net including current maturities			59,727,000	59,708,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt			$ 60,000,000	60,000,000
Medium Term Notes 6.00%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.00%
Debt Instrument, Maturity Date			Dec. 19, 2033
Medium Term Notes 6.00% | New Accounting Pronouncement, Early Adoption, Effect | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal			$ 100,000,000	100,000,000
Unamortized Debt Issuance Expense			(720,000)	(760,000)
Long-term debt, net including current maturities			99,280,000	99,240,000
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)	Dec. 14, 2015USD ($)	Oct. 31, 2015USD ($)	Oct. 31, 2014USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 850,000,000
Short-term debt		$ 340,000,000	$ 355,000,000
Ratio of Indebtedness to Net Capital		0.57
Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 850,000,000
Line of Credit Facility, Expiration Date		Oct. 1, 2017
Line of Credit Facility, Frequency of Commitment Fee Payment		annual
Line of Credit Facility, Commitment Fee Description		$35,000 plus 8.5 basis
Line of Credit Facility, Commitment Fee Amount		$ 35,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.085%
Line of Credit Facility, Interest Rate Description		30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points
Minimum Amount Outstanding During Period		$ 0
Maximum Amount Outstanding During Period		$ 0
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 57%
Debt Covenant Total Debt To Total Capital Ratio		70.00%
Ratio of Indebtedness to Net Capital		0.57
Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 10,000,000	10,000,000
Letters of Credit Outstanding, Amount		1,600,000	$ 1,800,000
Commercial Paper
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
Maximum Number Of Possible Days Outstanding For Commercial Paper Program		397 days
Short-term Debt, Weighted Average Interest Rate		0.22%	0.17%
Minimum Amount Outstanding During Period		$ 230,000,000
Maximum Amount Outstanding During Period		$ 580,000,000
Commercial Paper | Minimum
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity		7 days
Line of Credit Facility, Interest Rate During Period		0.15%
Commercial Paper | Maximum
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity		14 days
Line of Credit Facility, Interest Rate During Period		0.30%
Commercial Paper | Weighted Average
Line of Credit Facility [Line Items]
Line of Credit Facility, Interest Rate During Period		0.21%
Base Rate | Commercial Paper
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate		0.05%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Minimum
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate		0.75%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Maximum
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate		1.25%
Subsequent Event
Line of Credit Facility [Line Items]
Line of Credit Facility, Description	On December 14, 2015, we entered into an agreement with the lenders under our existing $850 million five-year revolving syndicated credit facility to amend and extend the facility at substantially similar terms to our existing facility. The amended facility extended the maturity of our facility to December 14, 2020. The amended facility expressly permits the Acquisition by Duke Energy. The CP program will continue to be backstopped by the new credit facility.
Subsequent Event | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 850,000,000
Line of Credit Facility, Expiration Date	Dec. 14, 2020
Number Days Outstanding From Issuance Until Maturity	5 years

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($)	Oct. 29, 2015	Sep. 15, 2015	Dec. 16, 2013	Feb. 19, 2013	Feb. 04, 2013	Jan. 29, 2013	Jul. 30, 2015	Apr. 24, 2015	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Jan. 31, 2015	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Jan. 31, 2013	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013	Jan. 07, 2015	Mar. 06, 2009	Dec. 16, 2005	Sep. 30, 2004
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance									1,136,000									1,136,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Beginning Balance												78,531,000				76,099,000	72,250,000	78,531,000	76,099,000	72,250,000
Common Stock, Value, Issued, Beginning Balance												$ 636,835,000				$ 561,644,000	$ 442,461,000	$ 636,835,000	$ 561,644,000	$ 442,461,000
Issued to participants in the Employee Stock Purchase Plan (ESPP) (in shares)																		31,000	34,000	33,000
Issued to participants in the Employee Stock Purchase Plan (ESPP)																		$ 1,239,000	$ 1,143,000	$ 1,056,000
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) (in shares)																		669,000	698,000	720,000
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)																		$ 24,679,000	$ 23,443,000	$ 22,791,000
Issued to participants in the Incentive Compensation Plan (ICP) (in shares)																		130,000	100,000	96,000
Issued to participants in the Incentive Compensation Plan (ICP)																		$ 4,964,000	$ 3,315,000	$ 3,065,000
Issuance of commons stock shares					3,000,000													1,522,000	1,600,000	3,000,000
Issuance of common stock, net																		$ 53,702,000	$ 47,290,000	$ 92,640,000
Expenses from Issuance of Common Stock																	$ (369,000)	$ (382,000)	$ (12,000)	$ (369,000)
Common Stock, Shares, Outstanding, Ending Balance									80,883,000				78,531,000					80,883,000	78,531,000	76,099,000
Common Stock, Value, Issued, Ending Balance									$ 721,419,000				$ 636,835,000					$ 721,419,000	$ 636,835,000	$ 561,644,000
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated OCIL beginning balance, net of tax												(237,000)				(284,000)		(237,000)	(284,000)
Total other comprehensive income (loss)																		(618,000)	47,000	21,000
Accumulated OCIL ending balance, net of tax									(855,000)				(237,000)					$ (855,000)	(237,000)	(284,000)
ATM Sales Agreement Amount Instant																					$ 170,000,000
ATM Sales Agreement Commission Percentage																		1.50%
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from equity method investments																		$ (34,461,000)	(32,753,000)	(26,056,000)
Income taxes																		13,288,000	11,642,000	8,612,000
Net Income									$ 14,109,000	$ 8,260,000	$ (66,402,000)	$ (92,978,000)	$ 8,967,000	$ 7,344,000	$ (62,540,000)	$ (97,572,000)		$ (137,011,000)	$ (143,801,000)	$ (134,417,000)
Forward Contract Indexed to Issuer's Equity [Line Items]
Common Stock Issued, Shares					3,000,000													1,522,000	1,600,000	3,000,000
Common Stock Issued, Value					$ 92,600,000													$ 84,966,000	$ 75,203,000	$ 119,552,000
Maximum Number Of Shares To Be Purchased						4,600,000
Shares Issued, Price Per Share					$ 32
Underwriter Discount					1.12
Net Settlement Price Per Share					$ 30.88
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives																		Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net settle for all or a portion of our obligation under the agreements
Forward Contract Indexed to Issuer's Equity, Classification																		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
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income																		$ 983,000	$ (308,000)
Employee Stock Purchase Plan
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance									145,000									145,000
Dividend Reinvestment Plan
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance									171,000									171,000
Stock Compensation Plan
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance									820,000									820,000
Common Stock Open Market Purchase Program
Class of Stock [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased																							6,000,000	3,000,000
ASR Program
Class of Stock [Line Items]
Additional Authorized Common Stock Repurchases Shares																							4,000,000
Common Stock Open Market Purchase Program and ASR Program
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
Forward Sales Agreement Merrill
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		114,500						612,000
Forward Contract Indexed to Issuer's Equity, Weighted Average Per Share		$ 36.58						$ 36.83
Initial Forward Price Per Share		$ 36.03						$ 36.28
Forward Sales Agreement JP Morgan
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares							795,529
Forward Contract Indexed to Issuer's Equity, Weighted Average Per Share							$ 36.42
Initial Forward Price Per Share							$ 35.87
Combined Forward Sale Agreements
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of commons stock shares	1,500,000		1,600,000
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares					1,600,000
Forward Contract Indexed to Issuer's Equity, Settlement Date																		Oct. 29, 2015	Dec. 16, 2013
Common Stock Issued, Shares	1,500,000		1,600,000
Common Stock Issued, Value	$ 54,100,000		$ 47,300,000
Net Settlement Price Per Share			$ 30.88
Forward Sale Agreement
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares					1,000,000
Additional Forward Sale Agreement
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares Option To Purchase Exercised By Underwriters				600,000
Additional Forward Sale Agreement | Maximum
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Indexed Shares					600,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax																		$ (1,601,000)	$ 355,000
Amounts reclassified, net of tax																		1,018,000	(284,000)
Total other comprehensive income (loss)																		(583,000)	71,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from equity method investments																		1,670,000	(461,000)
Income taxes																		(652,000)	177,000
Net Income																		1,018,000	(284,000)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Total other comprehensive income (loss)																		(35,000)	(24,000)
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from equity method investments																		(58,000)	(40,000)
Income taxes																		23,000	16,000
Net Income																		$ (35,000)	$ (24,000)

Financial Instruments & Relat50

Financial Instruments & Related Fair Value (Details) MMBTU in Millions	12 Months Ended
	Oct. 31, 2015USD ($)MMBTU	Oct. 31, 2014USD ($)MMBTU
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Options Total Coverage | MMBTU	34.7	29.2
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]
Marketable Securities	4,902,000	3,941,000
Long-term debt, principal	1,575,000,000	1,425,000,000
Current Assets, Gas purchase derivative assets	1,343,000	4,898,000
Amount of Gain (Loss) Recognized on Derivative Instruments	(4,423,000)	6,162,000
Amount Of Gain (Loss) Deferred Under PGA Procedures	$ (4,423,000)	6,162,000
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 have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. 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.
Fair Value, Measurements, Recurring
Assets [Abstract]
Derivative Asset	$ 1,343,000	4,898,000
Total Recurring Fair Value Assets	6,245,000	8,839,000
Money Market Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	516,000	469,000
Equity Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	4,386,000	3,472,000
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring
Assets [Abstract]
Derivative Asset	1,343,000	4,898,000
Total Recurring Fair Value Assets	6,245,000	8,839,000
Fair Value, Inputs, Level 1 | Money Market Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	516,000	469,000
Fair Value, Inputs, Level 1 | Equity Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	4,386,000	3,472,000
Fair Value, Inputs, Level 2
Assets [Abstract]
Long-term debt, fair value	1,720,586,000	1,617,453,000
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring
Assets [Abstract]
Total Recurring Fair Value Assets	0	0
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring
Assets [Abstract]
Total Recurring Fair Value Assets	0	$ 0
Accounts Receivable
Concentration Risk [Line Items]
Concentration Risk Amount	$ 2,900,000
Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration Risk, Percentage	5.00%

Commitments & Contingent Liab51

Commitments & Contingent Liabilities (Details) $ in Thousands	12 Months Ended
	Oct. 31, 2015USD ($)regulatory_commissionsites	Oct. 31, 2014USD ($)	Oct. 31, 2013USD ($)	Dec. 31, 2013USD ($)	Mar. 01, 2012USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating lease payments	$ 5,024	$ 4,701	$ 4,729
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	5,052
Operating Leases, Future Minimum Payments, Due in Two Years	4,706
Operating Leases, Future Minimum Payments, Due in Three Years	4,609
Operating Leases, Future Minimum Payments, Due in Four Years	4,433
Operating Leases, Future Minimum Payments, Due in Five Years	4,477
Operating Leases, Future Minimum Payments, Due Thereafter	24,413
Operating Leases Future Minimum Payments Due	47,690
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	300,198
Unrecorded Unconditional Purchase Obligation, Due within Two Years	255,394
Unrecorded Unconditional Purchase Obligation, Due within Three Years	213,966
Unrecorded Unconditional Purchase Obligation, Due within Four Years	202,438
Unrecorded Unconditional Purchase Obligation, Due within Five Years	184,159
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,224,031
Unrecorded Unconditional Purchase Obligation	$ 2,380,186
Number Of Regulatory Commissions | regulatory_commission	3
MGP Sites Under Settlement | sites	9
Site Contingency, Unasserted Claims	0
Site Contingency [Line Items]
Undiscounted Environmental Liability	$ 1,200
Regulatory Assets [Line Items]
Regulatory Assets	207,662	202,118
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets	6,600
Pipeline And Storage Capacity Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	178,594
Unrecorded Unconditional Purchase Obligation, Due within Two Years	163,806
Unrecorded Unconditional Purchase Obligation, Due within Three Years	143,728
Unrecorded Unconditional Purchase Obligation, Due within Four Years	132,259
Unrecorded Unconditional Purchase Obligation, Due within Five Years	114,400
Unrecorded Unconditional Purchase Obligation, Due after Five Years	516,333
Unrecorded Unconditional Purchase Obligation	1,249,120
Gas Supply Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	4,577
Unrecorded Unconditional Purchase Obligation, Due within Two Years	165
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	4,742
Gas Supply Purchase Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	65,286
Unrecorded Unconditional Purchase Obligation, Due within Two Years	89,784
Unrecorded Unconditional Purchase Obligation, Due within Three Years	69,569
Unrecorded Unconditional Purchase Obligation, Due within Four Years	69,569
Unrecorded Unconditional Purchase Obligation, Due within Five Years	69,759
Unrecorded Unconditional Purchase Obligation, Due after Five Years	707,698
Unrecorded Unconditional Purchase Obligation	1,071,665
Telecommunications And Technology Outsourcing Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	6,164
Unrecorded Unconditional Purchase Obligation, Due within Two Years	1,639
Unrecorded Unconditional Purchase Obligation, Due within Three Years	669
Unrecorded Unconditional Purchase Obligation, Due within Four Years	610
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	9,082
Others
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	45,577
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	$ 45,577
Tennessee Regulatory Authority | Environmental costs | General Rate Application Settlement 2012
Regulatory Assets [Line Items]
Regulatory Assets					$ 2,000
Regulatory Asset, Amortization Period	8 years
North Carolina Utilities Commission | Environmental costs | General Rate Application Settlement 2013
Regulatory Assets [Line Items]
Regulatory Assets				$ 6,300
Regulatory Asset, Amortization Period	5 years
Public Service Commission of South Carolina | Environmental costs | Settlement With Office of Regulatory Staff October 2014
Regulatory Assets [Line Items]
Regulatory Assets		$ 100
Regulatory Asset, Amortization Period	1 year
Letter of Credit
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,600
Surety Bond
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	6,600
Manufactured Gas Plant Sites
Site Contingency [Line Items]
Undiscounted Environmental Liability	1,100
Environmental Costs Incurred to Date	2,200
Huntersville NC LNG Site
Site Contingency [Line Items]
Undiscounted Environmental Liability	100
Environmental Costs Incurred to Date	$ 4,800

Commitments & Contingent Liab52

Commitments & Contingent Liabilities - Long Term Contracts (Details) - Maximum	12 Months Ended
	Oct. 31, 2015
Pipeline And Storage Capacity Contracts
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	20 years
Gas Supply Contracts
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	2 years
Gas Supply Purchase Commitments
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	15 years
Telecommunications And Technology Outsourcing Contracts
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, 2015	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2015	Oct. 31, 2014
Defined Contribution Plan Disclosure [Line Items]
Deferred Compensation Current Liability				$ 236,000	$ 214,000
Deferred Compensation Noncurrent Liability				5,089,000	4,248,000
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Measurement Date	October 31
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Noncurrent assets				17,770,000	33,757,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Regulatory asset				$ (207,662,000)	(202,118,000)
Defined Benefit Plan Actuarial Gains And Losses Amortization Corridor	5 years
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Gains And Losses Amortized In Excess Of Percentage				10.00%
Money Purchase Pension Plan
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plans Estimated Future Employer Contributions In Next Fiscal Year	$ 1,650,000
Money Purchase Pension Plan | Pension Plan
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%
Pension Contributions	$ 1,400,000	$ 900,000	$ 700,000
Plan Vesting Period Defined Contribution Plan	3 years
Voluntary Deferral Plan | Other Postretirement Benefit Plan
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution to Plan - deferred compensation	$ 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 | Other Postretirement Benefit Plan
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution Percentage Above IRS Limit	13.00%
Employer Contribution to Plan - deferred compensation	$ 548,000	524,000
Plan Vesting Period Defined Contribution Plan	5 years
Plan 401 K | Other Postretirement Benefit Plan
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%
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%
Employer Contribution to Plan	$ 6,584,000	6,134,000	5,688,000
Qualified Pension
Defined Benefit Plan Disclosure [Line Items]
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, Target Plan Asset Allocations	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 336,443,000	300,661,000	300,661,000	$ 329,307,000	$ 336,443,000
Defined Benefit Plan, Actual Plan Asset Allocations				100.00%	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				$ 263,120,000	$ 252,706,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	302,686,000	272,403,000
Service cost	11,403,000	10,865,000	12,005,000
Interest cost	12,018,000	11,781,000	9,946,000
Plan amendments	0	0
Actuarial (gain) loss	3,524,000	23,646,000
Participant contributions	0	0
Administrative expenses	(590,000)	(465,000)
Benefit payments	(17,504,000)	(15,544,000)
Obligation at end of year	311,537,000	302,686,000	272,403,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	336,443,000	300,661,000
Actual return on plan assets	958,000	31,791,000
Employer contributions	10,000,000	20,000,000
Participant contributions	0	0
Administrative expenses	(590,000)	(465,000)
Benefit payments	(17,504,000)	(15,544,000)
Fair value at end of year	329,307,000	336,443,000	300,661,000
Funded status at year end - (under) over				17,770,000	33,757,000
Noncurrent assets				17,770,000	33,757,000
Current liabilities				0	0
Noncurrent liabilities				0	0
Net amount recognized				17,770,000	33,757,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized prior service (cost) credit	12,848,000	15,046,000
Unrecognized actuarial loss	(120,541,000)	(103,038,000)
Regulatory asset				$ (107,693,000)	$ (87,992,000)
Cumulative employer contributions in excess of cost	125,463,000	121,749,000
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate				4.34%	4.13%
Rate Of Compensation Increase				4.07%	3.68%
Net Periodic Benefit Cost [Abstract]
Service cost	11,403,000	10,865,000	12,005,000
Interest cost	12,018,000	11,781,000	9,946,000
Expected return on plan assets	(23,614,000)	(22,530,000)	(21,105,000)
Transition obligation	0	0	0
Amortization of prior service cost (credit)	(2,198,000)	(2,198,000)	(2,198,000)
Amortization of net loss	8,676,000	7,685,000	11,202,000
Net periodic benefit cost	6,285,000	5,603,000	9,850,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	(2,198,000)
Amortization of unrecognized actuarial loss	8,164,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost (credit)	0	0	0
Net loss (gain)	26,179,000	14,385,000	(30,094,000)
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	0
Amortization of net loss	(8,676,000)	(7,685,000)	(11,202,000)
Amortization of prior service (cost) credit	2,198,000	2,198,000	2,198,000
Total recognized in regulatory asset (liability)	19,701,000	8,898,000	(39,098,000)
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	$ 25,986,000	$ 14,501,000	$ (29,248,000)
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.13%	4.55%	3.51%
Expected Long Term Rate Of Return On Plan Assets	7.50%	7.75%	8.00%
Rate Of Compensation Increase	3.68%	3.72%	3.76%
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months				$ 28,147,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Two				19,911,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Three				20,413,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four				21,348,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Five				21,829,000
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter				$ 114,267,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 336,443,000	$ 300,661,000
Actual return on plan assets:
Fair value at end of year	$ 329,307,000	336,443,000	$ 300,661,000
Qualified Pension | Minimum
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age For Defined Benefit Plan	21 years
Qualified Pension | Derivative | Maximum
Defined Benefit Plan, Information about Plan Assets [Abstract]
Investment Limitation Percentage				10.00%
Qualified Pension | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 78,074,000	78,074,000		$ 84,135,000	$ 78,074,000
Defined Benefit Plan, Actual Plan Asset Allocations				46.00%	45.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	78,074,000
Fair value at end of year	84,135,000	78,074,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	78,074,000
Actual return on plan assets:
Fair value at end of year	$ 84,135,000	78,074,000
Qualified Pension | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	35.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 51,266,000	51,266,000		$ 44,738,000	$ 51,266,000
Defined Benefit Plan, Actual Plan Asset Allocations				34.00%	31.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	51,266,000
Fair value at end of year	44,738,000	51,266,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	51,266,000
Actual return on plan assets:
Fair value at end of year	$ 44,738,000	51,266,000
Qualified Pension | Real estate
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%
Qualified Pension | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 28,367,000	28,367,000		$ 2,871,000	$ 28,367,000
Defined Benefit Plan, Actual Plan Asset Allocations				1.00%	8.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	28,367,000
Fair value at end of year	2,871,000	28,367,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	28,367,000
Actual return on plan assets:
Fair value at end of year	$ 2,871,000	28,367,000
Qualified Pension | Other investments
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	15.00%
Defined Benefit Plan, Actual Plan Asset Allocations				14.00%	11.00%
Qualified Pension | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 102,551,000	102,551,000		$ 121,743,000	$ 102,551,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	102,551,000
Fair value at end of year	121,743,000	102,551,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	102,551,000
Actual return on plan assets:
Fair value at end of year	121,743,000	102,551,000
Qualified Pension | Common trust fund
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	22,877,000	22,877,000		23,571,000	22,877,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	22,877,000
Fair value at end of year	$ 23,571,000	22,877,000
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	$ 22,877,000
Actual return on plan assets:
Fair value at end of year	$ 23,571,000	22,877,000
Qualified Pension | Private equity fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.50%
Defined Benefit Plan, Fair Value of Plan Assets	$ 7,158,000	7,158,000		8,344,000	7,158,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	7,158,000
Fair value at end of year	$ 8,344,000	7,158,000
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				4,000,000
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	$ 7,158,000
Actual return on plan assets:
Fair value at end of year	$ 8,344,000	7,158,000
Qualified Pension | Private equity fund of funds | Minimum
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 | Private equity fund of funds | Maximum
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 | Hedge fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 19,829,000	19,829,000		19,809,000	19,829,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	19,829,000
Fair value at end of year	$ 19,809,000	19,829,000
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, 2015.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 19,829,000
Actual return on plan assets:
Fair value at end of year	19,809,000	19,829,000
Qualified Pension | Commodities fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10,134,000	10,134,000		7,688,000	10,134,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	10,134,000
Fair value at end of year	$ 7,688,000	10,134,000
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	$ 10,134,000
Actual return on plan assets:
Fair value at end of year	7,688,000	10,134,000
Qualified Pension | High yield debt (bank loans)
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16,187,000	16,187,000		16,408,000	16,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	16,187,000
Fair value at end of year	$ 16,408,000	16,187,000
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
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 16,187,000
Actual return on plan assets:
Fair value at end of year	16,408,000	16,187,000
Qualified Pension | Fair Value, Inputs, Level 1
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	133,748,000	133,748,000		126,373,000	133,748,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	133,748,000
Fair value at end of year	126,373,000	133,748,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	133,748,000
Actual return on plan assets:
Fair value at end of year	126,373,000	133,748,000
Qualified Pension | Fair Value, Inputs, Level 1 | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	48,000	48,000		0	48,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	48,000
Fair value at end of year	0	48,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	48,000
Actual return on plan assets:
Fair value at end of year	0	48,000
Qualified Pension | Fair Value, Inputs, Level 1 | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	51,266,000	51,266,000		44,738,000	51,266,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	51,266,000
Fair value at end of year	44,738,000	51,266,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	51,266,000
Actual return on plan assets:
Fair value at end of year	44,738,000	51,266,000
Qualified Pension | Fair Value, Inputs, Level 1 | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	27,932,000	27,932,000		2,782,000	27,932,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,932,000
Fair value at end of year	2,782,000	27,932,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,932,000
Actual return on plan assets:
Fair value at end of year	2,782,000	27,932,000
Qualified Pension | Fair Value, Inputs, Level 1 | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	54,502,000	54,502,000		78,853,000	54,502,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	54,502,000
Fair value at end of year	78,853,000	54,502,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	54,502,000
Actual return on plan assets:
Fair value at end of year	78,853,000	54,502,000
Qualified Pension | Fair Value, Inputs, Level 1 | Common trust fund
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 1 | Private equity fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 2
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	149,387,000	149,387,000		150,685,000	149,387,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	149,387,000
Fair value at end of year	150,685,000	149,387,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	149,387,000
Actual return on plan assets:
Fair value at end of year	150,685,000	149,387,000
Qualified Pension | Fair Value, Inputs, Level 2 | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	78,026,000	78,026,000		84,135,000	78,026,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	78,026,000
Fair value at end of year	84,135,000	78,026,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	78,026,000
Actual return on plan assets:
Fair value at end of year	84,135,000	78,026,000
Qualified Pension | Fair Value, Inputs, Level 2 | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 2 | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	435,000	435,000		89,000	435,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	435,000
Fair value at end of year	89,000	435,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	435,000
Actual return on plan assets:
Fair value at end of year	89,000	435,000
Qualified Pension | Fair Value, Inputs, Level 2 | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	48,049,000	48,049,000		42,890,000	48,049,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	48,049,000
Fair value at end of year	42,890,000	48,049,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	48,049,000
Actual return on plan assets:
Fair value at end of year	42,890,000	48,049,000
Qualified Pension | Fair Value, Inputs, Level 2 | Common trust fund
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	22,877,000	22,877,000		23,571,000	22,877,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	22,877,000
Fair value at end of year	23,571,000	22,877,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	22,877,000
Actual return on plan assets:
Fair value at end of year	23,571,000	22,877,000
Qualified Pension | Fair Value, Inputs, Level 2 | Private equity fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000	7,158,000		8,344,000	7,158,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	7,158,000
Fair value at end of year	8,344,000	7,158,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	7,158,000
Actual return on plan assets:
Fair value at end of year	8,344,000	7,158,000
Qualified Pension | Fair Value, Inputs, Level 3 | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Common trust fund
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Private equity fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000	4,659,000	4,659,000	8,344,000	7,158,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	7,158,000	4,659,000
Fair value at end of year	8,344,000	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	7,158,000	4,659,000
Actual return on plan assets:
Relating to assets still held at the reporting date	413,000	1,031,000
Relating to assets sold during the period	618,000	113,000
Purchases, sales and settlements (net)	155,000	1,355,000
Transfer in/out of Level 3	0	0
Fair value at end of year	8,344,000	7,158,000	4,659,000
Non Qualified Pension
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0	0	0
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	520,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End				5,527,000	5,925,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	5,925,000	4,736,000
Service cost	0	0	0
Interest cost	209,000	200,000	157,000
Plan amendments	0	485,000
Actuarial (gain) loss	(100,000)	956,000
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	(507,000)	(452,000)
Obligation at end of year	5,527,000	5,925,000	4,736,000
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	507,000	452,000
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	(507,000)	(452,000)
Fair value at end of year	0	0	0
Funded status at year end - (under) over				(5,527,000)	(5,925,000)
Noncurrent assets				0	0
Current liabilities				(520,000)	(521,000)
Noncurrent liabilities				(5,007,000)	(5,404,000)
Net amount recognized				(5,527,000)	(5,925,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized prior service (cost) credit	(208,000)	(439,000)
Unrecognized actuarial loss	(1,560,000)	(1,745,000)
Regulatory asset				$ (1,768,000)	$ (2,184,000)
Cumulative employer contributions in excess of cost	(3,759,000)	(3,741,000)
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate				3.85%	3.69%
Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0
Interest cost	209,000	200,000	157,000
Expected return on plan assets	0	0	0
Transition obligation	0	0	0
Amortization of prior service cost (credit)	231,000	243,000	81,000
Amortization of net loss	85,000	31,000	161,000
Net periodic benefit cost	525,000	474,000	399,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	208,000
Amortization of unrecognized actuarial loss	81,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost (credit)	0	485,000	0
Net loss (gain)	(100,000)	956,000	(540,000)
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	0
Amortization of net loss	(85,000)	(31,000)	(161,000)
Amortization of prior service (cost) credit	(231,000)	(243,000)	(81,000)
Total recognized in regulatory asset (liability)	(416,000)	1,167,000	(782,000)
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	$ 109,000	$ 1,641,000	$ (383,000)
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	3.69%	3.98%	2.95%
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months				$ 520,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Two				504,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Three				482,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four				510,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Five				491,000
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter				2,100,000
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
Defined Benefit Plan Disclosure [Line Items]
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, Target Plan Asset Allocations	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 27,747,000	25,961,000	25,961,000	$ 27,546,000	$ 27,747,000
Defined Benefit Plan, Actual Plan Asset Allocations				100.00%	100.00%
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	1,300,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	37,817,000	33,678,000
Service cost	1,182,000	1,109,000	1,327,000
Interest cost	1,475,000	1,448,000	1,130,000
Plan amendments	(1,877,000)	0
Actuarial (gain) loss	1,697,000	3,734,000
Participant contributions	611,000	805,000
Administrative expenses	0	0
Benefit payments	(3,348,000)	(2,957,000)
Obligation at end of year	37,557,000	37,817,000	33,678,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,747,000	25,961,000
Actual return on plan assets	315,000	1,874,000
Employer contributions	2,221,000	2,064,000
Participant contributions	611,000	805,000
Administrative expenses	0	0
Benefit payments	(3,348,000)	(2,957,000)
Fair value at end of year	27,546,000	27,747,000	25,961,000
Funded status at year end - (under) over				$ (10,011,000)	$ (10,070,000)
Noncurrent assets				0	0
Current liabilities				0	0
Noncurrent liabilities				(10,011,000)	(10,070,000)
Net amount recognized				(10,011,000)	(10,070,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized prior service (cost) credit	1,877,000	0
Unrecognized actuarial loss	(7,185,000)	(3,995,000)
Regulatory asset				$ (5,308,000)	$ (3,995,000)
Cumulative employer contributions in excess of cost	(4,703,000)	(6,075,000)
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate				4.38%	4.03%
Net Periodic Benefit Cost [Abstract]
Service cost	1,182,000	1,109,000	1,327,000
Interest cost	1,475,000	1,448,000	1,130,000
Expected return on plan assets	(1,837,000)	(1,782,000)	(1,663,000)
Transition obligation	0	0	667,000
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss	29,000	0	0
Net periodic benefit cost	849,000	775,000	1,461,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	(332,000)
Amortization of unrecognized actuarial loss	459,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost (credit)	(1,877,000)	0	0
Net loss (gain)	3,219,000	3,641,000	(2,278,000)
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	(667,000)
Amortization of net loss	(29,000)	0	0
Amortization of prior service (cost) credit	0	0	0
Total recognized in regulatory asset (liability)	1,313,000	3,641,000	(2,945,000)
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	$ 2,162,000	$ 4,416,000	$ (1,484,000)
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.03%	4.44%	3.34%
Expected Long Term Rate Of Return On Plan Assets	7.50%	7.75%	8.00%
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months				$ 1,987,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Two				2,145,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Three				2,301,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four				2,421,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Five				2,494,000
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter				$ 13,379,000
Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.40%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate					2,027
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	$ 34,000
Effect of One Percentage Point Decrease on Service and Interest Cost Components	(35,000)
Effect Of One Percentage Point Increase on Postretirement Benefit Obligation	0
Effect of One Percentage Point Decrease on Postretirement Benefit Obligation	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,747,000	$ 25,961,000
Actual return on plan assets:
Fair value at end of year	$ 27,546,000	27,747,000	$ 25,961,000
Other Postretirement Benefit Plan | Minimum
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	45 years
Other Postretirement Benefit Plan | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations				47.00%	44.00%
Other Postretirement Benefit Plan | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	47.00%
Defined Benefit Plan, Actual Plan Asset Allocations				44.00%	42.00%
Other Postretirement Benefit Plan | Real estate
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%
Other Postretirement Benefit Plan | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,590,000	2,590,000		$ 1,164,000	$ 2,590,000
Defined Benefit Plan, Actual Plan Asset Allocations				4.00%	9.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	2,590,000
Fair value at end of year	1,164,000	2,590,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	2,590,000
Actual return on plan assets:
Fair value at end of year	$ 1,164,000	2,590,000
Other Postretirement Benefit Plan | High yield fixed income
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Other Postretirement Benefit Plan | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 25,157,000	25,157,000		$ 26,382,000	$ 25,157,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	25,157,000
Fair value at end of year	26,382,000	25,157,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	25,157,000
Actual return on plan assets:
Fair value at end of year	26,382,000	25,157,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	27,747,000	27,747,000		27,546,000	27,747,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,747,000
Fair value at end of year	27,546,000	27,747,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,747,000
Actual return on plan assets:
Fair value at end of year	27,546,000	27,747,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,590,000	2,590,000		1,164,000	2,590,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	2,590,000
Fair value at end of year	1,164,000	2,590,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	2,590,000
Actual return on plan assets:
Fair value at end of year	1,164,000	2,590,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	25,157,000	25,157,000		26,382,000	25,157,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	25,157,000
Fair value at end of year	26,382,000	25,157,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	25,157,000
Actual return on plan assets:
Fair value at end of year	26,382,000	25,157,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | Mutual funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	$ 0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Supplemental Executive Retirement Plans
Defined Benefit Plan, Information about Plan Assets [Abstract]
Assets for Participant Benefits				$ 0
Officers and Director-Level Employees Life Insurance
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	30,000	32,000	28,000
Certain Officers Vice President And Above Life Insurance
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Premiums Paid By Employer	$ 35,000	$ 30,000	$ 27,000
NCNG SERP
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate				3.78%
Directors SERP
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate				3.91%
Piedmont SERP
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate				3.17%

Employee Share Based Plans (Det

Employee Share Based Plans (Details) $ / shares in Units, $ in Thousands	Dec. 15, 2015USD ($)shares	Dec. 15, 2014USD ($)shares	Dec. 31, 2011shares	Oct. 31, 2015USD ($)Integershares	Oct. 31, 2014USD ($)shares	Oct. 31, 2013USD ($)shares	Dec. 14, 2015$ / shares	Oct. 24, 2015$ / shares	Dec. 12, 2014$ / shares
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 | shares				130,000	100,000	96,000
Business Acquisition, Share Price | $ / shares								$ 60
Compensation expense				$ 14,173	$ 8,496	$ 4,526
Tax Benefit				3,966	2,476	$ 1,538
Liability				22,037	$ 15,130
Incentive Compensation Plan Expected Payout In One Year				10,866
Incentive Compensation Plan Expected Payout In Two Years				8,179
Incentive Compensation Plan Expected Payout In Three Years				$ 2,992
Purchase Price of Common Stock, Percent				95.00%
Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Incentive Compensation Plan Awards | Integer				3
Stock Compensation Plan | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Price | $ / shares							$ 56.85
Share-based Compensation Arrangement by Share-based Payment Award, Description	The Merger Agreement provides for the conversion of the shares subject to the RSUs and ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the RSUs for our President and CEO (accelerated RSUs) and the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at his and their elections to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration of the vesting and payment of these awards will mitigate the effects of Section 280G of the Tax Code, including increasing the deductibility of such payments for the Company. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, and the RSUs, per the election of our President and CEO, occurred on December 15, 2015. In connection with the election to accelerate the ICP awards and the RSUs, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of common stock resulting from the reinvestment of dividends paid with respect to these shares of common stock that are required to be reinvested in additional shares of common stock, to the extent the shares of common stock would not otherwise have been earned or payable absent the acceleration. Under the share repayment agreements, the shares of common stock delivered to the participants, including dividends paid by the Company and reinvested as discussed above, may not be transferred or encumbered until such shares of common stock are no longer subject to repayment under the applicable repayment agreement. The restricted shares of common stock and dividends earned on those shares of common stock are subject to full or partial cancellation if the Acquisition is not consummated or the participant leaves the Company prior to consummation of the Acquisition. The participants otherwise have all rights of shareholders with respect to the restricted shares of common stock. The accelerated ICP awards and the accelerated RSUs were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes. The gross value of the shares issued for the accelerated ICP awards was $17.4 million, or $9.2 million net of federal and state tax withholdings. Under the accelerated RSUs, 19,554 restricted shares of our common stock were issued to our President and CEO, net of shares withheld for applicable federal and state income taxes. The gross value of the shares for the accelerated RSUs was $2.1 million, or $1.1 million net of federal and state tax withholdings.
Long Term Incentive Plan | Stock Compensation Plan | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Acceleration And Payout Election Rate	96.00%
Value of Incentive Compensation Plan Award Gross	$ 17,400
Value of Settlement of Employee Share Based Plan Awards, Net Of Tax	$ 9,200
Stock Issued During Period, Shares, Restricted Stock Award | shares	162,390
Long Term Incentive Plan | Stock Compensation Plan | EPS Performance
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units				37.50%
Long Term Incentive Plan | Stock Compensation Plan | Annual Shareholder Return
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units				37.50%
Long Term Incentive Plan | Stock Compensation Plan | Return On Equity
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units				25.00%
Retention Stock Unit Award Eligible Officers | Stock Compensation Plan
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 Chief Executive Officer | Stock Compensation Plan
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 | shares			64,700
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period				5 years
Retention Stock Unit Award President And Chief Executive Officer | Stock Compensation Plan | Share-based Compensation Award, Tranche One
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%
Stock Award Vested, Shares, Gross | shares		14,461
Stock Issued During Period, Shares, Share-based Compensation | shares		7,231
Share Price | $ / shares									$ 37.89
Payments Related to Tax Withholding for Share-based Compensation		$ 300
Retention Stock Unit Award President And Chief Executive Officer | Stock Compensation Plan | Share-based Compensation Award, Tranche Two
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 Chief Executive Officer | Stock Compensation Plan | Share-based Compensation Award, Tranche Two | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Award Vested, Shares, Gross | shares	22,434
Stock Issued During Period, Shares, Share-based Compensation | shares	11,732
Share Price | $ / shares							$ 56.85
Payments Related to Tax Withholding for Share-based Compensation	$ 600
Share-based Compensation Arrangement by Share-based Payment Award, Description	The December 15, 2015 vesting covers 30% of the grant, including accrued dividends, for a total of 22,434 shares of our common stock. After withholdings of $.6 million for federal and state income taxes, our President and CEO received 11,732 shares of our common stock at the NYSE composite closing price on December 14, 2015 of $56.85 per share.
Retention Stock Unit Award President And Chief Executive Officer | Stock Compensation Plan | Share-based Compensation Award, Tranche Three
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%
Retention Stock Unit Award President And Chief Executive Officer | Stock Compensation Plan | Share-based Compensation Award, Tranche Three | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of Incentive Compensation Plan Award Gross	$ 2,100
Value of Settlement of Employee Share Based Plan Awards, Net Of Tax	$ 1,100
Stock Issued During Period, Shares, Restricted Stock Award | shares	19,554

Income Taxes Income Tax Expense

Income Taxes Income Tax Expense Components (Details) - USD ($) $ in Thousands	12 Months Ended
	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Amortization of investment tax credits	$ (167)	$ (209)	$ (267)
Federal Total	76,986	78,836	72,860
State Total	13,236	15,982	13,086
Regulated Operation
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)	(10,449)	(1,653)	(3,032)
Current State Tax Expense (Benefit)	(289)	950	919
Deferred Federal Income Tax Expense (Benefit)	75,644	70,654	67,885
Deferred State Income Tax Expense (Benefit)	12,195	13,434	11,829
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Amortization of investment tax credits	(167)	(209)	(267)
Federal Total	65,028	68,792	64,586
State Total	11,906	14,384	12,748
Unregulated Operation
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)	9,709	4,233	6,049
Current State Tax Expense (Benefit)	1,449	870	984
Deferred Federal Income Tax Expense (Benefit)	2,249	5,811	2,225
Deferred State Income Tax Expense (Benefit)	(119)	728	(646)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Federal Total	11,958	10,044	8,274
State Total	1,330	1,598	338
Domestic Tax Authority | NOL Carryforward 1
Income Tax Table Continuing Operations [Line Items]
Deferred Federal Income Tax Expense (Benefit)	64,300		$ 62,300
Domestic Tax Authority | Net Operating Loss Utilization
Income Tax Table Continuing Operations [Line Items]
Deferred Federal Income Tax Expense (Benefit)	$ 19,800	$ 28,600

Income Taxes Operating Loss Car

Income Taxes Operating Loss Carryforwards (Details) - USD ($) $ in Thousands	12 Months Ended
	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013
Operating Loss Carryforwards [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 343	$ 0	$ 0
Domestic Tax Authority | Internal Revenue Service (IRS)
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	$ 300
Deferred Tax Assets, Capital Loss Carryforwards	1,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	1,100
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	115,100	7,200
NOL Carryforward 1 | Domestic Tax Authority
Operating Loss Carryforwards [Line Items]
Net Operating Loss, Retroactive Impact	61,100
Deferred Federal Income Tax Expense (Benefit)	64,300		$ 62,300
NOL Carryforward 1 | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	219,700	97,000
NOL Carryforward 2 | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 5,900	$ 5,900
Capital Loss Carryforward | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2019
Minimum | State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2018
Minimum | NOL Carryforward 1 | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2033
Minimum | NOL Carryforward 2 | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2023
Maximum | State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2030
Maximum | NOL Carryforward 1 | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2034
Maximum | NOL Carryforward 2 | Domestic Tax Authority | Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2025

Income Taxes Income Tax Examina

Income Taxes Income Tax Examination (Details) - Internal Revenue Service (IRS)	12 Months Ended
	Oct. 31, 2015
Tax Year 2010
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2,010
Tax Year 2011
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2,011
Tax Year 2012
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2,012

Income Taxes (Details)

Income Taxes (Details)	12 Months Ended
	Oct. 31, 2015USD ($)	Oct. 31, 2014USD ($)	Oct. 31, 2013USD ($)	Oct. 31, 2015USD ($)	Jul. 31, 2015	Oct. 31, 2014USD ($)	Jul. 31, 2013Integer
NC Tax Law [Line Items]
State and Local Income Tax Expense (Benefit)	$ 13,236,000	$ 15,982,000	$ 13,086,000
Non Operating Income Tax Expense Benefit	13,288,000	11,642,000	8,612,000
Regulatory liabilities, Noncurrent				$ 590,301,000		$ 558,598,000
Regulatory liabilities, Total				603,668,000		604,829,000
Federal Income Tax Expense (Benefit), Continuing Operations	76,986,000	78,836,000	72,860,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal taxes at 35%	79,532,000	83,517,000	77,127,000
State income taxes, net of federal benefit	8,604,000	10,389,000	8,506,000
Amortization of investment tax credits	(167,000)	(209,000)	(267,000)
Other, net	2,253,000	1,121,000	580,000
Total	90,222,000	94,818,000	85,946,000
Deferred tax assets:
Benefit of loss carryforwards				84,025,000		39,532,000
Revenues and cost of gas				3,495,000		4,960,000
Employee benefits and compensation				22,134,000		16,547,000
Revenue requirement				26,088,000		20,320,000
Utility plant				7,481,000		5,631,000
Other				10,461,000		12,869,000
Total deferred tax assets				153,684,000		99,859,000
Valuation allowance	(505,000)	(505,000)	(505,000)	(848,000)		(505,000)
Total deferred tax assets, net				152,836,000		99,354,000
Deferred tax liabilities:
Utility Plant				849,835,000		724,172,000
Revenues and cost of gas				0		4,340,000
Equity Method Investments				44,778,000		42,998,000
Deferred costs				73,903,000		65,828,000
Other				13,543,000		18,065,000
Total deferred tax liabilities				982,059,000		855,403,000
Net Deferred Income Tax Liabilities				829,223,000		756,049,000
Valuation Allowance [Abstract]
Balance at beginning of year	505,000	505,000	505,000
Charged to income tax expense	343,000	0	0
Balance at end of year	848,000	$ 505,000	505,000
Unrecognized Tax Benefits				0		0
Tax Law 2013 | State and Local Jurisdiction | North Carolina
NC Tax Law [Line Items]
State and Local Income Tax Expense (Benefit)			$ (1,000,000)
Number Of Additional Rate Reductions | Integer							2
Rate Reduction Percentage							1.00%
Regulatory liabilities, Noncurrent						3,000,000
Tax Law 2013 | State and Local Jurisdiction | Tax Year 2013 | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate							6.90%
Tax Law 2013 | State and Local Jurisdiction | Tax Year 2014 | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate							6.00%
Tax Law 2013 | State and Local Jurisdiction | Tax Year 2015 | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate							5.00%
Tax Law 2015 | State and Local Jurisdiction | North Carolina
NC Tax Law [Line Items]
Increase (Decrease) in Deferred Income Taxes	17,500,000
State and Local Income Tax Expense (Benefit)	$ (500,000)
Rate Reduction Percentage					1.00%
Tax Law 2015 | State and Local Jurisdiction | Tax Year 2017 | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					4.00%
Deferred income taxes
NC Tax Law [Line Items]
Regulatory liabilities, Noncurrent				68,738,000		$ 51,930,000
Deferred income taxes | Tax Law 2013 and 2015 | State and Local Jurisdiction | North Carolina
NC Tax Law [Line Items]
Regulatory liabilities, Total				44,000,000
Deferred income taxes | Tax Law 2015 | State and Local Jurisdiction | North Carolina
NC Tax Law [Line Items]
Regulatory liabilities, Noncurrent				$ 17,000,000

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($)	Dec. 09, 2015	Jul. 01, 2013	Sep. 30, 2013	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2013	Jun. 30, 2013
Schedule of Equity Method Investments [Line Items]
Retained Earnings, Undistributed Earnings from Equity Method Investees				$ 0
Transportation or gas storage costs				29,494,000	$ 29,650,000	$ 29,575,000
Trade accounts payable				2,473,000	2,510,000
Capital contributions to or payments to acquire equity method investments				$ 29,723,000	37,642,000	41,348,000
Cardinal Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				21.49%
Transportation or gas storage costs				$ 8,763,000	8,825,000	$ 8,775,000
Trade accounts payable				$ 744,000	$ 747,000
Pipeline Subscription Capacity Percentage				100.00%
Pipeline Transportation Capacity Subscribed				53.00%
Summarized Financial Information Percentage				100.00%	100.00%	100.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets				$ 9,451,000	$ 8,856,000
Noncurrent assets				106,444,000	111,881,000
Current liabilities				1,228,000	1,468,000
Noncurrent liabilities				45,446,000	45,402,000
Revenues				16,629,000	16,705,000	$ 17,649,000
Gross profit				16,629,000	16,705,000	17,649,000
Income (loss) before income taxes				$ 7,742,000	8,042,000	9,361,000
Pine Needle Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				45.00%			40.00%
Transportation or gas storage costs				$ 11,441,000	11,364,000	$ 11,098,000
Trade accounts payable				$ 955,000	$ 989,000
Pipeline Subscription Capacity Percentage				100.00%
Summarized Financial Information Percentage				100.00%	100.00%	100.00%
Capital contributions to or payments to acquire equity method investments		$ 2,900,000
Additional Equity Method Ownership Percentage Acquired		5.00%
Storage Capacity Subscribed				64.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets				$ 9,863,000	$ 8,812,000
Noncurrent assets				71,586,000	70,837,000
Current liabilities				5,377,000	38,029,000
Noncurrent liabilities				35,112,000	0
Revenues				16,913,000	18,025,000	$ 16,810,000
Gross profit				16,913,000	18,025,000	16,810,000
Income (loss) before income taxes				$ 6,002,000	6,011,000	5,804,000
South Star Energy Services
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				15.00%
Operating revenues				$ 1,568,000	3,541,000	$ 3,291,000
Trade accounts receivable				$ 183,000	$ 460,000
Summarized Financial Information Percentage				100.00%	100.00%	100.00%
Capital contributions to or payments to acquire equity method investments			$ 22,500,000
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets				$ 204,237,000	$ 192,151,000
Noncurrent assets				132,315,000	143,958,000
Current liabilities				45,953,000	47,923,000
Noncurrent liabilities				0	0
Revenues				769,295,000	845,695,000	$ 639,426,000
Gross profit				224,612,000	234,581,000	174,993,000
Income (loss) before income taxes				$ 129,340,000	136,569,000	102,805,000
South Star Energy Services | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Additional Information	On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar. GNGC’s election to purchase our entire 15% interest in SouthStar is subject to and effective with the consummation of the Acquisition.
Hardy Storage
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Transportation or gas storage costs				$ 9,290,000	9,461,000	$ 9,702,000
Trade accounts payable				$ 774,000	$ 774,000
Summarized Financial Information Percentage				100.00%	100.00%	100.00%
Storage Capacity Subscribed				40.00%
Storage Capacity Subscription Percentage				100.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets				$ 11,658,000	$ 12,644,000
Noncurrent assets				156,803,000	157,861,000
Current liabilities				19,078,000	17,316,000
Noncurrent liabilities				69,971,000	78,830,000
Revenues				23,350,000	23,804,000	$ 24,375,000
Gross profit				23,350,000	23,804,000	24,375,000
Income (loss) before income taxes				$ 10,403,000	$ 10,497,000	10,582,000
Constitution Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				24.00%
Pipeline Subscription Capacity Percentage				100.00%
Summarized Financial Information Percentage				100.00%	100.00%
Capital contributions to or payments to acquire equity method investments				$ 19,100,000
Total Contributions To Equity Method Investments For Project				72,700,000
Estimated Pipeline Development And Construction Costs				834,000,000
Estimated Contributions For Pipeline And Construction Costs				$ 200,200,000
Target Pipeline In Service Date				2,016
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets				$ 6,163,000	$ 11,273,000
Noncurrent assets				330,152,000	219,208,000
Current liabilities				4,398,000	7,667,000
Noncurrent liabilities				0	0
Revenues				0	0	0
Gross profit				0	0	0
Income (loss) before income taxes				$ 24,604,000	$ 10,091,000	$ 3,459,000
Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				10.00%
Summarized Financial Information Percentage				100.00%
Capital contributions to or payments to acquire equity method investments				$ 10,600,000
Target Pipeline In Service Date				2,018
Long-term Purchase Commitment, Period				20 years
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets				$ 23,422,000
Noncurrent assets				86,109,000
Current liabilities				9,105,000
Noncurrent liabilities				0
Revenues				0
Gross profit				0
Income (loss) before income taxes				$ (5,205,000)
Estimated Percentage Project Financing				60.00%
Maximum Funding Obligation Under Equity Contribution Agreements				$ 15,200,000
Equity Method Investment, Future Ownership Percentage				50.00%
Atlantic Coast Pipeline | Minimum
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs				$ 4,500,000,000
Atlantic Coast Pipeline | Maximum
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 - USD ($) $ in Thousands	Oct. 31, 2015	Oct. 31, 2014
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 206,956	$ 170,171
Cardinal Pipeline Company
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	15,083	16,073
Pine Needle Company
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	18,396	18,689
South Star Energy Services
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	41,325	40,965
Hardy Storage
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	39,706	37,179
Constitution Pipeline Company
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	82,403	57,255
Atlantic Coast Pipeline
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 10,043	$ 10

Business Segments (Details)

Business Segments (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Oct. 31, 2015USD ($)	Jul. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Jan. 31, 2015USD ($)	Oct. 31, 2014USD ($)	Jul. 31, 2014USD ($)	Apr. 30, 2014USD ($)	Jan. 31, 2014USD ($)	Oct. 31, 2015USD ($)segment		Oct. 31, 2014USD ($)		Oct. 31, 2013USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment									3
Segment Reporting, Disclosure of Major Customers									0
Segment Reporting Information [Abstract]
Revenues from external customers	$ 181,257	$ 158,266	$ 424,924	$ 607,271	$ 185,821	$ 164,187	$ 462,247	$ 657,733	$ 1,371,718	[1]	$ 1,469,988	[1]	$ 1,278,229	[1]
Margin	120,031	111,572	225,621	270,070	112,326	104,847	211,523	261,512	727,294		690,208		621,490
Operations and maintenance expenses									294,703		271,101		253,301
Depreciation									128,722		119,014		112,225
Operating income (loss) before income taxes									261,594		262,655		221,176
Income from equity method investments									34,461		32,753		26,056
Interest charges									68,631		54,686		24,938
Income before income taxes									227,233		238,619		220,363
Total assets	4,949,596				4,602,754				4,949,596		4,602,754		4,174,091
Equity method investments in non-utility activities	206,956				170,171				206,956		170,171		128,469
Construction expenditures									443,654		460,444		599,999
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment income (loss) before income taxes									261,594		262,655		221,176
Utility income taxes segment									(76,934)		(83,176)		(77,334)
Operating Income	(1,085)	5,233	75,123	105,758	6,993	3,254	67,299	102,319	185,029		179,865		144,194
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									227,233		238,619		220,363
Income taxes									(90,222)		(94,818)		(85,946)
Net Income	(14,109)	$ (8,260)	$ 66,402	$ 92,978	(8,967)	$ (7,344)	$ 62,540	$ 97,572	137,011		143,801		134,417
Segment Consolidated Assets [Abstract]
Total Assets	5,110,750				4,774,307				5,110,750		4,774,307
Operating Segments
Segment Consolidated Assets [Abstract]
Total Assets	4,949,596				4,602,754				4,949,596		4,602,754
Intersegment Eliminations
Segment Consolidated Assets [Abstract]
Total Assets	161,154				171,553				161,154		171,553
Regulated Operation
Segment Reporting Information [Abstract]
Revenues from external customers									1,371,718		1,469,988		1,278,229
Margin									727,294		690,208		621,490
Operations and maintenance expenses									294,517		270,877		253,120
Depreciation									128,704		118,996		112,207
Operating income (loss) before income taxes									261,963		263,041		221,528
Income from equity method investments									0		0		0
Interest charges									68,631		54,686		24,938
Income before income taxes									193,140		206,253		194,659
Total assets	4,742,284				4,432,239				4,742,284		4,432,239		4,045,259
Equity method investments in non-utility activities	0				0				0		0		0
Construction expenditures									443,654		460,444		599,999
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment income (loss) before income taxes									261,963		263,041		221,528
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									193,140		206,253		194,659
Regulated Non-Utility Activities
Segment Reporting Information [Abstract]
Revenues from external customers									0		0		0
Margin									0		0		0
Operations and maintenance expenses									81		132		103
Depreciation									0		0		0
Operating income (loss) before income taxes									(152)		(183)		(150)
Income from equity method investments									15,060		12,318		10,584
Interest charges									0		0		0
Income before income taxes									14,909		12,135		10,434
Total assets	165,630				129,206				165,630		129,206		90,097
Equity method investments in non-utility activities	165,630				129,206				165,630		129,206		90,097
Construction expenditures									0		0		0
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment income (loss) before income taxes									(152)		(183)		(150)
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									14,909		12,135		10,434
Unregulated Non-Utility Activities
Segment Reporting Information [Abstract]
Revenues from external customers									0		0		0
Margin									0		0		0
Operations and maintenance expenses									105		92		78
Depreciation									18		18		18
Operating income (loss) before income taxes									(217)		(203)		(202)
Income from equity method investments									19,401		20,435		15,472
Interest charges									0		0		0
Income before income taxes									19,184		20,231		15,270
Total assets	41,682				41,309				41,682		41,309		38,735
Equity method investments in non-utility activities	$ 41,326				$ 40,965				41,326		40,965		38,372
Construction expenditures									0		0		0
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment income (loss) before income taxes									(217)		(203)		(202)
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									$ 19,184		$ 20,231		$ 15,270
[1]	See Note 13 for amounts attributable to affiliates.

Selected Quarterly Financial 62

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Jan. 31, 2015	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2015		Oct. 31, 2014		Oct. 31, 2013
Quarterly Financial Data [Abstract]
Operating Revenues (1)	$ 181,257	$ 158,266	$ 424,924	$ 607,271	$ 185,821	$ 164,187	$ 462,247	$ 657,733	$ 1,371,718	[1]	$ 1,469,988	[1]	$ 1,278,229	[1]
Margin	120,031	111,572	225,621	270,070	112,326	104,847	211,523	261,512	727,294		690,208		621,490
Operating Income (Loss)	(1,085)	5,233	75,123	105,758	6,993	3,254	67,299	102,319	185,029		179,865		144,194
Net income (loss)	$ (14,109)	$ (8,260)	$ 66,402	$ 92,978	$ (8,967)	$ (7,344)	$ 62,540	$ 97,572	$ 137,011		$ 143,801		$ 134,417
Earnings Per Share of Common Stock:
Basic (usd per share)	$ (0.18)	$ (0.10)	$ 0.84	$ 1.18	$ (0.11)	$ (0.09)	$ 0.80	$ 1.27	$ 1.74		$ 1.85		$ 1.80
Diluted (usd per share)	$ (0.18)	$ (0.10)	$ 0.84	$ 1.18	$ (0.11)	$ (0.09)	$ 0.80	$ 1.26	$ 1.73		$ 1.84		$ 1.78
[1]	See Note 13 for amounts attributable to affiliates.