10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended January 31, 2016

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

 (Exact name of registrant as specified in its charter)

North Carolina	56-0556998
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
4720 Piedmont Row Drive, Charlotte, North Carolina	28210
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (704) 364-3120

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ýYes    ¨No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ýYes    ¨No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ý	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨Yes    ýNo

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at March 1, 2016
Common Stock, no par value	81,076,199

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

January 31, 2016

TABLE OF CONTENTS

		Page
Part I.	Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Comprehensive Income	3
	Condensed Consolidated Statements of Cash Flows	4
	Condensed Consolidated Statements of Stockholders’ Equity	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	47
Part II.	Other Information
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 6.	Exhibits	49
	Signatures	50

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)

	January 31, 2016		October 31, 2015
ASSETS
Utility Plant:
Utility plant in service	$	5,495,303	$	5,426,584
Less accumulated depreciation	1,278,629		1,251,940
Utility plant in service, net	4,216,674		4,174,644
Construction work in progress	204,628		170,250
Plant held for future use	3,155		3,155
Total utility plant, net	4,424,457		4,348,049
Other Physical Property, at cost (net of accumulated depreciation of $932 in 2016 and $926 in 2015	327		332
Current Assets:
Cash and cash equivalents	20,448		13,744
Trade accounts receivable(1) (less allowance for doubtful accounts of $3,762 in 2016 and $1,648 in 2015)	158,492		59,248
Income taxes receivable	12,877		11,447
Other receivables	18,701		10,667
Unbilled utility revenues	74,632		17,422
Inventories:
Gas in storage	61,135		68,240
Materials, supplies and merchandise	1,251		1,251
Gas purchase derivative assets, at fair value	1,602		1,343
Regulatory assets	61,815		10,936
Prepayments	10,697		28,903
Other current assets	271		344
Total current assets	421,921		223,545
Noncurrent Assets:
Equity method investments in non-utility activities	223,277		206,956
Goodwill	48,852		48,852
Regulatory assets	322,310		196,726
Income taxes receivable	26,023		26,023
Marketable securities, at fair value	4,842		4,666
Overfunded postretirement asset	28,620		17,770
Other noncurrent assets	5,751		5,439
Total noncurrent assets	659,675		506,432
Total	$	5,506,380	$	5,078,358
(1) See Note 13 for amounts attributable to affiliates.
See notes to condensed consolidated financial statements.

1

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)

	January 31, 2016			October 31, 2015
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock – no par value – 175 shares authorized	$	—		$	—
Common stock - no par value - shares authorized: 200,000 shares; outstanding: 81,072 in 2016 and 80,883 in 2015	732,056			721,419
Retained earnings	776,839			705,748
Accumulated other comprehensive loss	(487		)	(855		)
Total stockholders’ equity	1,508,408			1,426,312
Long-term debt	1,523,896			1,523,677
Total capitalization	3,032,304			2,949,989
Current Liabilities:
Current maturities of long-term debt	40,000			40,000
Short-term debt	495,000			340,000
Trade accounts payable (1)	120,954			99,895
Other accounts payable	38,377			52,149
Accrued interest	26,293			29,488
Customers’ deposits	22,212			20,896
General taxes accrued	12,734			27,940
Gas supply derivative liabilities, at fair value	28,300			—
Regulatory liabilities	5,680			13,367
Other current liabilities	7,541			11,861
Total current liabilities	797,091			635,596
Noncurrent Liabilities:
Deferred income taxes	894,429			829,223
Unamortized federal investment tax credits	987			1,027
Accumulated provision for postretirement benefits	14,944			14,975
Gas supply derivative liabilities, at fair value	127,000			—
Regulatory liabilities	590,400			590,301
Conditional cost of removal obligations	19,984			19,712
Other noncurrent liabilities	29,241			37,535
Total noncurrent liabilities	1,676,985			1,492,773
Commitments and Contingencies (Note 10)
Total	$	5,506,380		$	5,078,358
(1) See Note 13 for amounts attributable to affiliates.
See notes to condensed consolidated financial statements.

2

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended   January 31
	2016			2015
Operating Revenues (1)	$	461,337		$	607,271
Cost of Gas (1)	175,088			337,201
Margin	286,249			270,070
Operating Expenses:
Operations and maintenance	71,300			66,150
Depreciation	33,686			31,893
General taxes	9,922			9,997
Utility income taxes	61,909			56,272
Total operating expenses	176,817			164,312
Operating Income	109,432			105,758
Other Income (Expense):
Income from equity method investments	9,202			8,265
Non-operating income	329			630
Non-operating expense	(727		)	(700		)
Income taxes	(3,378		)	(3,264		)
Total other income (expense)	5,426			4,931
Utility Interest Charges:
Interest on long-term debt	18,839			17,489
Allowance for borrowed funds used during construction	(2,805		)	(2,272		)
Other	1,034			2,494
Total utility interest charges	17,068			17,711
Net Income	97,790			92,978
Other Comprehensive Income (Loss), net of tax:
Unrealized loss from hedging activities of equity method investments, net of tax of ($91) and ($600) for the three months ended January 31, 2016 and 2015, respectively	(138		)	(944		)
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, net of tax of $327 and $75 for the three months ended January 31, 2016 and 2015, respectively	505			117
Net current period benefit activities of equity method investments, net of tax of $1 for the three months ended January 31, 2016	1			—
Total other comprehensive income (loss)	368			(827		)
Comprehensive Income	$	98,158		$	92,151
Average Shares of Common Stock:
Basic	80,963			78,620
Diluted	81,266			78,945
Earnings Per Share of Common Stock:
Basic	$	1.21		$	1.18
Diluted	$	1.20		$	1.18
(1) See Note 13 for amounts attributable to affiliates.
See notes to condensed consolidated financial statements.

3

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Three Months Ended   January 31
	2016			2015
Cash Flows from Operating Activities:
Net income	$	97,790		$	92,978
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	36,491			34,760
Provision for doubtful accounts	2,147			2,163
Income from equity method investments	(9,202		)	(8,265		)
Distributions of earnings from equity method investments	2,041			1,788
Deferred income taxes, net	64,929			53,825
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	(259		)	3,885
Receivables	(166,935		)	(240,738		)
Inventories	7,105			(4,997		)
Settlement of legal asset retirement obligations	(895		)	(1,024		)
Regulatory assets	(178,598		)	14,561
Other assets	19,516			28,731
Accounts payable	13,516			31,655
Contributions to benefit plans	(10,132		)	(10,254		)
Accrued/deferred postretirement benefit costs	(748		)	345
Gas supply derivatives, at fair value	155,300			—
Regulatory liabilities	(12,408		)	36,369
Other liabilities	(23,761		)	(14,183		)
Net cash (used in) provided by operating activities	(4,103		)	21,599
Cash Flows from Investing Activities:
Utility capital expenditures	(112,262		)	(104,068		)
Allowance for borrowed funds used during construction	(2,805		)	(2,272		)
Contributions to equity method investments	(9,107		)	(10,019		)
Distributions of capital from equity method investments	551			837
Proceeds from sale of property	308			112
Investments in marketable securities	(440		)	(848		)
Other	2,850			85
Net cash used in investing activities	(120,905		)	(116,173		)

4

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Three Months Ended   January 31
	2016			2015
Cash Flows from Financing Activities:
Net borrowings – commercial paper	$	155,000		$	125,000
Expenses related to issuance of debt	(1,161		)	(1		)
Issuance of common stock through dividend reinvestment and employee stock plans	4,653			5,106
Dividends paid	(26,729		)	(25,168		)
Other	(51		)	(89		)
Net cash provided by financing activities	131,712			104,848
Net Increase in Cash and Cash Equivalents	6,704			10,274
Cash and Cash Equivalents at Beginning of Period	13,744			9,643
Cash and Cash Equivalents at End of Period	$	20,448		$	19,917
Cash Paid During the Period for:
Interest	$	22,852		$	22,641
Income Taxes:
Income taxes paid	$	2,027		$	1,378
Income taxes refunded	173			530
Income taxes, net	$	1,854		$	848
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	52,738		$	27,368
See notes to condensed consolidated financial statements.

5

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands, except per share amounts)

								Accumulated
								Other
	Common Stock				Retained			Comprehensive
	Shares	Amount			Earnings			Income (Loss)				Total
Balance, October 31, 2014	78,531	$	636,835		$	672,004		$	(237	)	$	1,308,602
Net Income					92,978						92,978
Other Comprehensive Loss								(827		)	(827		)
Common Stock Issued	236	8,995									8,995
Expenses from Issuance of Common Stock		(137		)							(137		)
Tax Benefit from Dividends Paid on ESOP Shares					32						32
Dividends Declared ($.32 per share)					(25,168		)				(25,168		)
Balance, January 31, 2015	78,767	$	645,693		$	739,846		$	(1,064	)	$	1,384,475
Balance, October 31, 2015	80,883	$	721,419		$	705,748		$	(855	)	$	1,426,312
Net Income					97,790						97,790
Other Comprehensive Income								368			368
Common Stock Issued	189	10,658									10,658
Expenses from Issuance of Common Stock		(21		)							(21		)
Tax Benefit from Dividends Paid on ESOP Shares					30						30
Dividends Declared ($.33 per share)					(26,729		)				(26,729		)
Balance, January 31, 2016	81,072	$	732,056		$	776,839		$	(487	)	$	1,508,408
See notes to condensed consolidated financial statements.

6

Piedmont Natural Gas Company, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Summary of Significant Accounting Policies

Significant Accounting Policies

These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 2015. Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. There were no significant changes to those accounting policies during the three months ended January 31, 2016.

Unaudited Interim Financial Information

The condensed consolidated financial statements have not been audited. We have prepared the unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles (GAAP) in the United States of America are omitted in this interim report under these SEC rules and regulations. The unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position as of January 31, 2016 and October 31, 2015, the results of operations for three months ended January 31, 2016 and 2015, and cash flows and stockholders’ equity for the three months ended January 31, 2016 and 2015.

Seasonality and Use of Estimates

Our business is seasonal in nature. The results of operations for the three months ended January 31, 2016 do not necessarily reflect the results to be expected for the full year.

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 condensed 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.

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 (loss) (OCIL). 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. Our regulatory assets and liabilities are detailed in Note 3 to the condensed consolidated financial statements in this Form 10-Q.

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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 Condensed Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option 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 Condensed Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans. As discussed below, effective in our first quarter 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.

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 for the specific instrument, location or commodity being valued. 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 maturity and settlement of our 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 fair value hierarchy levels as set forth in the fair value guidance.

For the fair value measurements of our derivatives and marketable securities, see Note 9 to the condensed consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 10 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. For further information on our fair value methodologies, see “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. Effective in our first quarter 2016, we have long-dated, fixed quantity natural gas supply contracts for our utility operations which are accounted for as derivatives. We classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we used a discounted cash flow technique to calculate our valuation. We incorporated the following inputs and assumptions in our model: contract volume, forward market prices from third party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. There were no other significant changes to these fair value methodologies during the three months ended January 31, 2016.

Recently Issued Accounting Standards Update (ASU)

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 development of guidance from our industry.

8

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 amendment provides 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 therein) 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 analyzing our cloud computing arrangements to identify any internal-use software and are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-01, January 2016, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The amendment addresses aspects of recognition, measurement, presentation and disclosure of financial instruments. It affects investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment.	Annual periods (and interim periods within those periods) beginning after December 15, 2017 (November 1, 2018 for us).	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for existing capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018 (November 1, 2019 for us), with early adoption permitted.	We are currently evaluating the effect on our financial position, results of operations and cash flows.

Reclassifications and Changes in Presentation

A reclassification has been made to the prior year Condensed Consolidated Balance Sheets to conform with the current year presentation. In this fiscal quarter, we early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This ASUeliminated the current requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet and replaced it with a noncurrent classification of deferred tax assets and liabilities. While the guidance would have been effective for us beginning November 1, 2017, we elected to adopt this guidance effective November 1, 2015 to simplify our presentation of deferred tax assets and liabilities.

With the adoption of the new pronouncement retrospectively, the fiscal year 2015 Condensed Consolidated Balance Sheets line item "Deferred income taxes" of $32.4 million previously included within "Current Assets" has been reclassified to net with the noncurrent line item "Deferred income taxes" as $829.2 million within "Noncurrent Liabilities." Line item "Total current

9

assets" has been reduced by $32.4 million to $223.5 million, line item "Total noncurrent liabilities" has been reduced to $1,492.8 million, resulting in total assets and total capitalization and liabilities totaling $5,078.4 million.

2. Proposed Acquisition by Duke Energy Corporation

On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (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).

On December 22, 2015, the Federal Trade Commission granted early termination of the 30-day waiting period for the Acquisition under the federal Hart-Scott-Rodino Antitrust Improvements Act of 1976. Expiration or termination of the waiting period is one of the conditions required for completion of the Acquisition.

For information on the January 15, 2016 filings with the North Carolina Utilities Commission (NCUC) for approval of the Acquisition and with the Tennessee Regulatory Authority (TRA) to transfer Piedmont's Tennessee operating license, see Note 3 to the condensed consolidated financial statements in this Form 10-Q.

At a specially called meeting held on January 22, 2016, the proposal to approve the Acquisition was approved by Piedmont's shareholders with a vote of 66.8% of Piedmont's outstanding shares of common stock entitled to vote. Piedmont's shareholder approval of the transaction is one of the conditions required for completion of the Acquisition.

In connection with this transaction, during the three months ended January 31, 2016, we recorded Acquisition-related integration expenses of $1.5 million for costs paid to outside parties, which are reflected in “Operations and maintenance” in “Operating Expenses” in the Condensed Consolidated Statements of Comprehensive Income. Also during this period, we recorded incremental share-based compensation expense of $4.7 million from the accelerated vesting, payment and taxation of certain share-based awards for our President and Chief Executive Officer (CEO) and other eligible officers and participants with the issuance of restricted nonvested shares of our common stock in December 2015. These share-based plan costs are reflected in "Operations and maintenance" and related payroll taxes in "General taxes" in "Operating Expenses" in the Condensed Consolidated Statements of Comprehensive Income. For further information on these accelerated share-based transactions, see Note 12 to the condensed consolidated financial statements in this Form 10-Q. These amounts do not include the cost of company personnel participating in Acquisition-related integration planning activities.

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3. Regulatory Matters

Rate Regulated Basis of Accounting

Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are as follows.

In thousands	January 31, 2016		October 31, 2015
Regulatory Assets:
Current:
Unamortized debt expense on reacquired debt	$	238	$	238
Amounts due from customers	22,956		—
Environmental costs	1,522		1,513
Deferred operations and maintenance expenses	860		847
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,757
Robeson liquefied natural gas (LNG) development costs	382		381
Derivatives - gas supply contracts held for utility operations	28,300		—
Other	1,330		1,730
Total current	61,815		10,936
Noncurrent:
Unamortized debt expense on reacquired debt	4,607		4,666
Environmental costs	4,587		5,107
Deferred operations and maintenance expenses	3,777		3,997
Deferred pipeline integrity expenses	29,767		29,824
Deferred pension and other retirement benefit costs	18,887		17,861
Amounts not yet recognized as a component of pension and other retirement benefit costs	113,197		114,854
Regulatory cost of removal asset	19,363		19,087
Robeson LNG development costs	32		127
Derivatives - gas supply contracts held for utility operations	127,000		—
Other	1,093		1,203
Total noncurrent	322,310		196,726
Total	$	384,125	$	207,662

Regulatory Liabilities:
Current:
Amounts due to customers	$	5,680	$	13,367
Noncurrent:
Regulatory cost of removal obligations	526,299		521,478
Deferred income taxes	64,019		68,738
Amounts not yet recognized as a component of pension and other retirement benefit costs	82		85
Total noncurrent	590,400		590,301
Total	$	596,080	$	603,668

Rate Oversight and Rate and Regulatory Actions

North Carolina

In November 2015, we filed a petition with the NCUC seeking authority, under the approved integrity management riders (IMR) settlement agreement and procedural schedule, to change our rates effective December 1, 2015 to collect a total of $40.9 million in annual IMR margin revenues, representing an additional $13.4 million in annual IMR margin revenues from rate adjustments approved by the NCUC in its January 2015 order. The rate adjustment was 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 December 2015, the NCUC approved the requested IMR rate increase. In February 2016, the NCUC Public Staff filed their

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IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers over December 2015 through May 2016, which we began recording in our first quarter 2016.

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.

In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. A hearing has been scheduled for July 18, 2016 on this matter.

South Carolina

In June 2015, we filed with the Public Service Commission of South Carolina (PSCSC) a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study as permitted under the Natural Gas Rate Stabilization Act requesting a change in our rates from those approved by the PSCSC in its October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff 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 January 2016, we and Duke Energy discussed the Acquisition of Piedmont by Duke Energy with the PSCSC pursuant to its procedures for an allowable ex-parte communication briefing in accordance with state statute. The PSCSC's approval of the Acquisition is not required.

Tennessee

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 Tennessee Incentive Plan (TIP). We are waiting on a ruling from the TRA at this time.

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 Actual Cost Adjustment (ACA) mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order.

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 IMR-eligible capital investments in integrity and safety projects over the twelve-month period ended October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016.

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 Tennessee Consumer Advocate stipulating that we refund the $4.7 million to customers over a twelve-month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve-month period beginning January 2016. In February 2016, the TRA issued its written order on this matter.

In January 2016, we and Duke Energy filed a joint application with the TRA seeking approval on or before April 30, 2016 of a transfer of Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statute due to the change in control. We are waiting on a ruling by the TRA at this time.

In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in a deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

4. 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 plan (ICP) awards 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.

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A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest and any FSAs settle, for the three months ended January 31, 2016 and 2015 is presented below.

	Three Months
In thousands, except per share amounts	2016		2015
Net Income	$	97,790	$	92,978
Average shares of common stock outstanding for basic earnings per share	80,963		78,620
Contingently issuable shares under ICP awards	117		325
Contingently issuable restricted nonvested shares under accelerated ICP awards	182		—
Contingently issuable shares under FSAs	4		—
Average shares of dilutive stock	81,266		78,945
Earnings Per Share of Common Stock:
Basic	$	1.21	$	1.18
Diluted	$	1.20	$	1.18

We accelerated the issuance of shares of common stock under approved ICP awards as permitted under the terms of the Merger Agreement. This acceleration resulted in the issuance of 181,944 restricted nonvested shares of our common stock in December 2015, plus 1,092 restricted nonvested shares of our common stock from the reinvestment of dividends on these shares in January 2016. These restricted nonvested shares of our common stock are included in the calculation of diluted earnings per share in the table above but excluded in basic earnings per share and shares of our common stock outstanding because of their restricted nonvested nature. For further information on the acceleration of these shares of our common stock under our employee share-based plans, see Note 12 to the condensed consolidated financial statements in this Form 10-Q.

5. Long-Term Debt Instruments

The NCUC approved debt and equity issuances under an effective debt and equity shelf registration statement up to $1 billion through June 6, 2017. As of January 31, 2016, we have $544.1 million remaining for debt and equity issuances as approved by the NCUC. For further information on equity transactions, see Note 7 to the condensed consolidated financial statements in this Form 10-Q. 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.

Our long-term debt as of January 31, 2016 and October 31, 2015 is presented below.

In thousands	January 31, 2016			October 31, 2015
Principal	$	1,575,000		$	1,575,000
Unamortized debt issuance expenses and discounts	(11,104		)	(11,323		)
Total	1,563,896			1,563,677
Less current maturities	40,000			40,000
Total long-term debt	$	1,523,896		$	1,523,677

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.

6. Short-Term Debt Instruments

On December 14, 2015, we amended and restated the agreement underlying our $850 million five-year revolving syndicated credit facility as an $850 million five-year revolving syndicated credit facility that expires on December 14, 2020 and has an option to request an expansion up to an additional $200 million. 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 was issued and outstanding as of January 31, 2016 and October 31, 2015. 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

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Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020, provided that we are in compliance with all terms of the agreement.

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 period.

As of January 31, 2016, we had $495 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Condensed Consolidated Balance Sheets, with original maturities ranging from 11 to 17 days from their dates of issuance at a weighted average interest rate of .57%. As of October 31, 2015, our outstanding notes under the CP program, included in the Condensed Consolidated Balance Sheets as stated above, were $340 million at a weighted average interest rate of .22%.

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2016. A summary of the short-term debt activity under our CP program for the three months ended January 31, 2016 is as follows.

In millions	Three Months
Minimum amount outstanding during period	$	340
Maximum amount outstanding during period	$	500
Minimum interest rate during period	.20		%
Maximum interest rate during period	.75		%
Weighted average interest rate during period	.44		%

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at January 31, 2016.

7. Stockholders’ Equity

Capital Stock

Changes in common stock for the three months ended January 31, 2016 are as follows.

In thousands	Shares	Amount
Balance, October 31, 2015	80,883	$	721,419
Issued to participants in the Employee Stock Purchase Plan (ESPP)	6	342
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan	77	4,260
Issued to participants in the ICP	106	6,056
Costs from issuance of common stock		(21		)
Balance, January 31, 2016	81,072	$	732,056

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 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 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 through July 31, 2016.

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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 JP Morgan on January 4, 2016, 360,000 shares were borrowed from third parties and sold by JP Morgan, from January 4, 2016 to January 28, 2016, at a weighted average share price of $57.90, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $57.04.

Under the terms of this FSA, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation under the agreement. We expect to settle by delivering shares. At our election, we intend to physically settle the shares under this agreement prior to the closing date of the Acquisition or October 31, 2016, whichever occurs first.

In accordance with accounting guidance, we have classified the FSA as an equity transaction because the FSA is indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts will be recorded in the consolidated financial statements until settlement of the FSA.

Upon physical settlement of the FSA, delivery of our shares will result in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSA on our EPS could occur during periods when the average market price per share of our common stock is above the per share adjusted forward sale price described above. See Note 4 to the condensed consolidated financial statements in this Form 10-Q for the dilutive effect of the FSA on our EPS at January 31, 2016 with the inclusion of the incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

If we had settled the FSA by delivery of the 360,000 shares of our common stock to the forward counterparty as of January 31, 2016, we would have received net proceeds of approximately $20.5 million based on the net settlement price of $57.03 per share. Upon settlement, we intend to use the net proceeds from this FSA to finance capital expenditures, to repay outstanding short-term unsecured notes under our CP program and for general corporate purposes.

Cash dividends paid per share of common stock for the three months ended January 31, 2016 and 2015 are as follows.

	Three Months
	2016		2015
Cash dividends paid per share of common stock	$	0.33	$	0.32

Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and benefit activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 13 to the condensed consolidated financial statements in this Form 10-Q. Changes in each component of accumulated OCIL are presented below for the three months ended January 31, 2016 and 2015.

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	Changes in Accumulated OCIL(1)
	Three Months
In thousands	2016			2015
Accumulated OCIL beginning balance, net of tax	$	(855	)	$	(237	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(138		)	(944		)
Amounts reclassified from accumulated OCIL, net of tax	505			117
Total current period activity of hedging activities of equity method investments, net of tax	367			(827		)
Net current period benefit activities of equity method investments, net of tax	1			—
Accumulated OCIL ending balance, net of tax	$	(487	)	$	(1,064	)
(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 three months ended January 31, 2016 and 2015.

	Reclassification Out of Accumulated OCIL (1)						Affected Line Items on Condensed Statements of Comprehensive Income
	Three Months
In thousands	2016			2015
Hedging activities of equity method investments	$	832		$	192		Income from equity method investments
Income tax expense	(327		)	(75		)	Income taxes
Hedging activities of equity method investments	505			117
Net benefit activities of equity method investments	2			—			Income from equity method investments
Income tax expense	(1		)	—			Income taxes
Net benefit activities of equity method investments	1			—
Total reclassification for the period, net of tax	$	506		$	117
(1) Amounts in parentheses indicate debits to accumulated OCIL.

8. 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 11 to the condensed consolidated financial statements in this Form 10-Q.

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 Condensed 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 the noncurrent deferred compensation liability with the noncurrent asset; the current asset portion is included in “Other current assets” in “Current Assets” in the Condensed Consolidated Balance Sheets.

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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 January 31, 2016 and October 31, 2015 is as follows.

	January 31, 2016				October 31, 2015
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	28	$	28	$	51	$	51
Mutual funds	77		109		114		185
Total current trading securities	105		137		165		236
Noncurrent trading securities:
Money markets	536		536		465		465
Mutual funds	4,233		4,306		3,625		4,201
Total noncurrent trading securities	4,769		4,842		4,090		4,666
Total trading securities	$	4,874	$	4,979	$	4,255	$	4,902

9. 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 with the purchase of call option derivatives. 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 gas purchase 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 January 31, 2016 and October 31, 2015, we had long gas purchase options providing total coverage of 33.6 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held at January 31, 2016 are for the period from March 2016 through January 2017.

Derivative Assets and Liabilities - Gas Supply Contracts

We enter into forward gas supply contracts to provide diversification, reliability and gas cost benefits to our customers as part of our diversified gas supply portfolio. We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. Effective in the period ended January 31, 2016, we have certain forward gas supply contracts that meet the definition of derivative instruments that should be recorded at fair value. We have included gas supply contracts requiring fair value accounting in "Gas supply derivative liabilities, at fair value" in "Current Liabilities" and "Noncurrent Liabilities" in the Condensed Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our purchased gas adjustment (PGA) clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.

Fair Value Measurements and Quantitative and Qualitative Disclosures

We use purchased call options as 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. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these contracts that became effective in the period ended January 31, 2016 should be recorded at fair value. We classify fair value balances based on the observance of 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 in our Form 10-K for the year ended October 31, 2015. For an updated discussion of our fair value methodology, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2016 and October 31, 2015. 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

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consideration within the fair value hierarchy levels. We have had no transfers between any level during the three months ended January 31, 2016 and 2015. 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 purchased call option 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 purchased call option derivatives held for utility operations. Our purchased call option derivatives held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivatives presented at fair value that are held for our utility operations.

Recurring Fair Value Measurements as of January 31, 2016
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - purchased call options held for utility operations	$	1,602	$	—	$	—	$	—	$	1,602
Debt and equity securities held as trading securities:
Money markets	564		—		—		—		564
Mutual funds	4,415		—		—		—		4,415
Total fair value assets	$	6,581	$	—	$	—	$	—	$	6,581
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	155,300	$	—	$	155,300

Recurring Fair Value Measurements 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)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - purchased call options held for utility 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

In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our derivative gas supply contracts in the mid to later years of contract terms ranged from $2.84 to $4.37 per dekatherm.

The fair value of our derivative gas supply contracts is sensitive to the pricing differential of various natural gas indexes relevant to those particular contracts. An increased market price spread between the indexes would increase the fair value of the derivative and result in an unrealized loss, while conversely, a decreased market price spread would decrease the fair value of the derivative and result in an unrealized gain.

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy.

In thousands
Balance, October 31, 2015	$	—
Realized and unrealized gains (losses):
Recorded to regulatory assets	(155,300		)
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Balance, January 31, 2016	$	(155,300	)

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Our regulated utility segment purchased call option 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 condensed consolidated financial statements in this Form 10-Q. 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.

Our gas supply derivatives are generally based on unobservable inputs and are classified within Level 3. In accordance with regulatory provisions for rate-regulated activities, any gains and losses associated with these derivatives are reflected as a regulatory asset or liability, as appropriate, in "Derivatives - gas supply contracts held for utility operations" in Note 3 to the condensed consolidated financial statements in this Form 10-Q.

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 Condensed 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 presented at net cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The principal and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.

In thousands	Principal		Fair Value
As of January 31, 2016	$	1,575,000	$	1,734,319
As of October 31, 2015	1,575,000		1,720,586

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 purchased call option 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 and gas supply contracts for natural gas as of January 31, 2016 and October 31, 2015.

Fair Value of Derivative Instruments
	January 31,		October 31,
In thousands	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (March 2016 - January 2017)	$	1,602
Current Assets – Gas purchase derivative assets (December 2015 - October 2016)			$	1,343
Liability Financial Instruments:
Current Liabilities – Gas supply derivative liabilities	$	28,300
Noncurrent Liabilities – Gas supply derivative liabilities	127,000

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

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operation of the hedging programs of the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 3 to the condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed 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 our gas purchase option financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.

	Amount of Loss Recognized on Derivative Instruments and Deferred Under PGA Procedures						Location of Loss Recognized through PGA Procedures
	Three Months Ended   January 31
In thousands	2016			2015
Purchased call options	$	(1,901	)	$	(558	)	Cost of Gas

In Tennessee, the cost of purchased call 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 purchased call 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.

We would have recorded an unrealized loss of $155.3 million related to our gas supply derivatives in the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas supply derivatives in the Condensed Consolidated Statements of Comprehensive Income as a component of "Cost of Gas" in the month purchased.

Credit and Counterparty Risk

Information regarding our credit and counterparty risk is set forth in Note 8 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. During the three months ended January 31, 2016, there were no material changes in our credit and counterparty risk.

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 Condensed Consolidated Balance Sheets attributable to these entities amounted to $18.6 million, or approximately 11%, of our gross trade accounts receivable as of January 31, 2016. 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.

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.

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10. Commitments and Contingent Liabilities

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 fully recoverable subject to 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 of reservation fees 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 Federal Energy Regulatory Commission (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 Condensed Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

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.

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 as of January 31, 2016. Additional information concerning letters of credit is included in Note 6 to the condensed consolidated financial statements in this Form 10-Q.

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 January 31, 2016, 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). There were no material changes in the status of environmental-related matters during the three months ended January 31, 2016.

As of January 31, 2016, our estimated undiscounted environmental liability totaled $1 million, and consisted of $.9 million for MGP sites for which we retain responsibility and $.1 million for the USTs and the Huntersville LNG facility. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

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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.

Additional information concerning commitments and contingencies is set forth in Note 9 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2015.

11. Employee Benefit Plans

Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). 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 and dental expenses.

Beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We decided to replace the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. We made 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 did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended January 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2016			2015			2016		2015		2016			2015
Service cost	$	2,750		$	3,050		$	—	$	—	$	294		$	295
Interest cost	2,400			2,975			40		52		321			369
Expected return on plan assets	(6,000		)	(5,925		)	—		—		(442		)	(459		)
Amortization of prior service (credit) cost	(550		)	(550		)	52		58		(83		)	—
Amortization of actuarial loss	2,100			2,050			20		21		115			7
Total	$	700		$	1,600		$	112	$	131	$	205		$	212

In November 2015, we contributed $10 million to the qualified pension plan, and in January 2016, we contributed $1.8 million to the money purchase pension plan. During the three months ended January 31, 2016, we contributed $.1 million to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans in 2016.

In thousands
Nonqualified pension plans	$	389
OPEB plan	1,300

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. For the three months ended January 31, 2016, we contributed $.5 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As of January 31, 2016, we have a liability of $5 million for these plans.

See Note 8 and Note 9 to the condensed consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trusts.

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12. 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 three months ended January 31, 2016 and 2015, we recorded compensation expense, and as of January 31, 2016 and October 31, 2015, 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. The award with the performance period that ended October 31, 2015 was paid out to participants in December 2015. Two other awards with performance periods ending October 31, 2016 (2016 plan) and October 31, 2017 (2017 plan) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.

Also under our approved ICP, 64,700 nonvested restricted stock units (RSUs) were granted to our President and CEO in December 2011. During the five-year vesting period, any dividend equivalents accrue on these stock units and are 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 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 and 30% of the units vested on December 15, 2015. The remaining 50% of the units that vest on December 15, 2016 (2016 RSU) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below. For the three months ended January 31, 2016 and 2015, we recorded compensation expense, and as of January 31, 2016 and October 31, 2015, we accrued a liability for nonvested RSUs, as applicable, based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value each quarter and at the settlement date.

The December 15, 2015 vesting covered 30% of the grant, including accrued dividends, for a total of 22,434 shares of 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.

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2016 and 2015, 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 Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are presented below.

	Three Months
In thousands	2016		2015
Compensation expense	$	6,230	$	2,230

	January 31, 2016		October 31, 2015
Liability	$	8,036	$	22,037

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 2016 RSU for our President and CEO (accelerated RSU) 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 nonvested 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 Internal Revenue Code of 1986, as amended, 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 2016 RSU, 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 2016 RSU, 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

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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 restricted nonvested 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 nonvested 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. In accordance with accounting guidance, we have not presented these restricted nonvested shares as shares outstanding or included them in our calculation of basic EPS as they are contingent shares until earned; as applicable, they are included in our calculation of diluted EPS in Note 4 to the condensed consolidated financial statements in this Form 10-Q. The participants otherwise have all rights of shareholders with respect to the restricted nonvested shares of common stock.

The accelerated ICP awards and the accelerated RSU were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted nonvested 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 2016 RSU, 19,554 restricted nonvested 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 issued for the accelerated RSU 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 fair market value is determined by calculating the average of the high and low trading prices on the purchase date.

13. Equity Method Investments

The condensed 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 Condensed Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Condensed Consolidated Statements of Comprehensive Income.

Ownership Interests

We have the following membership interests in these companies as of January 31, 2016 and October 31, 2015, respectively.

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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 approximately 600 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 diverse northeastern 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 Condensed 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 Condensed Consolidated Statements of Comprehensive Income.

Related Party Transactions

We have related party transactions as a customer of our investments. For each period of the three months ended January 31, 2016 and 2015, these gas costs and the amounts we owed to our equity method investees, as of January 31, 2016 and October 31, 2015 are as follows.

Related Party	Type of Expense	Cost of Gas (1)				Trade accounts payable (2)
		Three Months				January 31,		October 31,
In thousands		2016		2015		2016		2015
Cardinal	Transportation costs	$	2,203	$	2,214	$	740	$	744
Hardy Storage	Gas storage costs	2,322		2,322		774		774
Pine Needle	Gas storage costs	2,834		2,936		955		955
Totals		$	7,359	$	7,472	$	2,469	$	2,473
(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

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We have related party transactions as we sell wholesale gas supplies to SouthStar. For each period of the three months ended January 31, 2016 and 2015, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2016 and October 31, 2015 are as follows.

	Operating Revenues (1)				Trade accounts receivable (2)
	Three Months				January 31,		October 31,
In thousands	2016		2015		2016		2015
Operating revenues	$	57	$	396	$	54	$	183
(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

Other Information

SouthStar

In accordance with the SouthStar limited liability company agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to Georgia Natural Gas Company (GNGC). On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective with the consummation of the Acquisition. On February 12, 2016, we entered into a letter agreement with GNGC for the purchase of our interest for $160 million cash. The letter agreement provides that we and GNGC will execute a definitive agreement for the purchase, which will include the satisfaction of customary closing conditions and obtaining regulatory approvals or consents necessary to consummate the purchase of our interest, including approval from the Georgia Public Service Commission.

Constitution

A subsidiary of The Williams Companies is the operator of the pipeline. The total estimated cost of the project is $977 million, including an allowance for funds used during construction (AFUDC).

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 $857 million, excluding AFUDC, in total. Our total anticipated contributions are approximately $205.8 million. As of January 31, 2016, our fiscal year contributions were $4.7 million, with our total equity contribution for the project totaling $77.3 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 second half of 2017, reflecting a delay in the issuance of remaining outstanding permits. The capacity of the pipeline is 100% subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

ACP

A subsidiary of Dominion Resources, Inc. is the operator of the pipeline. The total cost of 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.

We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline. As of January 31, 2016, our fiscal year contributions were $4.4 million, with our total equity contributions for the project totaling $15.1 million to date.

ACP is regulated by the FERC and subject to state and other federal approvals with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by affiliates of the members of ACP and another utility under twenty-year contracts.

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.

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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 that grant Dominion an option to purchase additional ownership interests in ACP from Duke Energy to maintain a majority ownership percentage relative to all other members. After consummation of the Acquisition, Duke Energy, together with our ownership, would have a 50% membership interest unless Dominion exercises its option.

14. Variable Interest Entities

As of January 31, 2016, we have determined that we are not the primary beneficiary under variable interest entity (VIE) accounting guidance in any of our equity method investments, as presented in Note 13 to the condensed consolidated financial statements in this Form 10-Q. 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 Condensed Consolidated Balance Sheets. As of January 31, 2016 and October 31, 2015, our investment balances are as follows.

In thousands	January 31, 2016		October 31, 2015
Cardinal	$	14,928	$	15,083
Pine Needle	18,118		18,396
SouthStar	46,207		41,325
Hardy Storage	40,389		39,706
Constitution	88,968		82,403
ACP	14,667		10,043
Total equity method investments in non-utility activities	$	223,277	$	206,956

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.

15.     Business Segments

We have three reportable business segments, regulated utility, regulated non-utility 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

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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 Condensed Consolidated Statements of Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Condensed Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”

Our chief operating decision maker is the executive management team. We produce consolidated financial information internally that is supplemented with separate non-utility activity reporting that is used regularly to make operating decisions and assess performance of our three business segments. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the regulated and unregulated non-utility activities segments based on earnings and cash flows from the ventures.

The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements in our Form 10-K for the year ended October 31, 2015.

Operations by segment for the three months ended January 31, 2016 and 2015 are presented below.

	Regulated Utility				Regulated Non-Utility Activities						Unregulated Non-Utility Activities						Total
In thousands	2016		2015		2016			2015			2016			2015			2016		2015
Revenues from external customers	$	461,337	$	607,271	$	—		$	—		$	—		$	—		$	461,337	$	607,271
Margin	286,249		270,070		—			—			—			—			286,249		270,070
Operations and maintenance expenses	71,300		66,150		16			31			55			38			71,371		66,219
Income from equity method investments	—		—		4,692			3,771			4,510			4,494			9,202		8,265
Operating income (loss) before income taxes	171,341		162,030		(16		)	(31		)	(139		)	(121		)	171,186		161,878
Income before income taxes	154,030		144,401		4,676			3,740			4,371			4,373			163,077		152,514

Reconciliations to the condensed consolidated statements of comprehensive income for the three months ended January 31, 2016 and 2015 are presented below.

	Three Months
In thousands	2016			2015
Operating Income:
Segment operating income before income taxes	$	171,186		$	161,878
Utility income taxes	(61,909		)	(56,272		)
Regulated non-utility activities operating loss before income taxes	16			31
Unregulated non-utility activities operating loss before income taxes	139			121
Operating income	$	109,432		$	105,758

Net Income:
Income before income taxes for reportable segments	$	163,077		$	152,514
Income taxes	(65,287		)	(59,536		)
Total	$	97,790		$	92,978

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16. Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters and equity method investments, see Note 3 and Note 13, respectively, to the condensed consolidated financial statements in this Form 10-Q.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related notes in this Form 10-Q, as well as with our Form 10-K for the year ended October 31, 2015. Results for interim periods presented are not necessarily indicative of the results to be expected for the full fiscal year due to seasonal and other factors.

Forward-Looking Statements

This report, as well as other documents we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (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). Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Part II. Item 1A. Risk Factors, including those related to the Acquisition by Duke Energy that is more fully discussed in Note 2 to the condensed consolidated financial statements in this Form 10-Q:

• Economic conditions in our markets.

• Wholesale price of natural gas.

• Availability of adequate interstate pipeline transportation capacity and natural gas supply.

• Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis.

• Competition from other companies that supply energy.

• Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated.

• Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us.

• Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities.

• Weather conditions.

• Operational interruptions to our gas distribution and transmission activities.

• Inability to complete necessary or desirable pipeline expansion or infrastructure development projects.

• Elevated levels of capital expenditures.

• Changes to our credit ratings.

• Availability and cost of capital.

• Federal and state fiscal, tax and monetary policies.

• Ability to generate sufficient cash flows to meet all our cash needs.

• Ability to satisfy all of our outstanding debt obligations.

• Ability of counterparties to meet their obligations to us.

• Costs of providing pension benefits.

• Earnings from the joint venture businesses in which we invest.

• Ability to attract and retain professional and technical employees.

• Cybersecurity breaches or failure of technology systems.

• Ability to obtain and maintain sufficient insurance.

• Change in number of outstanding shares.

• Certain risks and uncertainties associated with the Acquisition, including, without limitation:

• the possibility that the Acquisition does not close due to the failure to satisfy the closing conditions, including, but not limited to, a failure to obtain the required regulatory approvals;

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• delays caused by the required regulatory approvals, which may delay the Acquisition or cause the companies to abandon the transaction;

• uncertainties and disruptions caused by the Acquisition that make it more difficult to maintain our business and operational relationships as well as maintain our relationships with employees, suppliers or customers, and the risk that unexpected costs will be incurred during this process;

• the diversion of management time on Acquisition-related issues, and;

• future shareholder suits could delay or prevent the closing of the Acquisition or otherwise

adversely impact our business and operations.

Other factors may be described elsewhere in this report. All of these factors are difficult to predict, and many of them are beyond our control. For these reasons, you should not place undue reliance on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “may,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

Forward-looking statements are based on information available to us as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities who are our wholesale customers. 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 businesses. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

We operate with three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities. Factors critical to the success of the regulated utility segment include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The regulated non-utility activities segment consists of our equity method investments in joint venture regulated energy-related pipeline and storage businesses that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in SouthStar Energy Services LLC (SouthStar) that is held by a wholly-owned subsidiary. For further information on equity method investments and business segments, see Note 13 and Note 15, respectively, to the condensed consolidated financial statements in this Form 10-Q. The percentages of the assets as of January 31, 2016 and earnings before taxes by segments for the three months ended January 31, 2016 are presented below.

	Assets		Earnings Before Taxes
Regulated Utility	96	%	94	%
Non-utility Activities:
Regulated non-utility activities	3	%	3	%
Unregulated non-utility activities	1	%	3	%
Total non-utility activities	4	%	6	%

We are also subject to various federal regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the certification and siting of new interstate natural gas pipeline projects, the purchase and sale of, the prices paid for, and the terms and conditions of service for the interstate transportation and storage of natural gas,

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regulations of the U.S. Department of Transportation that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the environment, including proposed air emissions regulations that would expand to include emissions of methane. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to recover the cost of natural gas we purchased for our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. The traditional utility rate design provides for the collection of margin revenue largely based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. By continually assessing alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy and through requests filed with our regulatory commissions, we have secured alternative rate structures and cost recovery mechanisms designed to allow us to recover certain costs through tracking mechanisms or riders without the need to file general rate cases. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag through rate stabilization adjustment (RSA) filings, integrity management riders (IMRs) or similar mechanisms and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation. This allows a better alignment of the interests of our shareholders and customers.

In North Carolina, we have a margin decoupling mechanism that provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, we operate under a RSA mechanism that achieves the objective of margin decoupling for residential and commercial customers with a one year lag. Under the RSA mechanism, we reset our rates based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism for residential and commercial customers in South Carolina for bills rendered during the months of November through March and in Tennessee for bills rendered during the months of October through April that partially offsets the impact of colder- or warmer-than-normal winter weather on our margin collections. Our WNA formulas calculate the actual weather variance from normal, using 30 years of history, and increase margin revenues when weather is warmer than normal and decrease margin revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors and when weather is significantly warmer or colder than normal. We have IMRs in North Carolina and Tennessee that separately track and recover, outside of general rate cases, certain costs associated with capital expenditures to comply with pipeline safety and integrity requirements.

In all three states, the gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the margin decoupling mechanism or the WNA mechanism. Through the use of various tariff mechanisms and fixed-rate contracts, we are able to achieve a higher degree of margin stabilization. For further information on state commission regulation, see Note 3 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. The following table presents the breakdown of our gas utility margin for the three months ended January 31, 2016 and 2015.

	2016		2015
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers,
Tennessee and North Carolina IMRs and fixed-rate contracts)	74	%	73	%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)	19	%	20	%
Volumetric or periodic renegotiation (including secondary marketing activity)	7	%	7	%
Total	100	%	100	%

Our long-term strategic directives shape our annual business objectives and focus on our customers, our communities, our employees and our shareholders. They also reflect what we believe are the inherent advantages of natural gas compared to other forms of energy. Our seven foundational strategic priorities are as follows:

• Promote the benefits of natural gas,

• Expand our core natural gas and complementary energy-related businesses to enhance shareholder value,

• Be the energy service provider of choice,

• Achieve excellence in customer service every time,

• Preserve financial strength and flexibility,

• Execute sustainable business practices, and

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• Enhance our healthy high performance culture.

With a continued focus on these priorities, we believe we will enhance long-term shareholder value. For a full discussion of our strategy and focus areas, see “Our Strategies” in Item 1. Business in our Form 10-K for the year ended October 31, 2015.

Executive Summary

Financial Performance – Quarter Ended 2016 Compared with Quarter Ended 2015

The following tables provide a comparison of the components of comprehensive income and statistical information for the three months ended January 31, 2016 as compared with the three months ended January 31, 2015.

Comprehensive Income Statement Components
	Three Months Ended January 31
In thousands, except per share amounts	2016		2015		Variance			Percent Change
Operating Revenues	$	461,337	$	607,271	$	(145,934	)	(24.0	)%
Cost of Gas	175,088		337,201		(162,113		)	(48.1	)%
Margin	286,249		270,070		16,179			6.0	%
Operations and Maintenance	71,300		66,150		5,150			7.8	%
Depreciation	33,686		31,893		1,793			5.6	%
General Taxes	9,922		9,997		(75		)	(0.8	)%
Utility Income Taxes	61,909		56,272		5,637			10.0	%
Total Operating Expenses	176,817		164,312		12,505			7.6	%
Operating Income	109,432		105,758		3,674			3.5	%
Other Income (Expense), net of tax	5,426		4,931		495			10.0	%
Utility Interest Charges	17,068		17,711		(643		)	(3.6	)%
Net Income	$	97,790	$	92,978	$	4,812		5.2	%
Average Shares of Common Stock:
Basic	80,963		78,620		2,343			3.0	%
Diluted	81,266		78,945		2,321			2.9	%
Earnings Per Share of Common Stock:
Basic	$	1.21	$	1.18	$	0.03		2.5	%
Diluted	$	1.20	$	1.18	$	0.02		1.7	%

Margin by Customer Class
	Three Months Ended January 31
In thousands	2016				2015
Sales and Transportation:
Residential	$	167,960	59	%	$	158,484	59	%
Commercial	73,101		25	%	68,874		25	%
Industrial	14,409		5	%	13,177		5	%
Power Generation	19,270		7	%	19,245		7	%
For Resale	3,187		1	%	2,642		1	%
Total	277,927		97	%	262,422		97	%
Secondary Market Sales	6,425		2	%	5,553		2	%
Miscellaneous	1,897		1	%	2,095		1	%
Total	$	286,249	100	%	$	270,070	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees
	Three Months Ended January 31
	2016		2015		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	24,252		31,473		(7,221	)	(22.9	)%
Commercial	15,229		18,389		(3,160	)	(17.2	)%
Industrial	26,966		27,264		(298	)	(1.1	)%
Power Generation	69,255		60,711		8,544		14.1	%
For Resale	2,290		2,950		(660	)	(22.4	)%
Throughput	137,992		140,787		(2,795	)	(2.0	)%
Secondary Market Volumes	16,530		11,169		5,361		48.0	%
Customers Billed (at period end)	1,038,369		1,023,245		15,124		1.5	%
Gross Residential, Commercial and Industrial Customer Additions	4,672		4,892		(220	)	(4.5	)%
Degree Days
Actual	1,455		1,945		(490	)	(25.2	)%
Normal	1,840		1,838		2		0.1	%
Percent (warmer) colder than normal	(20.9	)%	5.8	%	n/a		n/a
Number of Employees (at period end)	1,926		1,902		24		1.3	%

We closed our first quarter with a 5% increase in net income. Margin increased 6% due to IMR rate adjustments and customer growth. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Operations and maintenance (O&M) expense increased 8% primarily due to increases in payroll and direct and indirect Acquisition-related expenses. Depreciation increased 6% primarily due to increases in plant in service.

Financial Strength and Flexibility –In order to prudently fund our investment in growth and our ongoing capital needs, we continue to execute our financing program to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. In January 2016, we entered into a forward sale agreement (FSA) under our at-the-market (ATM) equity sales program that was established in January 2015. The timing and volume of sales under this program cannot be predicted with certainty and may be affected by factors outside our control, but will not exceed an aggregate of $170 million through the end of fiscal 2016. We continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs.

Managing Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have adequate and reliable supplies of competitively priced natural gas to meet the needs of our utility customers. In order to provide additional diversification, reliability and gas cost benefits to our customers, we have long-term supply and capacity contracts to buy and transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These competitive long-term sources of gas supply became available in late 2015 with the partial completion of the Williams – Transco Leidy Southeast expansion project and its Virginia Southside expansion project and replaced other sources of gas within our supply portfolio which supports our supply diversification strategy. Additional gas supplies from diverse gas supply basins in central West Virginia are anticipated to be available for the winter 2018 – 2019 season under a long-term pipeline capacity firm transportation agreement with Atlantic Coast Pipeline, LLC (ACP) upon completion of the project.

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Customer Growth –We continued to have solid customer growth in the first quarter. Affordable and stable wholesale natural gas costs continue to favorably position natural gas relative to other energy sources. Continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas should help us to sustain growth comparable to prior years. Extremely wet weather conditions delayed construction projects in residential and commercial markets, affecting growth in these markets during the current period as compared to the same prior period as presented below.

	2016	2015	Percent Change
Residential new home construction	3,306	3,302	0.1	%
Residential conversion	792	1,008	(21.4	)%
Commercial	572	580	(1.4	)%
Industrial	2	2	—	%
Total new customers	4,672	4,892	(4.5	)%

We forecast gross customer growth of approximately 1.6 – 2% for fiscal 2016. Overall, total net customers billed increased 1.5% for the three months ended January 31, 2016 as compared to the same period in 2015.

Capital Expenditures – We continued to execute our capital expansion and improvement programs that will provide benefits to our customers through safe and reliable natural gas service while providing our shareholders a fair and reasonable return on invested capital. Our capital expenditures are driven by pipeline integrity, safety and compliance programs, investments for customer growth, system infrastructure and technology, including a comprehensive work and asset management system.

With significant capital costs incurred under our ongoing system integrity programs, we have IMR regulatory mechanisms in North Carolina and Tennessee to separately track and recover certain costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity programs, as well as additional state safety and integrity requirements in Tennessee. The IMR orders by jurisdiction and the amount reflected in "Operating Revenues" in the Condensed Consolidated Statements of Comprehensive Income is summarized below:

In millions	North Carolina				Tennessee
Incremental annual margin revenue - 2014 IMR	$	1.0	(1)		$	13.1
Incremental annual margin revenue - 2015 IMR	24.4		(1)		6.5
Incremental annual margin revenue - 2016 IMR	15.5				1.7
Total cumulative incremental annual margin revenue (2)	$	40.9	(1	)	$	21.3
Amount recorded during first fiscal quarter in 2016	$	12.5			$	8.1
(1) Amounts reflect incremental annual IMR margin revenue, as adjusted per audit by the NCUC Public Staff under the approved IMR settlement agreement and procedural schedule, which may differ from the amounts reflected in the filed and approved rate adjustments. For further information on the current rate adjustment, see Note 3 to the condensed consolidated financial statements in this Form 10-Q. For further information on the IMR settlement agreement, see Note 3 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015.
(2) IMR recovery periods in both jurisdictions do not align with our fiscal year. For further information on these periods, see Note 3 to the condensed consolidated financial statements in this Form 10-Q.

Sustainable Business Practices – Our ability to provide safe and reliable natural gas service under any operating conditions is due to our ongoing investments in our pipeline delivery system through our system expansion and pipeline integrity management programs. Our review and implementation of our gas supply acquisition strategy ensures that we have adequate and reliable supplies to meet the peak day needs of our utility customers. We evaluate ongoing cold weather conditions and the corresponding customer consumption patterns, as well as historical winter weather over the past 40 years, in developing our peak day requirements.

Equity Method Investments –Our investments in complementary energy-related businesses continue to be an attractive way to generate earnings growth and long-term shareholder returns. We are a member of two ventures that propose to construct interstate natural gas pipelines, subject to the jurisdiction of the FERC. We are a 24% equity member of Constitution Pipeline Company LLC (Constitution) that plans to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. We are a 10% equity member of ACP that plans to transport diverse northeastern gas supplies into southeastern markets. The project would also require us to expand our utility natural gas delivery system in eastern North Carolina to provide redelivery of ACP volumes to retail natural gas markets. Having a second major interstate pipeline in the

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state will enhance the reliability and diversity of gas supplies to our Carolina market area. For further information on our anticipated contributions for these project costs, anticipated in-service dates and contributions made to date, see "Cash Flows from Investing Activities" in this Form 10-Q. For further information on equity method investments and business segments, see Note 13 and Note 15, respectively, to the condensed consolidated financial statements in this Form 10-Q.

Proposed Acquisition by Duke Energy – In October 2015, we entered into a Merger Agreement with Duke Energy. 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. For further information on the Acquisition, see "Forward Looking Statements" in Item 2 and Note 2, Note 3 and Note 13 to the condensed consolidated financial statements in this Form 10-Q. In the Merger Agreement, we agreed to covenants affecting the conduct of our business between the date of the Merger Agreement and the effective date of the Acquisition.

On November 6, 2015, Thomas E. Skains, Chairman, President and Chief Executive Officer of Piedmont, notified our Board of Directors and Duke Energy of his intent to terminate his employment and retire from Piedmont effective, and contingent, upon the closing of the Acquisition.

On December 18, 2015, Frank Yoho, our Senior Vice President - Commercial Operations, was designated by Duke Energy to lead the Duke Energy's natural gas operations, including our gas operations, when the Acquisition is closed.

Several required conditions for completion of the Acquisition have been obtained. In December 2015, the Federal Trade Commission granted early termination of the 30-day waiting period for the Acquisition under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In January 2016, the Acquisition was approved by 66.8% of eligible outstanding shares of common stock held by our shareholders.

Required filings were made with our state regulatory commissions in January 2016. We and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. We anticipate the Acquisition to close in 2016. We and Duke Energy filed a joint application seeking approval from the TRA to transfer our operating license to Duke Energy. We and Duke Energy discussed the Acquisition of Piedmont with the PSCSC.

In accordance with the SouthStar limited liability company agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to Georgia Natural Gas Company (GNGC). On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective with the consummation of the Acquisition. On February 12, 2016, we entered into a letter agreement with GNGC for the purchase of our interest for $160 million cash. The letter agreement provides that we and GNGC will execute a definitive agreement for the purchase, which will include the satisfaction of customary closing conditions and obtaining regulatory approvals or consents necessary to consummate the purchase of our interest, including approval from the Georgia Public Service Commission.

Additional information on operating results for the three months ended January 31, 2016 follows.

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Operating Revenues

Changes in operating revenues for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.

Changes in Operating Revenues - Increase (Decrease)
In millions	Three Months
Residential and commercial customers	$	(178.7	)
Industrial customers	(4.8		)
Secondary market	(18.4		)
Margin decoupling mechanism	31.3
WNA mechanisms	10.9
IMR mechanisms	14.0
Other revenue	(0.2		)
Total	$	(145.9	)

• Residential and commercial customers – the decrease is due to lower consumption from warmer weather and lower wholesale gas costs passed through to customers, slightly offset by customer growth.

• Industrial customers – the decrease is primarily due to lower wholesale gas costs passed through to customers and lower volumes from warmer weather.

• Secondary market – the decrease is due to lower margin sales prices, slightly offset by increased volumes. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements that are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

• Margin decoupling mechanism – the increase is primarily related to warmer weather in North Carolina as compared to the prior period. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to weather and conservation.

• WNA mechanisms – the increase is primarily related to warmer weather in South Carolina and Tennessee as compared to the prior period. As discussed in “Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.

• IMR mechanisms – the increase is due to the IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015 and December 2015.

Cost of Gas

Changes in cost of gas for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.

Changes in Cost of Gas - Increase (Decrease)
In millions	Three Months
Commodity gas costs passed through to sales customers	$	(94.2	)
Commodity gas costs in secondary market transactions	(19.3		)
Pipeline demand charges	(1.3		)
Regulatory-approved gas cost mechanisms	(47.3		)
Total	$	(162.1	)

• Commodity gas costs passed through to sales customers – the decrease is primarily due to lower consumption from warmer weather and lower wholesale gas costs passed through to sales customers, slightly offset by customer growth.

• Commodity gas costs in secondary market transactions – the decrease is primarily due to lower average wholesale gas costs, slightly offset by increased volumes.

• Pipeline demand charges – the decrease is primarily due to increased capacity release revenues and asset manager payments, slightly offset by increased demand costs.

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• Regulatory-approved gas cost mechanisms – the decrease is primarily due to a decrease in commodity gas cost and demand true-ups, partially offset by other regulatory mechanisms.

In all three states, we are authorized to recover from customers all prudently incurred gas costs. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account in current “Regulatory assets” or current “Regulatory liabilities” in the Condensed Consolidated Balance Sheets and are added to or deducted from cost of gas. For the amounts included in “Amounts due from customers” or “Amounts due to customers,” see Note 3 to the condensed consolidated financial statements in this Form 10-Q.

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory pass through of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 28% of revenues for the three months ended January 31, 2016, and our pipeline transportation and storage costs accounted for 7%.

In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers.

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These regulatory mechanisms by jurisdiction are presented below.

Regulatory Mechanism	North Carolina	South Carolina	Tennessee
WNA mechanism (1)		X	X
Margin decoupling mechanism (1)	X
Natural gas rate stabilization mechanism		X
Secondary market programs (2)	X	X	X
Incentive plan for gas supply (2)			X
IMR mechanism	X		X
Negotiated margin loss treatment	X	X
Uncollectible gas cost recovery	X	X	X
(1) Residential and commercial customers only.
(2) In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million.

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Changes in margin for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.

Changes in Margin - Increase (Decrease)
In millions	Three Months
Residential and commercial customers	$	13.7
Industrial customers	1.8
Secondary market activity	0.9
Net gas cost adjustments	(0.2		)
Total	$	16.2

• Residential and commercial customers – the increase is primarily due to IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015 and December 2015, and customer growth in all three states, partially offset by decreased volumes delivered in South Carolina and Tennessee due to warmer weather.

• Industrial customers – the increase is primarily due to IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015 and December 2015, as well as increased margin recognized from special contracts.

• Secondary market activity – the increase is primarily due to increased volumes, partially offset by lower margin sales.

Operations and Maintenance Expenses

Changes in O&M expenses for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)
In millions	Three Months
Payroll	$	5.3
Acquisition-related integration expenses	1.5
Other	(1.6		)
Total	$	5.2

• Payroll – the increase is primarily due to higher equity incentive plan accruals, including $4.3 million incremental expense from the accelerated vesting and payment of incentive awards under provisions in the Merger Agreement, additional employees and merit increases.

• Acquisition-related integration expenses – the increase is due to integration costs paid to outside parties in 2016.

Depreciation

Depreciation expense increased $1.8 million for the three months ended January 31, 2016 compared with the same period in 2015 primarily due to increases in plant in service, particularly related to major additions in system integrity investments.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, non-operating income, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, home service warranty programs, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and miscellaneous expenses. Other Income (Expense) for the three months ended January 31, 2016 was comparable to the same period in 2015.

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Utility Interest Charges

Changes in utility interest charges for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.

Changes in Utility Interest Charges - Increase (Decrease)
In millions	Three Months
Interest expense on long-term debt	$	1.4
Regulatory interest expense, net	(1.8		)
Other	(0.2		)
Total	$	(0.6	)

• Interest expense on long-term debt – the increase is primarily due to higher amounts of long-term debt outstanding in the current period.

• Regulatory interest expense, net – the change is primarily due to interest income on net amounts due from customers compared with interest expense in the prior year on net amounts due to customers.

Financial Condition and Liquidity

Our financial strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities. The need for long-term capital is driven by the level of and timing of capital expenditures and long-term debt maturities. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC.

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, beyond previously budgeted and planned amounts and allowed exceptions, 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. At this time, as a result of the Acquisition, we do not anticipate modifying our 2016 financing strategy discussed below and do not expect a significant impact on our cash requirements and sources of liquidity.

To meet our capital and liquidity requirements outside of the long-term capital markets, we rely on certain resources, including cash flows from operating activities, cash generated from our investments in joint ventures and short-term debt. Operating activities primarily provide the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs. We rely on short-term debt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned investments in customer growth, pipeline integrity programs, system infrastructure and contributions to our joint ventures.

The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventory and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by reduced tax payments due to the generation of federal net operating loss (NOL) carryforwards resulting from bonus depreciation, as well as the ability to recover and earn on investments in

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infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee. For further information on bonus depreciation, see the following discussion of "Cash Flows from Operating Activities" in this Form 10-Q.

Short-Term Debt

In December 2015, we amended and restated the agreement underlying our $850 million five-year revolving syndicated credit facility. The amended and restated agreement provides for a five-year revolving syndicated credit facility that expires in December 2020 and has an option to request an expansion of financing commitments by an additional $200 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $850 million. The five-year revolving syndicated credit facility continues to have the same financial covenants. The amended facility expressly permits the Acquisition by Duke Energy.

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. Any borrowings under the CP program rank equally with our other unsecured debt.

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2016. Highlights for our short-term debt under our CP program as of January 31, 2016 and for the quarter ended January 31, 2016 are presented below.

In thousands
End of period (January 31, 2016):
Amount outstanding	$	495,000
Weighted average interest rate	.57		%
During the period (November 1, 2015 – January 31, 2016):
Average amount outstanding	$	420,652
Minimum amount outstanding	340,000
Maximum amount outstanding	500,000
Minimum interest rate	.20		%
Maximum interest rate	.75		%
Weighted average interest rate	.44		%
Maximum amount outstanding:
November 2015	$	390,000
December 2015	480,000
January 2016	500,000

As of January 31, 2016, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.6 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of January 31, 2016, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $353.4 million.

Cash Flows from Operating Activities

The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term debt to meet seasonal working capital needs. The level of short-term debt can vary significantly due to changes as discussed above. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, construction activity and decreases in receipts from customers.

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During the winter heating season, our trade accounts payable increases to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts as amounts due to or from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers but may lead to conservation by customers in order to reduce their heating bills. Regulatory margin stabilizing and cost recovery mechanisms, such as decoupled tariffs and those that allow us to recover the gas cost portion of bad debt expense, mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.

Net cash (used in) provided by operating activities was $(4.1) million and $21.6 million for the three months ended January 31, 2016 and 2015, respectively. Net cash used in operating activities reflects an increase of $4.8 million in net income for 2016 compared with 2015 primarily due to increased margin, partially offset by increased operating expenses. The effect of changes in working capital on net cash used by operating activities is described below.

• Trade accounts receivable and unbilled utility revenues increased $158.6 million from October 31, 2015 primarily due to amounts billed to customers during the winter period and the seasonal increase in unbilled volumes.

• Net amounts due from customers increased$30.6 million in the current period primarily due to an increase in margin decoupling revenues, partially offset by excess deferred income taxes to be refunded to Tennessee customers.

• Gas in storage decreased$7.1 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for injections and lower volumes of gas in storage.

• Prepaid gas costs decreased$21.6 million in the current period primarily due to gas being made available for sale during the period. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

• Trade accounts payable increased $21.1 million in the current period primarily due to the purchase of natural gas for sale to our customers during the winter period, partially offset by the timing of payments for utility capital expenditures.

The Protecting Americans from Tax Hikes Act of 2015 (the Act), enacted December 18, 2015, retroactively extended the 50% bonus depreciation that expired in December 2014, extended 50% bonus depreciation for qualified property placed in service through December 2017 and provided for 40% and 30% bonus depreciation for property placed in service in 2018 and 2019, respectively. Under the Act, we were entitled to additional tax depreciation deductions for 2015. These additional depreciation deductions resulted in generating a federal NOL in 2015. We anticipate we will generate a NOL in 2016 due to bonus depreciation deductions and that we will generate future taxable income sufficient to utilize NOL tax carryforwards prior to the expiration of the carryforward periods.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee generated charges to customers of $9.8 million and credits to customers of $1.1 million in the three months ended January 31, 2016 and 2015, respectively. In Tennessee, adjustments are made directly to individual customer monthly bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities,” as presented in Note 3 to the condensed consolidated financial statements in this Form 10-Q, for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin decoupling mechanism increased margin by $18 million and decreased margin by $13.3 million in the three months ended January 31, 2016 and 2015, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanisms.

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The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs, if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

We face competition from other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on the relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the U.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternative fuel decisions made by industrial customers.

In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and O&M cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system.

Cash Flows from Investing Activities

Net cash used in investing activities was $120.9 million and $116.2 million for the three months ended January 31, 2016 and 2015, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures for the three months ended January 31, 2016 and 2015 were $112.3 million and $104.1 million, respectively, primarily for system integrity projects.

We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. Our program supports our system infrastructure, the growth in our customer base and large amounts for pipeline integrity, safety and compliance programs, including systems and technology infrastructure to enhance our pipeline system and integrity through a comprehensive work and asset management system. Significant utility construction expenditures are expected for growth and system integrity and are part of our long-range forecasts that are prepared at least annually and typically covering a forecast period of five years. We are contractually obligated to expend capital as the work is completed.

Detail of our forecasted fiscal 2016 – 2018 capital expenditures, including an allowance for funds used during construction, and our commitments to fund equity method investments is presented below. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 50 – 60% in total debt and 40 – 50% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to accelerated depreciation.

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In millions	2016		2017		2018
Customer growth and other	$	300	$	315	$	385
System integrity	270		275		205
Total forecasted utility capital expenditures	570		590		590
Forecasted funding of construction in equity method investments	50		170		80
Total	$	620	$	760	$	670

In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression to serve Duke Energy's W.S. Lee power generation facility near Anderson, South Carolina. Our total investment is estimated to be $38 million, with expenditures occurring primarily in our fiscal year 2016, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges and has a target in-service date of May 2017.

Also, in May 2015, we executed an agreement to construct a delivery station and associated compression to provide additional service to Duke Energy’s power generation facility at their Sutton site near Wilmington, North Carolina. Our total investment is estimated to be $13 million with expenditures occurring primarily in our fiscal years 2016 and 2017, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges and has a target in-service date of June 2017.

We are invested as equity members in two interstate natural gas pipeline projects that are in the development stage. As a member of each of these limited liability companies, we are committed to fund construction in proportion to our ownership interests. For further information on these equity investments, see Note 13 to the condensed consolidated financial statements in this Form 10-Q. Details of the project costs for these investments are presented below.

	Constitution		ACP
In millions	(24% ownership interest)		(10% ownership interest)
Our anticipated contributions for total project costs	$	205.8	$	450 – 500
Anticipated in-service date	second half of 2017			late 2018
Our contributions:
For the three months ended January 31, 2016	$	4.7		$	4.4
Over life of project to date	$	77.3		$	15.1

In connection with the ACP project, we plan to make additional utility capital investments in our natural gas delivery system, predominately in fiscal 2017 and 2018, of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets we serve. Of that amount, approximately $170 million will be supported by third-party contracts. These expenditures are driving the increase in utility capital expenditures for fiscal 2018 for customer growth as shown above in the schedule of forecasted capital expenditures.

Cash Flows from Financing Activities

Net cash used in financing activities was $131.7 million and $104.8 million for the three months ended January 31, 2016 and 2015, respectively. Funds are primarily provided from long-term debt securities, short-term borrowings, and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). We may sell common stock and long-term debt, when market and other conditions favor such long-term financing to maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. Funds are primarily used to finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program when required to maintain target capital structure, pay quarterly dividends on our common stock and for other general corporate purposes.

Outstanding debt under our CP program increased from $340 million as of October 31, 2015 to $495 million as of January 31, 2016 primarily due to seasonal requirements for utility capital expenditures, investments in our equity method investments and dividend payments. As discussed above in “Short-Term Debt” in “Financial Condition and Liquidity,” in December 2015, we amended and extended our existing $850 million five-year revolving syndicated credit facility, including an option to request an expansion of financing commitments by an additional $200 million. For further information on short-term debt, see Note 6 to

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the condensed consolidated financial statements in this Form 10-Q and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

We have a combined debt and equity shelf registration statement with the SEC that became effective on June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration up to $1 billion during its three-year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment-grade securities.

Under this shelf registration statement, we established an ATM equity sales program, including a forward sale component, by entering into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or 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 that began in January 2015 and ending October 31, 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.

Our ability to sell our common stock up to the specified $170 million limit will depend on a variety of circumstances, including equity market conditions, trading volume in our common stock and other factors outside our control. We cannot predict the timing of any such sales or the aggregate amount of shares that may be sold under the ATM program. In addition, the ATM program allows us, at our option, to sell shares pursuant to FSAs with affiliates of our sales agents (forward counterparties) under the related ATM program sales agreements. Shares sold pursuant to FSAs settle on dates specified by us, which may be substantially after the sales occur but not later than October 31, 2016, subject to certain exceptions. As of January 31, 2016, all FSAs that have been settled were settled in shares, and we intend to settle any current and future FSAs in shares. Under the terms of the Merger Agreement, we would need to obtain Duke Energy's prior consent to cash or net settle a FSA.

During the three months ended January 31, 2016, we sold 360,000 shares of our common stock under a FSA with JP Morgan that must be settled by the date discussed above. Under the terms of the FSA, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation. We expect to settle the FSA by delivering shares prior to the closing of the Acquisition or October 31, 2016, whichever occurs first. If we physically settle by issuing shares to the forward counterparty, the forward counterparty will, at settlement, pay us the proceeds less certain adjustments for its sale of the borrowed shares to the underwriters, which is anticipated to be approximately $20.1 million as of October 31, 2016. During the period ended January 31, 2016, we did not pay any compensation to the sales agent.

Upon settlement, we will use the net proceeds from this equity transaction to finance capital expenditures, repay outstanding notes under our unsecured CP program and for general corporate purposes. We will not recognize the proceeds from the forward sale nor record the issuance of such shares until the date of settlement. As of January 31, 2016, we have approximately $93.3 million remaining under the ATM program. For further information on our common stock and for more details on equity issuance transactions, see Note 7 to the condensed consolidated financial statements in this Form 10-Q.

As of January 31, 2016, we have $544.1 million remaining under the shelf registration statement for debt and equity issuances as approved by the NCUC. We plan to issue equity capital in our fiscal year 2016, at such amounts to support our capital investment program and maintain our target capital structure as discussed above. We continually monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt. In addition to issuing common stock under our DRIP and ESPP as described above, we expect to continue to issue common stock under our ATM program as described above through the end of fiscal 2016.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 in this Form 10-Q. We do not anticipate repurchasing any of our common stock in fiscal year 2016.

During the three months ended January 31, 2016 and 2015, we issued $4.7 million and $5.1 million, respectively, of common stock through DRIP and ESPP.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of January 31, 2016, our ability to pay dividends was not restricted by these note agreements. On March 9, 2016, the Board of Directors declared a quarterly dividend on common stock of $.34 per share, payable April 15, 2016 to shareholders of record at the close of business

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on March 25, 2016. For further information on long-term debt, see Note 5 to the condensed consolidated financial statements in this Form 10-Q.

Our targeted capitalization ratio is 50 – 60% in total debt and 40 – 50% in common equity. The components of our total debt outstanding (short-term debt and long-term debt, excluding unamortized discount and debt issuance costs) to our total capitalization as of January 31, 2016 and 2015, and October 31, 2015, are summarized in the table below.

	January 31				October 31				January 31
In thousands	2016		Percentage		2015		Percentage		2015		Percentage
Short-term debt	$	495,000	14	%	$	340,000	10	%	$	480,000	15	%
Current portion of long-term debt	40,000		1	%	40,000		1	%	—		—	%
Long-term debt, principal	1,535,000		43	%	1,535,000		46	%	1,425,000		43	%
Total debt	2,070,000		58	%	1,915,000		57	%	1,905,000		58	%
Common stockholders’ equity	1,508,408		42	%	1,426,312		43	%	1,384,475		42	%
Total capitalization (including short-term debt)	$	3,578,408	100	%	$	3,341,312	100	%	$	3,289,475	100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. The borrowing costs under our revolving syndicated credit facility and our unsecured CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds.

The lenders under our revolving syndicated credit facility and our unsecured CP program are major financial institutions, all of which have investment-grade credit ratings as of January 31, 2016. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

As of January 31, 2016, all of our long-term debt was unsecured. Our long-term debt is rated by two rating agencies, Standard & Poor’s Ratings Services (S&P) and Moody’s Investors Service (Moody’s). Our current debt ratings are all considered investment grade and are as follows.

	S&P	Moody's
Unsecured long-term debt	A	A2
Commercial paper	A1	P1

Subsequent to the announcement of the Acquisition, S&P affirmed our A rating for our senior unsecured long-term debt but placed it on credit watch with negative implications. Currently, Moody's has maintained its stable outlook for our long-term

debt. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, a change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

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 January 31, 2016, there has been no event of default giving rise to acceleration of our debt.

The Acquisition would constitute a change in control under the note agreements under which our 2.92% Senior Notes due 2016, which will be paid at its maturity date in June, 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued. While the Acquisition would not constitute an event of default, upon the closing of the Acquisition, we would be required to offer to prepay these notes to the noteholders at 100% of the principal amounts plus accrued interest.

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Estimated Future Contractual Obligations

During the three months ended January 31, 2016, there were no material changes to our estimated future contractual obligations in Management’s Discussion and Analysis in this Form 10-Q compared to the disclosure provided in our Form 10-K for the year ended October 31, 2015.

Off-balance Sheet Arrangements

From time to time, we enter into letters of credit, surety bonds and operating leases, as well as credit support arrangements on behalf of a wholly-owned subsidiary that holds one of our equity-method investments. None of these existing arrangements are material to our results of operations, cash flows or financial position. The letters of credit and surety bonds are discussed in Note 6 and Note 10, respectively, to the condensed consolidated financial statements in this Form 10-Q. The operating leases were discussed in Note 9 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. The credit support arrangement and indemnification agreement are discussed in Note 13 to the condensed consolidated financial statements in this Form 10-Q.

Critical Accounting Policies and Estimates

We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used, would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates presented in our Form 10-K for the year ended October 31, 2015 in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Management has discussed these critical accounting estimates with the Audit Committee of the Board of Directors. There have been no changes in our critical accounting policies and estimates discussed above since October 31, 2015, except as discussed below.

As discussed in our Form 10-K for the year ended October 31, 2015 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We decided to replace the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. We made 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 did 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 accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

Effective in our first quarter 2016, we have long-dated, fixed quantity natural gas supply contracts which are accounted for as derivatives. Our accounting of derivatives and the related fair value of the derivatives is a critical accounting estimate. We enter into both physical and financial contracts for the purchase and sale of natural gas. Fixed quantity gas supply contracts, as well as financial contracts that we purchase to hedge commodity price risks under our hedging programs established under state regulatory authority, are derivative instruments subject to fair value accounting and are recorded on the balance sheet at fair value. We record the changes in the fair value of these derivative instruments recoverable from or refundable to customers as regulatory assets or liabilities. 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 condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates. For the gas supply derivatives, we record the change in fair value as current and noncurrent regulatory assets or liabilities, the detail of which is presented in Note 3 to the condensed consolidated financial statements in this Form 10-Q, with corresponding current and noncurrent supply derivative liabilities recognized in the Condensed Consolidated Balance Sheets.

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Fair value is based on actively quoted market prices when they are available. In the absence of actively quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, internal models are used to estimate prices based on available historical and near-term future price information and/or the use of statistical methods. These inputs are used with industry standard valuation methodologies. See Note 1 and Note 9 to the condensed consolidated financial statements in this Form 10-Q for a discussion of our valuation methodologies.

Our judgment is required in determining the appropriate accounting treatment for our derivative instruments. This judgment involves various factors, including our ability to: (i) evaluate contracts and other activities as derivative instruments subject to the accounting guidance; (ii) determine whether or not our derivative instruments are recoverable from or refundable to customers in future periods and (iii) derive the estimated fair value of our derivative instruments.

Accounting Guidance

For information regarding recently issued accounting guidance, see Note 1 to the condensed consolidated financial statements in this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage all of these risks in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management (ERM) program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

The Board of Directors has delegated oversight of our ERM program to the Finance and Enterprise Risk (FER) Committee. All other committees of our Board of Directors have enhanced monitoring of those risks relating to areas where they have oversight responsibility. The Board of Directors approved risk tolerances for our major areas of risk exposure and receives quarterly reports from the FER Committee and annual reports from management.

Our exposure to, and management of, interest rate risk, commodity price risk and weather risk has remained the same during the three months ended January 31, 2016. Our annual discussion of market risk was included in Item 7A of our Form 10-K as of October 31, 2015. Additional information concerning market risk is included in “Financial Condition and Liquidity” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 2 in this Form 10-Q.

As of January 31, 2016, we had $495 million of short-term debt outstanding as commercial paper at an interest rate of .59%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $1.1 million during the three months ended January 31, 2016.

Item 4. Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-Q. Such disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-Q, our disclosure controls and procedures were effective at the reasonable assurance level.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the first quarter of fiscal 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

We have only immaterial litigation or routine litigation in the normal course of business.

Item 1A. Risk Factors

During the three months ended January 31, 2016, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2015.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

c) Issuer Purchases of Equity Securities.

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended January 31, 2016.

Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet be Purchased Under the Program (1)
Beginning of the period					2,910,074
11/1/15 – 11/30/15	—	$	—	—	2,910,074
12/1/15 – 12/31/15	—	$	—	—	2,910,074
1/1/16 – 1/31/16	—	$	—	—	2,910,074
Total	—	$	—	—
(1) The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. 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. On that date, the Board also approved an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. 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.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain 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 January 31, 2016, our ability to pay dividends was not restricted.

Per a provision in the Merger Agreement of the proposed Acquisition with Duke Energy as discussed in Note 2 to the condensed consolidated financial statements in this Form 10-Q, our cash dividend cannot exceed the current annual per share dividend rate by more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practice. 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.

48

Item 6. Exhibits

10.1	Second Amended and Restated Credit Agreement, dated as of December 14, 2015, among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Bank of America, N.A, Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated December 16, 2015)
Compensatory Contracts:
10.2	Form of Share Repayment Agreement (LTIPs) between Piedmont Natural Gas Company, Inc. dated December 15, 2015 (substantially identical agreements have been executed with Thomas E. Skains, Karl W. Newlin, Franklin H. Yoho, Kevin M. O’Hara and Jane Lewis-Raymond) (incorporated by reference to Exhibit 10.2, Form 8-K dated December 16, 2015)
10.3	Form of Share Repayment Agreement (RSUs) between Piedmont Natural Gas Company, Inc. and Thomas E. Skains dated December 15, 2015 (incorporated by reference to Exhibit 10.3, Form 8-K dated December 16, 2015)
10.4	Form of Performance Unit Award Agreement
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.DEF	XBRL Taxonomy Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015; (3) Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016 and 2015; (4) Condensed Consolidated Statements of Cash Flows for the three months ended January 31, 2016 and 2015; (5) Condensed Consolidated Statements of Stockholders’ Equity for the three months ended January 31, 2016 and 2015; and (6) Notes to Condensed Consolidated Financial Statements.

49

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Piedmont Natural Gas Company, Inc.

(Registrant)

Date March 9, 2016	/s/ Karl W. Newlin
	Karl W. Newlin
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

Date March 9, 2016	/s/ Jose M. Simon
	Jose M. Simon
	Vice President and Controller
	(Principal Accounting Officer)

50

Piedmont Natural Gas Company, Inc.

Form 10-Q

For the Quarter Ended January 31, 2016

Exhibits

Compensatory Contract:
10.4	Form of Performance Unit Award Agreement
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer

51

EX-10.4

Exhibit 10.4

PERFORMANCE UNIT AWARD AGREEMENT

(2018 Award)

THIS PERFORMANCE UNIT AWARD AGREEMENT (this “Agreement”), made and entered into as of the 10th day of December, 2015, by and between Piedmont Natural Gas Company, Inc. (the “Company”) and ______________(“Participant”).

WITNESSETH:

WHEREAS, the Company has adopted, and its shareholders have approved, the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan (the “Plan”); and

WHEREAS, on October 15, 2015, the Compensation Committee of the Company’s Board of Directors (the “Committee”) established a three-year performance period under the Plan beginning November 1, 2015 and ending October 31, 2018 (the “2018 Award Performance Period”), and the Committee approved the award of Performance Units for the 2018 Award Performance Period; and

WHEREAS, the Participant has been awarded [•] Performance Units for the 2018 Award Performance Period.

NOW, THEREFORE, in consideration of these premises and the mutual promises contained herein, the parties hereto hereby agree as follows:

1.Subject to the provisions of Section 2 below, the Participant acknowledges that the grant and distribution of the award hereunder is governed by the terms of the Plan, and the terms of the Plan are incorporated into this Agreement in their entirety and made a part hereof by reference. Unless otherwise defined herein, capitalized terms used herein shall have the meaning set forth in the Plan. In the event of any conflict between the terms of the Plan and this Agreement, the terms of the Plan shall control.

2.The Company is party to an Agreement and Plan of Merger with Duke Energy Corporation and Forest Subsidiary, Inc. dated October 24, 2015 (the “Merger Agreement”). Section 2.3(c) of the Merger Agreement provides that if the Performance Units awarded to the Participant pursuant to this Agreement are outstanding as of the closing of the merger and other transactions contemplated by the Merger Agreement, the Performance Units will be converted into a Duke Energy retention stock unit award (“Duke Energy RSU Award”), with the number of shares of Duke Energy common stock subject to such Duke Energy RSU Award equal to 125% of the number of Performance Units multiplied by a fraction, the numerator of which is the merger consideration and the denominator of which is the average of the volume weighted averages of the trading prices of Duke Energy common stock on the New York Stock Exchange on each of the five consecutive trading days ending on (and inclusive of) the trading day that is two trading days prior to the closing date of the merger (rounded down to the nearest whole share). The Duke Energy RSU Awards will be subject to the same vesting schedule and payment terms and similar terms and conditions as apply to the Performance Units, except that the

performance-based vesting conditions will cease to apply to the Duke Energy RSU Awards and vesting will be subject to the Participant remaining continuously employed by Duke Energy or its affiliates through the date on which the 2018 Award Performance Period would have ended. The Duke Energy RSU Award will be subject to 100% accelerated vesting upon certain types of terminations of employment and prorated accelerated vesting upon retirement.

The Participant acknowledges and agrees that Section 2.3(c) of the Merger Agreement shall govern and control the conversion of the Performance Units as of the closing of the merger and other transaction contemplated by the Merger Agreement if the Performance Units are outstanding at such time notwithstanding any contrary provision of the Plan or this Agreement.

3.The percentage of the Performance Units awarded to the Participant that shall be distributed to the Participant shall depend on the levels of performance achieved during the 2018 Award Performance Period as set forth on Exhibit A attached hereto. No distributions of Performance Units shall be made with respect to a particular measure of performance if the minimum percentage of the applicable measure of performance is not achieved for the 2018 Award Performance Period as set forth on Exhibit A.

The performance levels achieved for the 2018 Award Performance Period and the percentage of Performance Units to be distributed shall be conclusively determined by the Compensation Committee of the Board of Directors.

Notwithstanding the foregoing, in the event the Participant’s employment with the Company is terminated by the Company without Cause or by the Participant for Good Reason, in either case within a period of one year following the occurrence of a Change in Control and prior to the end of the 2018 Award Performance Period, one hundred percent (100%) of the 2018 Award Performance Units awarded to the Participant hereunder shall be distributed to the Participant without any adjustment for the levels of performance actually achieved during the 2018 Award Performance Period prior to or after the Change in Control.

4.The percentage of Performance Units awarded to the Participant which the Participant shall become entitled to receive shall be distributed in the form of shares of the Company’s common stock (“Shares”), with one earned Performance Unit equal to one Share.

5.The Company shall deduct from any Shares otherwise distributable to the Participant that number of Shares having a value equal to the amount of any taxes required by law to be withheld from awards made under the Plan. The Participant may elect to have the Company withhold a greater number of Shares (up to a maximum of fifty percent (50%) of the Shares distributable to the Participant) for tax withholding.

6.The extent to which the Performance Units are forfeited or remain outstanding in the event the Participant terminates employment with the Company prior to the end of the 2018 Award Performance Period for any reason, including due to the Participant’s death, Disability or Retirement, shall be governed by the terms of the Plan.

7.No award of undistributed Performance Units hereunder to the Participant shall entitle the Participant to any rights as a shareholder of the Company.

8.The Participant’s award under the Plan may not be assigned or alienated. Subject to any limitations under the Plan on transferability, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

9.Neither the Plan, nor this Agreement, nor any action taken under the Plan or this Agreement shall be construed as giving to the Participant the right to be retained in the employ of the Company.

10.Any distribution of Shares may be delayed until the requirements of any applicable laws or regulations or any stock exchange requirements are satisfied. The Shares distributed to the Participant shall be subject to such restrictions and conditions on disposition as counsel for the Company shall determine to be desirable or necessary under applicable law.

11.The Participant may designate a beneficiary or beneficiaries to receive all or part of the Performance Units to be distributed to him/her under the Plan in case of death of the Participant. Any such Performance Units awarded under this Plan shall be distributed to the beneficiary(ies) designated in Exhibit B that is incorporated herein for all purposes. If no beneficiary(ies) is designated, such Performance Units shall be paid to the estate of the Participant.

12.The Committee shall have authority to administer and interpret the Plan and to establish rules for its administration.

13.This Agreement constitutes the entire understanding of the parties on the subjects covered. The Participant expressly warrants that he/she is not accepting this Agreement in reliance on any promises, representations, or inducements other than those contained herein. Except with respect to modifications of the Plan as provided therein, this Agreement can be amended only in writing executed by the Participant and a duly authorized officer of the Company.

14.This Agreement shall be governed by the laws of the State of North Carolina to the extent not preempted by applicable federal law.

IN WITNESS WHEREOF, the parties hereto have executed or caused this Agreement to be executed in duplicate as of the date first above written.

PIEDMONT NATURAL GAS COMPANY, INC.

By:

Chairman, President and Chief Executive Officer

By:

_______________________________________

Participant

EXHIBIT A

Performance Measures for the Three-Year Performance

Period beginning November 1, 2015 (2018 Award)

A financial performance target of [•]% compounded annual increase in basic earnings per share (“ESP Growth”) will govern [•]% of the Performance Units awarded.

Total shareholder return (“TSR”) in comparison to the designated industry peer group as approved by the Compensation Committee of the Board of Directors (increase in stock price plus dividends paid over the 2018 Award Performance Period) will govern [•]% of the Performance Units awarded.

The amount of net income returned as a percentage of shareholders equity, or return on equity (“ROE”), will govern [•]% of the Performance Units awarded.

EPS Growth ([•]% Weight)			Relative TSR ([•]% Weight)		ROE ([•]% Weight)
Actual 3-year Compounded EPS Growth %	% of Performance Units Earned	Company’s TSR as a Percentile Ranking Of Peer Group TSR		% of Performance Units Earned	Company’s ROE as a Percentage of Weighted Average Allowed ROE	% of Performance Units Earned
Less than [•]%	0%	Less than 25%		0%	Less than 95%	0%
[•]%	50%	25% - 39%		50%	95%	50%
[•]%	100%	40% - 49%		75%	100%	100%
[•]% or greater	150%	50% - 74%		100%	120% or greater	150%
		75% - 89%		125%
		90% or greater		150%

Note:    EPS Growth and ROE levels between threshold ([•]% and 95%, respectively) and stretch ([•]% and 120%, respectively) will be subject to mathematical interpolation.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Thomas E. Skains, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 9, 2016	/s/ Thomas E. Skains
		Thomas E. Skains
		Chairman of the Board, President
		and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Karl W. Newlin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 9, 2016	/s/ Karl W. Newlin
		Karl W. Newlin
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Quarterly Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-Q for the period ended January 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Skains, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

March 9, 2016

/s/ Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President and Chief Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Quarterly Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-Q for the period ended January 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Karl W. Newlin, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

March 9, 2016

/s/ Karl W. Newlin

Karl W. Newlin

Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information - shares	3 Months Ended
	Jan. 31, 2016	Mar. 01, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	PIEDMONT NATURAL GAS CO INC
Entity Central Index Key	0000078460
Document Type	10-Q
Document Period End Date	Jan. 31, 2016
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2016
Amendment Flag	false
Current Fiscal Year End Date	--10-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		81,076,199
Trading Symbol	PNY

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Jan. 31, 2016	Oct. 31, 2015
Utility Plant:
Utility plant in service		$ 5,495,303	$ 5,426,584
Less accumulated depreciation		1,278,629	1,251,940
Utility plant in service, net		4,216,674	4,174,644
Construction work in progress		204,628	170,250
Plant held for future use		3,155	3,155
Total utility plant, net		4,424,457	4,348,049
Other Physical Property, at cost (net of accumulated depreciation of $932 in 2016 and $926 in 2015		327	332
Current Assets:
Cash and cash equivalents		20,448	13,744
Trade accounts receivable(1) (less allowance for doubtful accounts of $3,762 in 2016 and $1,648 in 2015)	[1]	158,492	59,248
Income taxes receivable		12,877	11,447
Other receivables		18,701	10,667
Unbilled utility revenues		74,632	17,422
Inventories:
Gas in storage		61,135	68,240
Materials, supplies and merchandise		1,251	1,251
Gas purchase derivative assets, at fair value		1,602	1,343
Regulatory assets		61,815	10,936
Prepayments		10,697	28,903
Other current assets		271	344
Total current assets		421,921	223,545
Noncurrent Assets:
Equity method investments in non-utility activities		223,277	206,956
Goodwill		48,852	48,852
Regulatory assets		322,310	196,726
Income taxes receivable		26,023	26,023
Marketable securities, at fair value		4,842	4,666
Overfunded postretirement asset		28,620	17,770
Other noncurrent assets		5,751	5,439
Total noncurrent assets		659,675	506,432
Total		5,506,380	5,078,358
Stockholders’ equity:
Cumulative preferred stock – no par value – 175 shares authorized		0	0
Common stock - no par value - shares authorized: 200,000 shares; outstanding: 81,072 in 2016 and 80,883 in 2015		732,056	721,419
Retained earnings		776,839	705,748
Accumulated other comprehensive loss		(487)	(855)
Total stockholders’ equity		1,508,408	1,426,312
Long-term debt		1,523,896	1,523,677
Total capitalization		3,032,304	2,949,989
Current Liabilities:
Current maturities of long-term debt		40,000	40,000
Short-term debt		495,000	340,000
Trade accounts payable (1)	[1]	120,954	99,895
Other accounts payable		38,377	52,149
Accrued interest		26,293	29,488
Customers’ deposits		22,212	20,896
General taxes accrued		12,734	27,940
Gas supply derivative liabilities, at fair value		28,300	0
Regulatory liabilities		5,680	13,367
Other current liabilities		7,541	11,861
Total current liabilities		797,091	635,596
Noncurrent Liabilities:
Deferred income taxes		894,429	829,223
Unamortized federal investment tax credits		987	1,027
Accumulated provision for postretirement benefits		14,944	14,975
Gas supply derivative liabilities, at fair value		127,000	0
Regulatory liabilities		590,400	590,301
Conditional cost of removal obligations		19,984	19,712
Other noncurrent liabilities		29,241	37,535
Total noncurrent liabilities		$ 1,676,985	$ 1,492,773
Commitments and Contingencies
Total		$ 5,506,380	$ 5,078,358

[1] See Note 13 for amounts attributable to affiliates.

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals) - USD ($) $ in Thousands	Jan. 31, 2016	Oct. 31, 2015
Statement of Financial Position [Abstract]
Other Physical Property accumulated depreciation	$ 932	$ 926
Allowance for doubtful accounts	$ 3,762	$ 1,648
Cumulative preferred stock par value	$ 0	$ 0
Cumulative preferred stock shares authorized	175,000	175,000
Common stock par value per share	$ 0	$ 0
Common stock shares authorized	200,000,000	200,000,000
Common stock shares outstanding	81,072,000	80,883,000

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Jan. 31, 2016	Jan. 31, 2015
Statement of Comprehensive Income [Abstract]
Operating Revenues (1)	[1]	$ 461,337	$ 607,271
Cost of Gas (1)	[1]	175,088	337,201
Margin		286,249	270,070
Operating Expenses:
Operations and maintenance		71,300	66,150
Depreciation		33,686	31,893
General taxes		9,922	9,997
Utility income taxes		61,909	56,272
Total operating expenses		176,817	164,312
Operating Income		109,432	105,758
Other Income (Expense):
Income from equity method investments		9,202	8,265
Non-operating income		329	630
Non-operating expense		(727)	(700)
Income taxes		(3,378)	(3,264)
Total other income (expense)		5,426	4,931
Utility Interest Charges:
Interest on long-term debt		18,839	17,489
Allowance for borrowed funds used during construction		(2,805)	(2,272)
Other		1,034	2,494
Total utility interest charges		17,068	17,711
Net Income		97,790	92,978
Other Comprehensive Income (Loss), net of tax:
Unrealized loss from hedging activities of equity method investments, net of tax of ($91) and ($600) for the three months ended January 31, 2016 and 2015, respectively		(138)	(944)
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, net of tax of $327 and $75 for the three months ended January 31, 2016 and 2015, respectively		505	117
Net current period benefit activities of equity method investments, net of tax of $1 for the three months ended January 31, 2016		1	0
Total other comprehensive income (loss)		368	(827)
Comprehensive Income		$ 98,158	$ 92,151
Average Shares of Common Stock:
Basic (in shares)		80,963	78,620
Diluted (in shares)		81,266	78,945
Earnings Per Share of Common Stock:
Basic (usd per share)		$ 1.21	$ 1.18
Diluted (usd per share)		$ 1.20	$ 1.18

[1] See Note 13 for amounts attributable to affiliates.

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended
	Jan. 31, 2016	Jan. 31, 2015
Statement of Comprehensive Income [Abstract]
Unrealized loss from hedging activities of equity method investments, tax	$ (91)	$ (600)
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, tax	327	75
Net current period benefit activities of equity method investments, tax	$ 1	$ 0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Jan. 31, 2016	Jan. 31, 2015
Cash Flows from Operating Activities:
Net income	$ 97,790	$ 92,978
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	36,491	34,760
Provision for doubtful accounts	2,147	2,163
Income from equity method investments	(9,202)	(8,265)
Distributions of earnings from equity method investments	2,041	1,788
Deferred income taxes, net	64,929	53,825
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	(259)	3,885
Receivables	(166,935)	(240,738)
Inventories	7,105	(4,997)
Settlement of legal asset retirement obligations	(895)	(1,024)
Regulatory assets	(178,598)	14,561
Other assets	19,516	28,731
Accounts payable	13,516	31,655
Contributions to benefit plans	(10,132)	(10,254)
Accrued/deferred postretirement benefit costs	(748)	345
Gas supply derivatives, at fair value	155,300	0
Regulatory liabilities	(12,408)	36,369
Other liabilities	(23,761)	(14,183)
Net cash (used in) provided by operating activities	(4,103)	21,599
Cash Flows from Investing Activities:
Utility capital expenditures	(112,262)	(104,068)
Allowance for borrowed funds used during construction	(2,805)	(2,272)
Contributions to equity method investments	(9,107)	(10,019)
Distributions of capital from equity method investments	551	837
Proceeds from sale of property	308	112
Investments in marketable securities	(440)	(848)
Other	2,850	85
Net cash used in investing activities	(120,905)	(116,173)
Cash Flows from Financing Activities:
Net borrowings – commercial paper	155,000	125,000
Expenses related to issuance of debt	(1,161)	(1)
Issuance of common stock through dividend reinvestment and employee stock plans	4,653	5,106
Dividends paid	(26,729)	(25,168)
Other	(51)	(89)
Net cash provided by financing activities	131,712	104,848
Net Increase in Cash and Cash Equivalents	6,704	10,274
Cash and Cash Equivalents at Beginning of Period	13,744	9,643
Cash and Cash Equivalents at End of Period	20,448	19,917
Cash Paid During the Period for:
Interest	22,852	22,641
Income Taxes:
Income taxes paid	2,027	1,378
Income taxes refunded	173	530
Income taxes, net	1,854	848
Noncash Investing and Financing Activities:
Accrued capital expenditures	$ 52,738	$ 27,368

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Stockholders' Equity, beginning balance at Oct. 31, 2014	$ 1,308,602	$ 636,835	$ 672,004	$ (237)
Common Stock, Shares, Outstanding, Beginning Balance at Oct. 31, 2014		78,531
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	92,978		92,978
Other Comprehensive Income (Loss)	(827)			(827)
Common Stock Issued	8,995	$ 8,995
Common Stock Issued (Shares)		236
Expenses from Issuance of Common Stock	(137)	$ (137)
Tax Benefit from Dividends Paid on ESOP Shares	32		32
Dividends Declared	(25,168)		(25,168)
Common Stock, Shares, Outstanding, Ending Balance at Jan. 31, 2015		78,767
Stockholders' Equity, ending balance at Jan. 31, 2015	1,384,475	$ 645,693	739,846	(1,064)
Stockholders' Equity, beginning balance at Oct. 31, 2015	$ 1,426,312	$ 721,419	705,748	(855)
Common Stock, Shares, Outstanding, Beginning Balance at Oct. 31, 2015	80,883	80,883
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 97,790		97,790
Other Comprehensive Income (Loss)	368			368
Common Stock Issued	10,658	$ 10,658
Common Stock Issued (Shares)		189
Expenses from Issuance of Common Stock	(21)	$ (21)
Tax Benefit from Dividends Paid on ESOP Shares	30		30
Dividends Declared	$ (26,729)		(26,729)
Common Stock, Shares, Outstanding, Ending Balance at Jan. 31, 2016	81,072	81,072
Stockholders' Equity, ending balance at Jan. 31, 2016	$ 1,508,408	$ 732,056	$ 776,839	$ (487)

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parentheticals) - $ / shares	3 Months Ended
	Jan. 31, 2016	Jan. 31, 2015
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$ 0.33	$ 0.32

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Summary of Significant Accounting Policies

3 Months Ended

Jan. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Significant Accounting Policies

These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 2015. Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. There were no significant changes to those accounting policies during the three months ended January 31, 2016.

Unaudited Interim Financial Information

The condensed consolidated financial statements have not been audited. We have prepared the unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles (GAAP) in the United States of America are omitted in this interim report under these SEC rules and regulations. The unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position as of January 31, 2016 and October 31, 2015, the results of operations for three months ended January 31, 2016 and 2015, and cash flows and stockholders’ equity for the three months ended January 31, 2016 and 2015.

Seasonality and Use of Estimates

Our business is seasonal in nature. The results of operations for the three months ended January 31, 2016 do not necessarily reflect the results to be expected for the full year.

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 condensed 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.

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 (loss) (OCIL). 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. Our regulatory assets and liabilities are detailed in Note 3 to the condensed consolidated financial statements in this Form 10-Q.

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 Condensed Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option 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 Condensed Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans. As discussed below, effective in our first quarter 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.

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 for the specific instrument, location or commodity being valued. 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 maturity and settlement of our 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 fair value hierarchy levels as set forth in the fair value guidance.

For the fair value measurements of our derivatives and marketable securities, see Note 9 to the condensed consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 10 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. For further information on our fair value methodologies, see “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. Effective in our first quarter 2016, we have long-dated, fixed quantity natural gas supply contracts for our utility operations which are accounted for as derivatives. We classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we used a discounted cash flow technique to calculate our valuation. We incorporated the following inputs and assumptions in our model: contract volume, forward market prices from third party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. There were no other significant changes to these fair value methodologies during the three months ended January 31, 2016.

Recently Issued Accounting Standards Update (ASU)

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 development of guidance from our industry.

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 amendment provides 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 therein) 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 analyzing our cloud computing arrangements to identify any internal-use software and are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-01, January 2016, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The amendment addresses aspects of recognition, measurement, presentation and disclosure of financial instruments. It affects investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment.	Annual periods (and interim periods within those periods) beginning after December 15, 2017 (November 1, 2018 for us).	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for existing capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018 (November 1, 2019 for us), with early adoption permitted.	We are currently evaluating the effect on our financial position, results of operations and cash flows.

Reclassifications and Changes in Presentation

A reclassification has been made to the prior year Condensed Consolidated Balance Sheets to conform with the current year presentation. In this fiscal quarter, we early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This ASUeliminated the current requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet and replaced it with a noncurrent classification of deferred tax assets and liabilities. While the guidance would have been effective for us beginning November 1, 2017, we elected to adopt this guidance effective November 1, 2015 to simplify our presentation of deferred tax assets and liabilities.

With the adoption of the new pronouncement retrospectively, the fiscal year 2015 Condensed Consolidated Balance Sheets line item "Deferred income taxes" of $32.4 million previously included within "Current Assets" has been reclassified to net with the noncurrent line item "Deferred income taxes" as $829.2 million within "Noncurrent Liabilities." Line item "Total current assets" has been reduced by $32.4 million to $223.5 million, line item "Total noncurrent liabilities" has been reduced to $1,492.8 million, resulting in total assets and total capitalization and liabilities totaling $5,078.4 million.

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Proposed Acquisition by Duke Energy Corporation

3 Months Ended

Jan. 31, 2016

Business Combinations [Abstract]

Proposed Acquisition by Duke Energy Corporation

Proposed Acquisition by Duke Energy Corporation

On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (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).

On December 22, 2015, the Federal Trade Commission granted early termination of the 30-day waiting period for the Acquisition under the federal Hart-Scott-Rodino Antitrust Improvements Act of 1976. Expiration or termination of the waiting period is one of the conditions required for completion of the Acquisition.

For information on the January 15, 2016 filings with the North Carolina Utilities Commission (NCUC) for approval of the Acquisition and with the Tennessee Regulatory Authority (TRA) to transfer Piedmont's Tennessee operating license, see Note 3 to the condensed consolidated financial statements in this Form 10-Q.

At a specially called meeting held on January 22, 2016, the proposal to approve the Acquisition was approved by Piedmont's shareholders with a vote of 66.8% of Piedmont's outstanding shares of common stock entitled to vote. Piedmont's shareholder approval of the transaction is one of the conditions required for completion of the Acquisition.

In connection with this transaction, during the three months ended January 31, 2016, we recorded Acquisition-related integration expenses of $1.5 million for costs paid to outside parties, which are reflected in “Operations and maintenance” in “Operating Expenses” in the Condensed Consolidated Statements of Comprehensive Income. Also during this period, we recorded incremental share-based compensation expense of $4.7 million from the accelerated vesting, payment and taxation of certain share-based awards for our President and Chief Executive Officer (CEO) and other eligible officers and participants with the issuance of restricted nonvested shares of our common stock in December 2015. These share-based plan costs are reflected in "Operations and maintenance" and related payroll taxes in "General taxes" in "Operating Expenses" in the Condensed Consolidated Statements of Comprehensive Income. For further information on these accelerated share-based transactions, see Note 12 to the condensed consolidated financial statements in this Form 10-Q. These amounts do not include the cost of company personnel participating in Acquisition-related integration planning activities.

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Regulatory Matters

3 Months Ended

Jan. 31, 2016

Public Utilities, General Disclosures [Abstract]

Regulatory Matters

Regulatory Matters

Rate Regulated Basis of Accounting

Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are as follows.

In thousands	January 31, 2016		October 31, 2015
Regulatory Assets:
Current:
Unamortized debt expense on reacquired debt	$	238	$	238
Amounts due from customers	22,956		—
Environmental costs	1,522		1,513
Deferred operations and maintenance expenses	860		847
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,757
Robeson liquefied natural gas (LNG) development costs	382		381
Derivatives - gas supply contracts held for utility operations	28,300		—
Other	1,330		1,730
Total current	61,815		10,936
Noncurrent:
Unamortized debt expense on reacquired debt	4,607		4,666
Environmental costs	4,587		5,107
Deferred operations and maintenance expenses	3,777		3,997
Deferred pipeline integrity expenses	29,767		29,824
Deferred pension and other retirement benefit costs	18,887		17,861
Amounts not yet recognized as a component of pension and other retirement benefit costs	113,197		114,854
Regulatory cost of removal asset	19,363		19,087
Robeson LNG development costs	32		127
Derivatives - gas supply contracts held for utility operations	127,000		—
Other	1,093		1,203
Total noncurrent	322,310		196,726
Total	$	384,125	$	207,662

Regulatory Liabilities:
Current:
Amounts due to customers	$	5,680	$	13,367
Noncurrent:
Regulatory cost of removal obligations	526,299		521,478
Deferred income taxes	64,019		68,738
Amounts not yet recognized as a component of pension and other retirement benefit costs	82		85
Total noncurrent	590,400		590,301
Total	$	596,080	$	603,668

Rate Oversight and Rate and Regulatory Actions

North Carolina

In November 2015, we filed a petition with the NCUC seeking authority, under the approved integrity management riders (IMR) settlement agreement and procedural schedule, to change our rates effective December 1, 2015 to collect a total of $40.9 million in annual IMR margin revenues, representing an additional $13.4 million in annual IMR margin revenues from rate adjustments approved by the NCUC in its January 2015 order. The rate adjustment was 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 December 2015, the NCUC approved the requested IMR rate increase. In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers over December 2015 through May 2016, which we began recording in our first quarter 2016.

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.

In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. A hearing has been scheduled for July 18, 2016 on this matter.

South Carolina

In June 2015, we filed with the Public Service Commission of South Carolina (PSCSC) a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study as permitted under the Natural Gas Rate Stabilization Act requesting a change in our rates from those approved by the PSCSC in its October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff 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 January 2016, we and Duke Energy discussed the Acquisition of Piedmont by Duke Energy with the PSCSC pursuant to its procedures for an allowable ex-parte communication briefing in accordance with state statute. The PSCSC's approval of the Acquisition is not required.

Tennessee

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 Tennessee Incentive Plan (TIP). We are waiting on a ruling from the TRA at this time.

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 Actual Cost Adjustment (ACA) mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order.

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 IMR-eligible capital investments in integrity and safety projects over the twelve-month period ended October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016.

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 Tennessee Consumer Advocate stipulating that we refund the $4.7 million to customers over a twelve-month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve-month period beginning January 2016. In February 2016, the TRA issued its written order on this matter.

In January 2016, we and Duke Energy filed a joint application with the TRA seeking approval on or before April 30, 2016 of a transfer of Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statute due to the change in control. We are waiting on a ruling by the TRA at this time.

In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in a deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

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Earnings Per Share

3 Months Ended

Jan. 31, 2016

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 plan (ICP) awards 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 any FSAs settle, for the three months ended January 31, 2016 and 2015 is presented below.

	Three Months
In thousands, except per share amounts	2016		2015
Net Income	$	97,790	$	92,978
Average shares of common stock outstanding for basic earnings per share	80,963		78,620
Contingently issuable shares under ICP awards	117		325
Contingently issuable restricted nonvested shares under accelerated ICP awards	182		—
Contingently issuable shares under FSAs	4		—
Average shares of dilutive stock	81,266		78,945
Earnings Per Share of Common Stock:
Basic	$	1.21	$	1.18
Diluted	$	1.20	$	1.18

We accelerated the issuance of shares of common stock under approved ICP awards as permitted under the terms of the Merger Agreement. This acceleration resulted in the issuance of 181,944 restricted nonvested shares of our common stock in December 2015, plus 1,092 restricted nonvested shares of our common stock from the reinvestment of dividends on these shares in January 2016. These restricted nonvested shares of our common stock are included in the calculation of diluted earnings per share in the table above but excluded in basic earnings per share and shares of our common stock outstanding because of their restricted nonvested nature. For further information on the acceleration of these shares of our common stock under our employee share-based plans, see Note 12 to the condensed consolidated financial statements in this Form 10-Q.

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Long Term Debt Instruments

3 Months Ended

Jan. 31, 2016

Long-term Debt, Unclassified [Abstract]

Long-Term Debt Instruments

Long-Term Debt Instruments

The NCUC approved debt and equity issuances under an effective debt and equity shelf registration statement up to $1 billion through June 6, 2017. As of January 31, 2016, we have $544.1 million remaining for debt and equity issuances as approved by the NCUC. For further information on equity transactions, see Note 7 to the condensed consolidated financial statements in this Form 10-Q. 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.

Our long-term debt as of January 31, 2016 and October 31, 2015 is presented below.

In thousands	January 31, 2016			October 31, 2015
Principal	$	1,575,000		$	1,575,000
Unamortized debt issuance expenses and discounts	(11,104		)	(11,323		)
Total	1,563,896			1,563,677
Less current maturities	40,000			40,000
Total long-term debt	$	1,523,896		$	1,523,677

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.

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Short Term Debt Instruments

3 Months Ended

Jan. 31, 2016

Line of Credit Facility [Abstract]

Short-Term Debt Instruments

Short-Term Debt Instruments

On December 14, 2015, we amended and restated the agreement underlying our $850 million five-year revolving syndicated credit facility as an $850 million five-year revolving syndicated credit facility that expires on December 14, 2020 and has an option to request an expansion up to an additional $200 million. 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 was issued and outstanding as of January 31, 2016 and October 31, 2015. 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 112.5 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020, provided that we are in compliance with all terms of the agreement.

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 period.

As of January 31, 2016, we had $495 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Condensed Consolidated Balance Sheets, with original maturities ranging from 11 to 17 days from their dates of issuance at a weighted average interest rate of .57%. As of October 31, 2015, our outstanding notes under the CP program, included in the Condensed Consolidated Balance Sheets as stated above, were $340 million at a weighted average interest rate of .22%.

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2016. A summary of the short-term debt activity under our CP program for the three months ended January 31, 2016 is as follows.

In millions	Three Months
Minimum amount outstanding during period	$	340
Maximum amount outstanding during period	$	500
Minimum interest rate during period	.20		%
Maximum interest rate during period	.75		%
Weighted average interest rate during period	.44		%

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at January 31, 2016.

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Stockholders' Equity

3 Months Ended

Jan. 31, 2016

Stockholders' Equity Note [Abstract]

Stockholders' Equity

Stockholders’ Equity

Capital Stock

Changes in common stock for the three months ended January 31, 2016 are as follows.

In thousands	Shares	Amount
Balance, October 31, 2015	80,883	$	721,419
Issued to participants in the Employee Stock Purchase Plan (ESPP)	6	342
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan	77	4,260
Issued to participants in the ICP	106	6,056
Costs from issuance of common stock		(21		)
Balance, January 31, 2016	81,072	$	732,056

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 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 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 through July 31, 2016.

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 JP Morgan on January 4, 2016, 360,000 shares were borrowed from third parties and sold by JP Morgan, from January 4, 2016 to January 28, 2016, at a weighted average share price of $57.90, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $57.04.

Under the terms of this FSA, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation under the agreement. We expect to settle by delivering shares. At our election, we intend to physically settle the shares under this agreement prior to the closing date of the Acquisition or October 31, 2016, whichever occurs first.

In accordance with accounting guidance, we have classified the FSA as an equity transaction because the FSA is indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts will be recorded in the consolidated financial statements until settlement of the FSA.

Upon physical settlement of the FSA, delivery of our shares will result in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSA on our EPS could occur during periods when the average market price per share of our common stock is above the per share adjusted forward sale price described above. See Note 4 to the condensed consolidated financial statements in this Form 10-Q for the dilutive effect of the FSA on our EPS at January 31, 2016 with the inclusion of the incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

If we had settled the FSA by delivery of the 360,000 shares of our common stock to the forward counterparty as of January 31, 2016, we would have received net proceeds of approximately $20.5 million based on the net settlement price of $57.03 per share. Upon settlement, we intend to use the net proceeds from this FSA to finance capital expenditures, to repay outstanding short-term unsecured notes under our CP program and for general corporate purposes.

Cash dividends paid per share of common stock for the three months ended January 31, 2016 and 2015 are as follows.

	Three Months
	2016		2015
Cash dividends paid per share of common stock	$	0.33	$	0.32

Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and benefit activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 13 to the condensed consolidated financial statements in this Form 10-Q. Changes in each component of accumulated OCIL are presented below for the three months ended January 31, 2016 and 2015.

	Changes in Accumulated OCIL(1)
	Three Months
In thousands	2016			2015
Accumulated OCIL beginning balance, net of tax	$	(855	)	$	(237	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(138		)	(944		)
Amounts reclassified from accumulated OCIL, net of tax	505			117
Total current period activity of hedging activities of equity method investments, net of tax	367			(827		)
Net current period benefit activities of equity method investments, net of tax	1			—
Accumulated OCIL ending balance, net of tax	$	(487	)	$	(1,064	)
(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 three months ended January 31, 2016 and 2015.

	Reclassification Out of Accumulated OCIL (1)						Affected Line Items on Condensed Statements of Comprehensive Income
	Three Months
In thousands	2016			2015
Hedging activities of equity method investments	$	832		$	192		Income from equity method investments
Income tax expense	(327		)	(75		)	Income taxes
Hedging activities of equity method investments	505			117
Net benefit activities of equity method investments	2			—			Income from equity method investments
Income tax expense	(1		)	—			Income taxes
Net benefit activities of equity method investments	1			—
Total reclassification for the period, net of tax	$	506		$	117
(1) Amounts in parentheses indicate debits to accumulated OCIL.

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Marketable Securities

3 Months Ended

Jan. 31, 2016

Marketable Securities [Abstract]

Marketable Securities

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 11 to the condensed consolidated financial statements in this Form 10-Q.

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 Condensed 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 the noncurrent deferred compensation liability with the noncurrent asset; the current asset portion is included in “Other current assets” in “Current Assets” in the Condensed 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 January 31, 2016 and October 31, 2015 is as follows.

	January 31, 2016				October 31, 2015
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	28	$	28	$	51	$	51
Mutual funds	77		109		114		185
Total current trading securities	105		137		165		236
Noncurrent trading securities:
Money markets	536		536		465		465
Mutual funds	4,233		4,306		3,625		4,201
Total noncurrent trading securities	4,769		4,842		4,090		4,666
Total trading securities	$	4,874	$	4,979	$	4,255	$	4,902

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Financial Instruments & Related Fair Value

3 Months Ended

Jan. 31, 2016

Financial Instruments And 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 with the purchase of call option derivatives. 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 gas purchase 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 January 31, 2016 and October 31, 2015, we had long gas purchase options providing total coverage of 33.6 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held at January 31, 2016 are for the period from March 2016 through January 2017.

Derivative Assets and Liabilities - Gas Supply Contracts

We enter into forward gas supply contracts to provide diversification, reliability and gas cost benefits to our customers as part of our diversified gas supply portfolio. We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. Effective in the period ended January 31, 2016, we have certain forward gas supply contracts that meet the definition of derivative instruments that should be recorded at fair value. We have included gas supply contracts requiring fair value accounting in "Gas supply derivative liabilities, at fair value" in "Current Liabilities" and "Noncurrent Liabilities" in the Condensed Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our purchased gas adjustment (PGA) clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.

Fair Value Measurements and Quantitative and Qualitative Disclosures

We use purchased call options as 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. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these contracts that became effective in the period ended January 31, 2016 should be recorded at fair value. We classify fair value balances based on the observance of 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 in our Form 10-K for the year ended October 31, 2015. For an updated discussion of our fair value methodology, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2016 and October 31, 2015. 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 three months ended January 31, 2016 and 2015. 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 purchased call option 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 purchased call option derivatives held for utility operations. Our purchased call option derivatives held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivatives presented at fair value that are held for our utility operations.

Recurring Fair Value Measurements as of January 31, 2016
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - purchased call options held for utility operations	$	1,602	$	—	$	—	$	—	$	1,602
Debt and equity securities held as trading securities:
Money markets	564		—		—		—		564
Mutual funds	4,415		—		—		—		4,415
Total fair value assets	$	6,581	$	—	$	—	$	—	$	6,581
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	155,300	$	—	$	155,300

Recurring Fair Value Measurements 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)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - purchased call options held for utility 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

In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our derivative gas supply contracts in the mid to later years of contract terms ranged from $2.84 to $4.37 per dekatherm.

The fair value of our derivative gas supply contracts is sensitive to the pricing differential of various natural gas indexes relevant to those particular contracts. An increased market price spread between the indexes would increase the fair value of the derivative and result in an unrealized loss, while conversely, a decreased market price spread would decrease the fair value of the derivative and result in an unrealized gain.

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy.

In thousands
Balance, October 31, 2015	$	—
Realized and unrealized gains (losses):
Recorded to regulatory assets	(155,300		)
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Balance, January 31, 2016	$	(155,300	)

Our regulated utility segment purchased call option 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 condensed consolidated financial statements in this Form 10-Q. 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.

Our gas supply derivatives are generally based on unobservable inputs and are classified within Level 3. In accordance with regulatory provisions for rate-regulated activities, any gains and losses associated with these derivatives are reflected as a regulatory asset or liability, as appropriate, in "Derivatives - gas supply contracts held for utility operations" in Note 3 to the condensed consolidated financial statements in this Form 10-Q.

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 Condensed 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 presented at net cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The principal and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.

In thousands	Principal		Fair Value
As of January 31, 2016	$	1,575,000	$	1,734,319
As of October 31, 2015	1,575,000		1,720,586

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 purchased call option 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 and gas supply contracts for natural gas as of January 31, 2016 and October 31, 2015.

Fair Value of Derivative Instruments
	January 31,		October 31,
In thousands	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (March 2016 - January 2017)	$	1,602
Current Assets – Gas purchase derivative assets (December 2015 - October 2016)			$	1,343
Liability Financial Instruments:
Current Liabilities – Gas supply derivative liabilities	$	28,300
Noncurrent Liabilities – Gas supply derivative liabilities	127,000

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 of the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 3 to the condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed 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 our gas purchase option financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.

	Amount of Loss Recognized on Derivative Instruments and Deferred Under PGA Procedures						Location of Loss Recognized through PGA Procedures
	Three Months Ended   January 31
In thousands	2016			2015
Purchased call options	$	(1,901	)	$	(558	)	Cost of Gas

In Tennessee, the cost of purchased call 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 purchased call 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.

We would have recorded an unrealized loss of $155.3 million related to our gas supply derivatives in the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas supply derivatives in the Condensed Consolidated Statements of Comprehensive Income as a component of "Cost of Gas" in the month purchased.

Credit and Counterparty Risk

Information regarding our credit and counterparty risk is set forth in Note 8 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. During the three months ended January 31, 2016, there were no material changes in our credit and counterparty risk.

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 Condensed Consolidated Balance Sheets attributable to these entities amounted to $18.6 million, or approximately 11%, of our gross trade accounts receivable as of January 31, 2016. 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.

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.

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Commitments and Contingent Liabilities

3 Months Ended

Jan. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingent Liabilities

Commitments and Contingent Liabilities

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 fully recoverable subject to 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 of reservation fees 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 Federal Energy Regulatory Commission (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 Condensed Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

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.

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 as of January 31, 2016. Additional information concerning letters of credit is included in Note 6 to the condensed consolidated financial statements in this Form 10-Q.

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 January 31, 2016, 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). There were no material changes in the status of environmental-related matters during the three months ended January 31, 2016.

As of January 31, 2016, our estimated undiscounted environmental liability totaled $1 million, and consisted of $.9 million for MGP sites for which we retain responsibility and $.1 million for the USTs and the Huntersville LNG facility. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

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.

Additional information concerning commitments and contingencies is set forth in Note 9 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2015.

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Employee Benefit Plans

3 Months Ended

Jan. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). 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 and dental expenses.

Beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We decided to replace the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. We made 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 did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended January 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2016			2015			2016		2015		2016			2015
Service cost	$	2,750		$	3,050		$	—	$	—	$	294		$	295
Interest cost	2,400			2,975			40		52		321			369
Expected return on plan assets	(6,000		)	(5,925		)	—		—		(442		)	(459		)
Amortization of prior service (credit) cost	(550		)	(550		)	52		58		(83		)	—
Amortization of actuarial loss	2,100			2,050			20		21		115			7
Total	$	700		$	1,600		$	112	$	131	$	205		$	212

In November 2015, we contributed $10 million to the qualified pension plan, and in January 2016, we contributed $1.8 million to the money purchase pension plan. During the three months ended January 31, 2016, we contributed $.1 million to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans in 2016.

In thousands
Nonqualified pension plans	$	389
OPEB plan	1,300

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. For the three months ended January 31, 2016, we contributed $.5 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As of January 31, 2016, we have a liability of $5 million for these plans.

See Note 8 and Note 9 to the condensed consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trusts.

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Employee Share-Based Plans

3 Months Ended

Jan. 31, 2016

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 three months ended January 31, 2016 and 2015, we recorded compensation expense, and as of January 31, 2016 and October 31, 2015, 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. The award with the performance period that ended October 31, 2015 was paid out to participants in December 2015. Two other awards with performance periods ending October 31, 2016 (2016 plan) and October 31, 2017 (2017 plan) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.

Also under our approved ICP, 64,700 nonvested restricted stock units (RSUs) were granted to our President and CEO in December 2011. During the five-year vesting period, any dividend equivalents accrue on these stock units and are 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 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 and 30% of the units vested on December 15, 2015. The remaining 50% of the units that vest on December 15, 2016 (2016 RSU) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below. For the three months ended January 31, 2016 and 2015, we recorded compensation expense, and as of January 31, 2016 and October 31, 2015, we accrued a liability for nonvested RSUs, as applicable, based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value each quarter and at the settlement date.

The December 15, 2015 vesting covered 30% of the grant, including accrued dividends, for a total of 22,434 shares of 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.

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2016 and 2015, 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 Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are presented below.

	Three Months
In thousands	2016		2015
Compensation expense	$	6,230	$	2,230

	January 31, 2016		October 31, 2015
Liability	$	8,036	$	22,037

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 2016 RSU for our President and CEO (accelerated RSU) 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 nonvested 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 Internal Revenue Code of 1986, as amended, 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 2016 RSU, 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 2016 RSU, 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 restricted nonvested 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 nonvested 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. In accordance with accounting guidance, we have not presented these restricted nonvested shares as shares outstanding or included them in our calculation of basic EPS as they are contingent shares until earned; as applicable, they are included in our calculation of diluted EPS in Note 4 to the condensed consolidated financial statements in this Form 10-Q. The participants otherwise have all rights of shareholders with respect to the restricted nonvested shares of common stock.

The accelerated ICP awards and the accelerated RSU were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted nonvested 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 2016 RSU, 19,554 restricted nonvested 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 issued for the accelerated RSU 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 fair market value is determined by calculating the average of the high and low trading prices on the purchase date.

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Equity Method Investments

3 Months Ended

Jan. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Equity Method Investments

The condensed 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 Condensed Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Condensed Consolidated Statements of Comprehensive Income.

Ownership Interests

We have the following membership interests in these companies as of January 31, 2016 and October 31, 2015, respectively.

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 approximately 600 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 diverse northeastern 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 Condensed 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 Condensed Consolidated Statements of Comprehensive Income.

Related Party Transactions

We have related party transactions as a customer of our investments. For each period of the three months ended January 31, 2016 and 2015, these gas costs and the amounts we owed to our equity method investees, as of January 31, 2016 and October 31, 2015 are as follows.

Related Party	Type of Expense	Cost of Gas (1)				Trade accounts payable (2)
		Three Months				January 31,		October 31,
In thousands		2016		2015		2016		2015
Cardinal	Transportation costs	$	2,203	$	2,214	$	740	$	744
Hardy Storage	Gas storage costs	2,322		2,322		774		774
Pine Needle	Gas storage costs	2,834		2,936		955		955
Totals		$	7,359	$	7,472	$	2,469	$	2,473
(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

We have related party transactions as we sell wholesale gas supplies to SouthStar. For each period of the three months ended January 31, 2016 and 2015, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2016 and October 31, 2015 are as follows.

	Operating Revenues (1)				Trade accounts receivable (2)
	Three Months				January 31,		October 31,
In thousands	2016		2015		2016		2015
Operating revenues	$	57	$	396	$	54	$	183
(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

Other Information

SouthStar

In accordance with the SouthStar limited liability company agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to Georgia Natural Gas Company (GNGC). On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective with the consummation of the Acquisition. On February 12, 2016, we entered into a letter agreement with GNGC for the purchase of our interest for $160 million cash. The letter agreement provides that we and GNGC will execute a definitive agreement for the purchase, which will include the satisfaction of customary closing conditions and obtaining regulatory approvals or consents necessary to consummate the purchase of our interest, including approval from the Georgia Public Service Commission.

Constitution

A subsidiary of The Williams Companies is the operator of the pipeline. The total estimated cost of the project is $977 million, including an allowance for funds used during construction (AFUDC).

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 $857 million, excluding AFUDC, in total. Our total anticipated contributions are approximately $205.8 million. As of January 31, 2016, our fiscal year contributions were $4.7 million, with our total equity contribution for the project totaling $77.3 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 second half of 2017, reflecting a delay in the issuance of remaining outstanding permits. The capacity of the pipeline is 100% subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

ACP

A subsidiary of Dominion Resources, Inc. is the operator of the pipeline. The total cost of 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.

We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline. As of January 31, 2016, our fiscal year contributions were $4.4 million, with our total equity contributions for the project totaling $15.1 million to date.

ACP is regulated by the FERC and subject to state and other federal approvals with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by affiliates of the members of ACP and another utility under twenty-year contracts.

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 that grant Dominion an option to purchase additional ownership interests in ACP from Duke Energy to maintain a majority ownership percentage relative to all other members. After consummation of the Acquisition, Duke Energy, together with our ownership, would have a 50% membership interest unless Dominion exercises its option.

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Variable Interest Entities

3 Months Ended

Jan. 31, 2016

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Variable Interest Entities

Variable Interest Entities

As of January 31, 2016, we have determined that we are not the primary beneficiary under variable interest entity (VIE) accounting guidance in any of our equity method investments, as presented in Note 13 to the condensed consolidated financial statements in this Form 10-Q. 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 Condensed Consolidated Balance Sheets. As of January 31, 2016 and October 31, 2015, our investment balances are as follows.

In thousands	January 31, 2016		October 31, 2015
Cardinal	$	14,928	$	15,083
Pine Needle	18,118		18,396
SouthStar	46,207		41,325
Hardy Storage	40,389		39,706
Constitution	88,968		82,403
ACP	14,667		10,043
Total equity method investments in non-utility activities	$	223,277	$	206,956

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.

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Business Segments

3 Months Ended

Jan. 31, 2016

Segment Reporting [Abstract]

Business Segments

Business Segments

We have three reportable business segments, regulated utility, regulated non-utility 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.

Operations of the regulated utility segment are reflected in “Operating Income” in the Condensed Consolidated Statements of Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Condensed Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”

Our chief operating decision maker is the executive management team. We produce consolidated financial information internally that is supplemented with separate non-utility activity reporting that is used regularly to make operating decisions and assess performance of our three business segments. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the regulated and unregulated non-utility activities segments based on earnings and cash flows from the ventures.

The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements in our Form 10-K for the year ended October 31, 2015.

Operations by segment for the three months ended January 31, 2016 and 2015 are presented below.

	Regulated Utility				Regulated Non-Utility Activities						Unregulated Non-Utility Activities						Total
In thousands	2016		2015		2016			2015			2016			2015			2016		2015
Revenues from external customers	$	461,337	$	607,271	$	—		$	—		$	—		$	—		$	461,337	$	607,271
Margin	286,249		270,070		—			—			—			—			286,249		270,070
Operations and maintenance expenses	71,300		66,150		16			31			55			38			71,371		66,219
Income from equity method investments	—		—		4,692			3,771			4,510			4,494			9,202		8,265
Operating income (loss) before income taxes	171,341		162,030		(16		)	(31		)	(139		)	(121		)	171,186		161,878
Income before income taxes	154,030		144,401		4,676			3,740			4,371			4,373			163,077		152,514

Reconciliations to the condensed consolidated statements of comprehensive income for the three months ended January 31, 2016 and 2015 are presented below.

	Three Months
In thousands	2016			2015
Operating Income:
Segment operating income before income taxes	$	171,186		$	161,878
Utility income taxes	(61,909		)	(56,272		)
Regulated non-utility activities operating loss before income taxes	16			31
Unregulated non-utility activities operating loss before income taxes	139			121
Operating income	$	109,432		$	105,758

Net Income:
Income before income taxes for reportable segments	$	163,077		$	152,514
Income taxes	(65,287		)	(59,536		)
Total	$	97,790		$	92,978

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Subsequent Events

3 Months Ended

Jan. 31, 2016

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 and equity method investments, see Note 3 and Note 13, respectively, to the condensed consolidated financial statements in this Form 10-Q.

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Summary Of Significant Accounting Policies (Policies)

3 Months Ended

Jan. 31, 2016

Accounting Policies [Abstract]

Unaudited Interim Financial Information and Seasonality

Our business is seasonal in nature. The results of operations for the three months ended January 31, 2016 do not necessarily reflect the results to be expected for the full year.

The condensed consolidated financial statements have not been audited. We have prepared the unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles (GAAP) in the United States of America are omitted in this interim report under these SEC rules and regulations.

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 condensed 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.

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.

Fair Value Measurements

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 for the specific instrument, location or commodity being valued. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

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 Condensed Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option 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 Condensed Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans. As discussed below, effective in our first quarter 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.

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 plan (ICP) awards 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.

Marketable Securities

The fair values of the equity securities are based on quoted market prices as traded on the exchanges.

Trading securities are recorded at fair value on the Condensed Consolidated Balance Sheets with any gains or losses recognized currently in earnings.

Derivatives

We have included gas supply contracts requiring fair value accounting in "Gas supply derivative liabilities, at fair value" in "Current Liabilities" and "Noncurrent Liabilities" in the Condensed Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our purchased gas adjustment (PGA) clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.

We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes.

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.

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Summary Of Significant Accounting Policies (Tables)

3 Months Ended

Jan. 31, 2016

Accounting Policies [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

Recently Issued Accounting Standards Update (ASU)

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 development of guidance from our industry.

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 amendment provides 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 therein) 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 analyzing our cloud computing arrangements to identify any internal-use software and are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-01, January 2016, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The amendment addresses aspects of recognition, measurement, presentation and disclosure of financial instruments. It affects investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment.	Annual periods (and interim periods within those periods) beginning after December 15, 2017 (November 1, 2018 for us).	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for existing capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018 (November 1, 2019 for us), with early adoption permitted.	We are currently evaluating the effect on our financial position, results of operations and cash flows.

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Regulatory Matters Regulatory Matters (Tables)

3 Months Ended

Jan. 31, 2016

Regulated Operations [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are as follows.

In thousands	January 31, 2016		October 31, 2015
Regulatory Assets:
Current:
Unamortized debt expense on reacquired debt	$	238	$	238
Amounts due from customers	22,956		—
Environmental costs	1,522		1,513
Deferred operations and maintenance expenses	860		847
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,757
Robeson liquefied natural gas (LNG) development costs	382		381
Derivatives - gas supply contracts held for utility operations	28,300		—
Other	1,330		1,730
Total current	61,815		10,936
Noncurrent:
Unamortized debt expense on reacquired debt	4,607		4,666
Environmental costs	4,587		5,107
Deferred operations and maintenance expenses	3,777		3,997
Deferred pipeline integrity expenses	29,767		29,824
Deferred pension and other retirement benefit costs	18,887		17,861
Amounts not yet recognized as a component of pension and other retirement benefit costs	113,197		114,854
Regulatory cost of removal asset	19,363		19,087
Robeson LNG development costs	32		127
Derivatives - gas supply contracts held for utility operations	127,000		—
Other	1,093		1,203
Total noncurrent	322,310		196,726
Total	$	384,125	$	207,662

Schedule of Regulatory Liabilities

Regulatory Liabilities:
Current:
Amounts due to customers	$	5,680	$	13,367
Noncurrent:
Regulatory cost of removal obligations	526,299		521,478
Deferred income taxes	64,019		68,738
Amounts not yet recognized as a component of pension and other retirement benefit costs	82		85
Total noncurrent	590,400		590,301
Total	$	596,080	$	603,668

Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are as follows.

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Earnings Per Share (Tables)

3 Months Ended

Jan. 31, 2016

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 any FSAs settle, for the three months ended January 31, 2016 and 2015 is presented below.

	Three Months
In thousands, except per share amounts	2016		2015
Net Income	$	97,790	$	92,978
Average shares of common stock outstanding for basic earnings per share	80,963		78,620
Contingently issuable shares under ICP awards	117		325
Contingently issuable restricted nonvested shares under accelerated ICP awards	182		—
Contingently issuable shares under FSAs	4		—
Average shares of dilutive stock	81,266		78,945
Earnings Per Share of Common Stock:
Basic	$	1.21	$	1.18
Diluted	$	1.20	$	1.18

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Long Term Debt Instruments Long Term Debt (Tables)

3 Months Ended

Jan. 31, 2016

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments

Our long-term debt as of January 31, 2016 and October 31, 2015 is presented below.

In thousands	January 31, 2016			October 31, 2015
Principal	$	1,575,000		$	1,575,000
Unamortized debt issuance expenses and discounts	(11,104		)	(11,323		)
Total	1,563,896			1,563,677
Less current maturities	40,000			40,000
Total long-term debt	$	1,523,896		$	1,523,677

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Short Term Debt Instruments (Tables)

3 Months Ended

Jan. 31, 2016

Line of Credit Facility [Abstract]

Schedule of Line of Credit Facilities

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2016. A summary of the short-term debt activity under our CP program for the three months ended January 31, 2016 is as follows.

In millions	Three Months
Minimum amount outstanding during period	$	340
Maximum amount outstanding during period	$	500
Minimum interest rate during period	.20		%
Maximum interest rate during period	.75		%
Weighted average interest rate during period	.44		%

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Stockholders' Equity (Tables)

3 Months Ended

Jan. 31, 2016

Stockholders' Equity Note [Abstract]

Schedule Of Capital Stock

Changes in common stock for the three months ended January 31, 2016 are as follows.

In thousands	Shares	Amount
Balance, October 31, 2015	80,883	$	721,419
Issued to participants in the Employee Stock Purchase Plan (ESPP)	6	342
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan	77	4,260
Issued to participants in the ICP	106	6,056
Costs from issuance of common stock		(21		)
Balance, January 31, 2016	81,072	$	732,056

Dividends Paid

Cash dividends paid per share of common stock for the three months ended January 31, 2016 and 2015 are as follows.

	Three Months
	2016		2015
Cash dividends paid per share of common stock	$	0.33	$	0.32

Accumulated Other Comprehensive Income (Loss)

Changes in each component of accumulated OCIL are presented below for the three months ended January 31, 2016 and 2015.

	Changes in Accumulated OCIL(1)
	Three Months
In thousands	2016			2015
Accumulated OCIL beginning balance, net of tax	$	(855	)	$	(237	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(138		)	(944		)
Amounts reclassified from accumulated OCIL, net of tax	505			117
Total current period activity of hedging activities of equity method investments, net of tax	367			(827		)
Net current period benefit activities of equity method investments, net of tax	1			—
Accumulated OCIL ending balance, net of tax	$	(487	)	$	(1,064	)
(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 three months ended January 31, 2016 and 2015.

	Reclassification Out of Accumulated OCIL (1)						Affected Line Items on Condensed Statements of Comprehensive Income
	Three Months
In thousands	2016			2015
Hedging activities of equity method investments	$	832		$	192		Income from equity method investments
Income tax expense	(327		)	(75		)	Income taxes
Hedging activities of equity method investments	505			117
Net benefit activities of equity method investments	2			—			Income from equity method investments
Income tax expense	(1		)	—			Income taxes
Net benefit activities of equity method investments	1			—
Total reclassification for the period, net of tax	$	506		$	117
(1) Amounts in parentheses indicate debits to accumulated OCIL.

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Marketable Securities (Tables)

3 Months Ended

Jan. 31, 2016

Marketable Securities [Abstract]

Composition of Marketable Securities

The composition of these securities as of January 31, 2016 and October 31, 2015 is as follows.

	January 31, 2016				October 31, 2015
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	28	$	28	$	51	$	51
Mutual funds	77		109		114		185
Total current trading securities	105		137		165		236
Noncurrent trading securities:
Money markets	536		536		465		465
Mutual funds	4,233		4,306		3,625		4,201
Total noncurrent trading securities	4,769		4,842		4,090		4,666
Total trading securities	$	4,874	$	4,979	$	4,255	$	4,902

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Financial Instruments & Related Fair Value (Tables)

3 Months Ended

Jan. 31, 2016

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]

Assets And Liabilities Measured And Recorded At Fair Value On Recurring Basis

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2016 and October 31, 2015.

Recurring Fair Value Measurements as of January 31, 2016
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - purchased call options held for utility operations	$	1,602	$	—	$	—	$	—	$	1,602
Debt and equity securities held as trading securities:
Money markets	564		—		—		—		564
Mutual funds	4,415		—		—		—		4,415
Total fair value assets	$	6,581	$	—	$	—	$	—	$	6,581
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	155,300	$	—	$	155,300

Recurring Fair Value Measurements 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)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - purchased call options held for utility 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

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy.

In thousands
Balance, October 31, 2015	$	—
Realized and unrealized gains (losses):
Recorded to regulatory assets	(155,300		)
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Balance, January 31, 2016	$	(155,300	)

Fair Value By Balance Sheet Grouping

The principal and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.

In thousands	Principal		Fair Value
As of January 31, 2016	$	1,575,000	$	1,734,319
As of October 31, 2015	1,575,000		1,720,586

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following table presents the impact that our gas purchase option financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.

	Amount of Loss Recognized on Derivative Instruments and Deferred Under PGA Procedures						Location of Loss Recognized through PGA Procedures
	Three Months Ended   January 31
In thousands	2016			2015
Purchased call options	$	(1,901	)	$	(558	)	Cost of Gas

The following table presents the fair value and balance sheet classification of our financial options and gas supply contracts for natural gas as of January 31, 2016 and October 31, 2015.

Fair Value of Derivative Instruments
	January 31,		October 31,
In thousands	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (March 2016 - January 2017)	$	1,602
Current Assets – Gas purchase derivative assets (December 2015 - October 2016)			$	1,343
Liability Financial Instruments:
Current Liabilities – Gas supply derivative liabilities	$	28,300
Noncurrent Liabilities – Gas supply derivative liabilities	127,000

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Employee Benefit Plans (Tables)

3 Months Ended

Jan. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Components Of Net Periodic Benefit Cost

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended January 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2016			2015			2016		2015		2016			2015
Service cost	$	2,750		$	3,050		$	—	$	—	$	294		$	295
Interest cost	2,400			2,975			40		52		321			369
Expected return on plan assets	(6,000		)	(5,925		)	—		—		(442		)	(459		)
Amortization of prior service (credit) cost	(550		)	(550		)	52		58		(83		)	—
Amortization of actuarial loss	2,100			2,050			20		21		115			7
Total	$	700		$	1,600		$	112	$	131	$	205		$	212

Anticipated Employer Contribution To Benefit Plans

We anticipate that we will contribute the following additional amounts to our plans in 2016.

In thousands
Nonqualified pension plans	$	389
OPEB plan	1,300

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Employee Share-Based Plans (Tables)

3 Months Ended

Jan. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Compensation Expense and Liabilities

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2016 and 2015, 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 Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are presented below.

	Three Months
In thousands	2016		2015
Compensation expense	$	6,230	$	2,230

	January 31, 2016		October 31, 2015
Liability	$	8,036	$	22,037

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Equity Method Investments (Tables)

3 Months Ended

Jan. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investments

For each period of the three months ended January 31, 2016 and 2015, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2016 and October 31, 2015 are as follows.

	Operating Revenues (1)				Trade accounts receivable (2)
	Three Months				January 31,		October 31,
In thousands	2016		2015		2016		2015
Operating revenues	$	57	$	396	$	54	$	183
(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

For each period of the three months ended January 31, 2016 and 2015, these gas costs and the amounts we owed to our equity method investees, as of January 31, 2016 and October 31, 2015 are as follows.

Related Party	Type of Expense	Cost of Gas (1)				Trade accounts payable (2)
		Three Months				January 31,		October 31,
In thousands		2016		2015		2016		2015
Cardinal	Transportation costs	$	2,203	$	2,214	$	740	$	744
Hardy Storage	Gas storage costs	2,322		2,322		774		774
Pine Needle	Gas storage costs	2,834		2,936		955		955
Totals		$	7,359	$	7,472	$	2,469	$	2,473
(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

We have the following membership interests in these companies as of January 31, 2016 and October 31, 2015, respectively.

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 approximately 600 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 diverse northeastern gas supplies into southeastern markets; regulated by the FERC

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Variable Interest Entities (Tables)

3 Months Ended

Jan. 31, 2016

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Schedule Of Variable Interest Entities Investment Balances

As of January 31, 2016 and October 31, 2015, our investment balances are as follows.

In thousands	January 31, 2016		October 31, 2015
Cardinal	$	14,928	$	15,083
Pine Needle	18,118		18,396
SouthStar	46,207		41,325
Hardy Storage	40,389		39,706
Constitution	88,968		82,403
ACP	14,667		10,043
Total equity method investments in non-utility activities	$	223,277	$	206,956

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Business Segments (Tables)

3 Months Ended

Jan. 31, 2016

Segment Reporting [Abstract]

Operations By Segment

Operations by segment for the three months ended January 31, 2016 and 2015 are presented below.

	Regulated Utility				Regulated Non-Utility Activities						Unregulated Non-Utility Activities						Total
In thousands	2016		2015		2016			2015			2016			2015			2016		2015
Revenues from external customers	$	461,337	$	607,271	$	—		$	—		$	—		$	—		$	461,337	$	607,271
Margin	286,249		270,070		—			—			—			—			286,249		270,070
Operations and maintenance expenses	71,300		66,150		16			31			55			38			71,371		66,219
Income from equity method investments	—		—		4,692			3,771			4,510			4,494			9,202		8,265
Operating income (loss) before income taxes	171,341		162,030		(16		)	(31		)	(139		)	(121		)	171,186		161,878
Income before income taxes	154,030		144,401		4,676			3,740			4,371			4,373			163,077		152,514

Reconciliation of Operating Profit (Loss) from Segments to Consolidated

Reconciliations to the condensed consolidated statements of comprehensive income for the three months ended January 31, 2016 and 2015 are presented below.

	Three Months
In thousands	2016			2015
Operating Income:
Segment operating income before income taxes	$	171,186		$	161,878
Utility income taxes	(61,909		)	(56,272		)
Regulated non-utility activities operating loss before income taxes	16			31
Unregulated non-utility activities operating loss before income taxes	139			121
Operating income	$	109,432		$	105,758

Net Income:
Income before income taxes for reportable segments	$	163,077		$	152,514
Income taxes	(65,287		)	(59,536		)
Total	$	97,790		$	92,978

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Summary Of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Jan. 31, 2016	Oct. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Current deferred income taxes		$ 32,400
Noncurrent deferred income taxes	$ 894,429	829,223
Total current assets	421,921	223,545
Total noncurrent liabilities	1,676,985	1,492,773
Total capitalization and liabilities	$ 5,506,380	5,078,358
New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Noncurrent deferred income taxes		829,200
Total current assets		223,500
Total noncurrent liabilities		1,492,800
Total capitalization and liabilities		5,078,400
Deferred Tax Asset [Domain] | New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (Decrease) In Total Assets And Liabilities		$ (32,400)

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Proposed Acquisition by Duke Energy Corporation (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Jan. 31, 2016	Jan. 22, 2016	Oct. 24, 2015
Business Combinations [Abstract]
Business Acquisition, Date of Acquisition Agreement	Oct. 24, 2015
Business Acquisition, Share Price			$ 60
Shareholder Approval Vote, Percentage Amount		66.80%
Business Combination, Acquisition Related Costs	$ 1.5
Business Acquisition, Incremental Share Based Compensation, Acceleration	$ 4.7

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Regulatory Matters - Assets and Liabilities (Details) - USD ($) $ in Thousands	Jan. 31, 2016	Oct. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory liabilities - current	$ 5,680	$ 13,367
Regulatory liabilities - noncurrent	590,400	590,301
Regulatory liabilities, Total	596,080	603,668
Regulatory Assets [Line Items]
Regulatory assets - current	61,815	10,936
Regulatory assets - noncurrent	322,310	196,726
Regulatory assets, Total	384,125	207,662
Amounts due to customers
Regulatory Liabilities [Line Items]
Regulatory liabilities - current	5,680	13,367
Regulatory cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities - noncurrent	526,299	521,478
Deferred income taxes
Regulatory Liabilities [Line Items]
Regulatory liabilities - noncurrent	64,019	68,738
Amounts not yet recognized as a component of pension and other retirement benefit costs
Regulatory Liabilities [Line Items]
Regulatory liabilities - noncurrent	82	85
Unamortized debt expense on reacquired debt
Regulatory Assets [Line Items]
Regulatory assets - current	238	238
Regulatory assets - noncurrent	4,607	4,666
Amounts due from customers
Regulatory Assets [Line Items]
Regulatory assets - current	22,956	0
Environmental costs
Regulatory Assets [Line Items]
Regulatory assets - current	1,522	1,513
Regulatory assets - noncurrent	4,587	5,107
Deferred operations and maintenance expenses
Regulatory Assets [Line Items]
Regulatory assets - current	860	847
Regulatory assets - noncurrent	3,777	3,997
Deferred pipeline integrity expenses
Regulatory Assets [Line Items]
Regulatory assets - current	3,470	3,470
Regulatory assets - noncurrent	29,767	29,824
Deferred pension and other retirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets - current	2,757	2,757
Regulatory assets - noncurrent	18,887	17,861
Amounts not yet recognized as a component of pension and other retirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets - noncurrent	113,197	114,854
Regulatory cost of removal
Regulatory Assets [Line Items]
Regulatory assets - noncurrent	19,363	19,087
Robeson liquefied natural gas (LNG) development costs
Regulatory Assets [Line Items]
Regulatory assets - current	382	381
Regulatory assets - noncurrent	32	127
Derivatives - gas supply contracts held for utility operations
Regulatory Assets [Line Items]
Regulatory assets - current	28,300	0
Regulatory assets - noncurrent	127,000	0
Other
Regulatory Assets [Line Items]
Regulatory assets - current	1,330	1,730
Regulatory assets - noncurrent	$ 1,093	$ 1,203

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Regulatory Matters - Rate and Regulatory Actions (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	11 Months Ended	12 Months Ended
	Feb. 29, 2016	Jan. 31, 2016	Sep. 30, 2015	Oct. 31, 2015
NORTH CAROLINA
Public Utilities, Rate Matters, Approved [Abstract]
Capital Investments In Integrity and Safety Projects			$ 161,900
TENNESSEE
Public Utilities, Rate Matters, Approved [Abstract]
Capital Investments In Integrity and Safety Projects				$ 18,400
North Carolina Utilities Commission | NCUC Petition Filed IMR November 2015
Public Utilities, Rate Matters, Requested [Abstract]
Annual Requested Integrity Management Rider, Amount		$ 40,900
Public Utilities Requested Rate Increase (Decrease) Amount		$ 13,400
North Carolina Utilities Commission | North Carolina Public Staff Audit 2015 Gas Cost Review Period
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs		100.00%
North Carolina Utilities Commission | Subsequent Event | NCUC Public Staff Audit Report February 2016
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Disclosure of Rate Matters	In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers over December 2015 through May 2016, which we began recording in our first quarter 2016.
Public Service Commission of South Carolina [Member] | Settlement With Office Of Regulatory Staff October 2015
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities Approved Rate Increase (Decrease) Amount		$ 1,650
Public Utilities, Approved Return on Equity, Percentage		10.20%
Tennessee Regulatory Authority | TRA Petition Filed IMR November 2015
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities Requested Rate Increase (Decrease) Amount		$ 1,700
Tennessee Regulatory Authority | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities Approved Rate Increase (Decrease) Amount		(4,700)
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities Requested Rate Increase (Decrease) Amount		$ (4,700)
Tennessee Regulatory Authority | Subsequent Event | TRA Approved Actual Cost Adjustment February 2016
Public Utilities, Rate Matters, Approved [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 Actual Cost Adjustment (ACA) mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order.
Tennessee Regulatory Authority | Subsequent Event | TRA Approved IMR December 2015
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Disclosure of Rate Matters	In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016.
Tennessee Regulatory Authority | Subsequent Event | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Disclosure of Rate Matters	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 Tennessee Consumer Advocate stipulating that we refund the $4.7 million to customers over a twelve-month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve-month period beginning January 2016. In February 2016, the TRA issued its written order on this matter.
Tennessee Regulatory Authority | Subsequent Event | TRA ACA Petition Filed February 2016
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Disclosure of Rate Matters	In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in a deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Jan. 31, 2016	Jan. 31, 2015	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income	$ 97,790	$ 92,978
Average shares of common stock outstanding for basic earnings per share	80,963,000	78,620,000
Contingently issuable shares under ICP awards	117,000	325,000
Contingently issuable restricted nonvested shares under accelerated ICP awards	182,000	0
Contingently issuable shares under FSAs	4,000	0
Average shares of dilutive stock	81,266,000	78,945,000
Basic (usd per share)	$ 1.21	$ 1.18
Diluted (usd per share)	$ 1.20	$ 1.18
Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Stock Outstanding, Shares, Restricted, Nonvested Stock Award			181,944
Stock Outstanding, Shares, Restricted Stock Awards, Dividend Reinvestment	1,092

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Long-term Debt Instruments (Details) - USD ($)	3 Months Ended
	Jan. 31, 2016	Oct. 31, 2015
Debt Instrument [Line Items]
Principal	$ 1,575,000,000	$ 1,575,000,000
Current maturities of long-term debt	40,000,000	40,000,000
Long-term Debt, excluding Current Maturities	1,523,896,000	1,523,677,000
New Accounting Pronouncement, Early Adoption, Effect
Debt Instrument [Line Items]
Long-term Debt, excluding Current Maturities	1,523,896,000	1,523,677,000
Unsecured Debt | New Accounting Pronouncement, Early Adoption, Effect
Debt Instrument [Line Items]
Principal	1,575,000,000	1,575,000,000
Unamortized debt issuance expenses and discounts	(11,104,000)	(11,323,000)
Total Long-term Debt	1,563,896,000	$ 1,563,677,000
North Carolina Utilities Commission
Debt Instrument [Line Items]
Public Utilities, Approved Debt Equity Securities Limit, Amount	1,000,000,000
Public Utilities, Approved Debt Equity Securities Limit, Amount Remaining	$ 544,100,000

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Short Term Debt Instruments (Details)	3 Months Ended
	Jan. 31, 2016 USD ($)	Dec. 14, 2015 USD ($)	Oct. 31, 2015 USD ($)
Line Of Credit Facility [Line Items]
Credit Facility Current Borrowing Capacity	$ 850,000,000
Commercial Paper	$ 495,000,000		$ 340,000,000
Revolving Credit Facility
Line Of Credit Facility [Line Items]
Line of Credit Facility, Initiation Date	Dec. 14, 2015
Credit Facility Current Borrowing Capacity		$ 850,000,000
Line of Credit Facility, Expiration Date	Dec. 14, 2020
Line Of Credit Facility, Optional Additional Expansion Amount	$ 200,000,000
Line Of Credit Facility Frequency Of Commitment Fee Payment	annual
Line of Credit Facility, Commitment Fee Description	$35,000 plus 8.5 basis points
Credit Facility Interest Rate Description	30-day London Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.085%
Line of Credit Facility, Commitment Fee Amount	$ 35,000
Minimum amount outstanding during period	0
Maximum amount outstanding during period	$ 0
Credit Facility Covenant Terms	total debt to total capitalization of no greater than 70%
Credit Facility Covenant Compliance	actual ratio was 58%
Debt Covenant Total Debt To Total Capital Ratio	70.00%
Ratio of Indebtedness to Net Capital	0.58
Revolving Credit Facility | Minimum | London Interbank Offered Rate (LIBOR)
Line Of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
Revolving Credit Facility | Maximum | London Interbank Offered Rate (LIBOR)
Line Of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%
Letter Of Credit
Line Of Credit Facility [Line Items]
Credit Facility Current Borrowing Capacity	$ 10,000,000		10,000,000
Letters of Credit Outstanding, Amount	1,600,000		$ 1,600,000
Commercial Paper
Line Of Credit Facility [Line Items]
Credit Facility Current Borrowing Capacity	$ 850,000,000
Credit Facility Interest Rate Description	interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points
Short Term Borrowings Term	$850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt.
Maximum Number Of Possible Days Outstanding For Commercial Paper Program	397 days
Weighted Average Interest Rate	0.57%		0.22%
Minimum amount outstanding during period	$ 340,000,000
Maximum amount outstanding during period	$ 500,000,000
Commercial Paper | Base Rate
Line Of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.05%
Commercial Paper | Minimum
Line Of Credit Facility [Line Items]
Debt Instrument, Term	11 days
Line of Credit Facility Interest Rate During Period	0.20%
Commercial Paper | Maximum
Line Of Credit Facility [Line Items]
Debt Instrument, Term	17 days
Line of Credit Facility Interest Rate During Period	0.75%
Commercial Paper | Weighted Average
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.44%

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Stockholders' Equity (Details) - USD ($)		1 Months Ended	3 Months Ended
	Jan. 07, 2015	Jan. 28, 2016	Jan. 31, 2016	Jan. 31, 2015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Beginning Balance			80,883,000
Common Stock, Value, Issued, Beginning Balance			$ 721,419,000
Issued to participants in the Employee Stock Purchase Plan (ESPP) (in shares)			6,000
Issued to participants in the Employee Stock Purchase Plan (ESPP)			$ 342,000
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (in shares)			77,000
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan			$ 4,260,000
Issued to participants in the Incentive Compensation Plan (ICP) (in shares)			106,000
Issued to participants in the ICP			$ 6,056,000
Costs from issuance of common stock			$ (21,000)	$ (137,000)
Common Stock, Shares, Outstanding, Ending Balance			81,072,000
Common Stock, Value, Issued, Ending Balance			$ 732,056,000
ATM Sales Agreement Aggregate Amount	$ 170,000,000
ATM Sales Agreement Commission Percentage			1.50%
Cash dividends paid per share of common stock (usd per share)			$ 0.33	$ 0.32
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		360,000
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share		$ 57.90
Initial Forward Price Per Share		$ 57.04
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives			Under the terms of this FSA, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation under the agreement.
Forward Contract Indexed to Issuer's Equity, Classification			we have classified the FSA as an equity transaction because the FSA is indexed to our own stock and physical settlement is within our control
Forward Contract Amount Recorded in Consolidated Financial Statements			$ 0
Forward Contract Indexed to Issuer's Equity, Indexed Shares			360,000
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value			$ 20,500,000
Net Settlement Price Per Share			$ 57.03
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from equity method investments			$ (9,202,000)	$ (8,265,000)
Income taxes			3,378,000	3,264,000
Net income			(97,790,000)	(92,978,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated OCIL beginning balance, net of tax			(855,000)	(237,000)
Total other comprehensive income (loss)			368,000	(827,000)
Accumulated OCIL ending balance, net of tax			(487,000)	(1,064,000)
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income			$ 506,000	117,000
Maximum
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Settlement Date			Oct. 31, 2016
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
OCIL before reclassifications, net of tax			$ (138,000)	(944,000)
Amounts reclassified from accumulated OCIL, net of tax			505,000	117,000
Total other comprehensive income (loss)			367,000	(827,000)
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			832,000	192,000
Income taxes			(327,000)	(75,000)
Net income			505,000	117,000
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Total other comprehensive income (loss)			1,000	0
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			2,000	0
Income taxes			(1,000)	0
Net income			$ 1,000	$ 0

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Marketable Securities (Details) - USD ($) $ in Thousands	Jan. 31, 2016	Oct. 31, 2015
Schedule of Trading Securities and Other Trading Assets [Line Items]
Current trading securities (cost)	$ 105	$ 165
Noncurrent trading securities (cost)	4,769	4,090
Current trading securities (fair value)	137	236
Noncurrent trading securities (fair value)	4,842	4,666
Total trading securities (cost)	4,874	4,255
Total trading (fair value)	4,979	4,902
Money markets
Schedule of Trading Securities and Other Trading Assets [Line Items]
Current trading securities (cost)	28	51
Noncurrent trading securities (cost)	536	465
Current trading securities (fair value)	28	51
Noncurrent trading securities (fair value)	536	465
Mutual funds
Schedule of Trading Securities and Other Trading Assets [Line Items]
Current trading securities (cost)	77	114
Noncurrent trading securities (cost)	4,233	3,625
Current trading securities (fair value)	109	185
Noncurrent trading securities (fair value)	$ 4,306	$ 4,201

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Financial Instruments & Related Fair Value (Details) MMBTU in Millions	3 Months Ended
	Jan. 31, 2016 USD ($) MMBTU $ / MMBTU	Jan. 31, 2015 USD ($)	Oct. 31, 2015 USD ($) MMBTU
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value measurement transfers between levels activity	$ 0	$ 0
Assets, Fair Value Disclosure
Debt and equity securities held as trading securities	4,979,000		$ 4,902,000
Fair Value, Derivative Liability Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Gas supply derivative liabilities, beginning balance	0
Unrealized gains (losses) recorded to regulatory assets	(155,300,000)
Purchases, sales and settlements (net)	0
Transfer in/out of Level 3	0
Gas supply derivative liabilities, ending balance	(155,300,000)
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, carry amount	1,575,000,000		1,575,000,000
Current Assets - Gas purchase derivative assets	1,602,000		1,343,000
Current Liabilities - Gas supply derivative liabilities	28,300,000		0
Noncurrent Liabilities - Gas supply derivative liabilities	$ 127,000,000		0
Percentage of annual gas costs approved for recovery under TIP	1.00%
Concentration Risk [Line Items]
Concentration risk, description	“Trade accounts receivable” in “Current Assets” in the Condensed Consolidated Balance Sheets
Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Total fair value assets	$ 6,581,000		6,245,000
Money markets | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Debt and equity securities held as trading securities	564,000		516,000
Mutual funds | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Debt and equity securities held as trading securities	$ 4,415,000		$ 4,386,000
Call Option Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long gas purchase options providing total coverage | MMBTU	33.6		34.7
Collateral, Obligation to Return Cash	$ 0		$ 0
Collateral, Right to Reclaim Cash	0		0
Liabilities, Fair Value Disclosure
Derivative Liability	0		0
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Current Assets - Gas purchase derivative assets	1,602,000		1,343,000
Purchased call options	(1,901,000)	(558,000)
Amount Of Gain (Loss) Deferred Under PGA Procedures	(1,901,000)	$ (558,000)
Call Option Derivatives | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Derivatives - purchased call options held for utility operations	1,602,000		1,343,000
Gas Supply Contracts
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Current Liabilities - Gas supply derivative liabilities	28,300,000
Noncurrent Liabilities - Gas supply derivative liabilities	127,000,000
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss)	$ 155,300,000
Gas Supply Contracts | Minimum
Liabilities, Fair Value Disclosure
Fair Value Inputs, Price Per Dekatherm | $ / MMBTU	2.84
Gas Supply Contracts | Maximum
Liabilities, Fair Value Disclosure
Fair Value Inputs, Price Per Dekatherm | $ / MMBTU	4.37
Gas Supply Contracts | Fair Value, Measurements, Recurring
Liabilities, Fair Value Disclosure
Derivative Liability	$ 155,300,000
Quoted Prices in Active Markets (Level 1) | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Total fair value assets	6,581,000		6,245,000
Quoted Prices in Active Markets (Level 1) | Money markets | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Debt and equity securities held as trading securities	564,000		516,000
Quoted Prices in Active Markets (Level 1) | Mutual funds | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Debt and equity securities held as trading securities	4,415,000		4,386,000
Quoted Prices in Active Markets (Level 1) | Call Option Derivatives | Fair Value, Measurements, Recurring
Assets, Fair Value Disclosure
Derivatives - purchased call options held for utility operations	1,602,000		1,343,000
Significant Other Observable Inputs (Level 2)
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, fair value	1,734,319,000		$ 1,720,586,000
Significant Unobservable Inputs (Level 3) | Gas Supply Contracts | Fair Value, Measurements, Recurring
Liabilities, Fair Value Disclosure
Derivative Liability	155,300,000
Accounts Receivable
Concentration Risk [Line Items]
Concentration risk amount	$ 18,600,000
Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	11.00%

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Commitments and Contingent Liabilities (Details) $ in Millions	3 Months Ended
	Jan. 31, 2016 USD ($) regulatory_commission
Site Contingency [Line Items]
Accrual For Environmental Loss Contingencies Gross	$ 1.0
Long-term Purchase Commitment [Line Items]
Number Of Regulatory Commissions | regulatory_commission	3
Letter Of Credit
Guarantor Obligations [Line Items]
Total contingent obligation	$ 1.6
Surety Bond
Guarantor Obligations [Line Items]
Total contingent obligation	6.6
Manufactured Gas Plant Sites
Site Contingency [Line Items]
Accrual For Environmental Loss Contingencies Gross	0.9
Other Environmental Remediation Sites
Site Contingency [Line Items]
Accrual For Environmental Loss Contingencies Gross	$ 0.1
Pipeline And Storage Capacity Contacts | Maximum
Long-term Purchase Commitment [Line Items]
Long term purchase commitment time period	20 years
Reservation Fees Under Gas Supply Contracts | Maximum
Long-term Purchase Commitment [Line Items]
Long term purchase commitment time period	2 years
Gas Supply Purchase Commitments | Maximum
Long-term Purchase Commitment [Line Items]
Long term purchase commitment time period	15 years
Telecommunications And Technology Outsourcing Contracts | Maximum
Long-term Purchase Commitment [Line Items]
Long term purchase commitment time period	5 years

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Employee Benefit Plans (Details) - USD ($)	1 Months Ended		3 Months Ended
	Jan. 31, 2016	Nov. 30, 2015	Jan. 31, 2016	Jan. 31, 2015
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Deferred Compensation Liability	$ 5,000,000		$ 5,000,000
Defined Contribution Restoration Plan
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Employer Contribution to Plan - deferred compensation			500,000
Voluntary Deferral Plan
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Employer Contribution to Plan - deferred compensation			0
Pension Plan | MPP Plan
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution to Plan - defined contribution	$ 1,800,000
Qualified Pension Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			2,750,000	$ 3,050,000
Interest cost			2,400,000	2,975,000
Expected return on plan assets			(6,000,000)	(5,925,000)
Amortization of prior service (credit) cost			(550,000)	(550,000)
Amortization of actuarial loss			2,100,000	2,050,000
Total			700,000	1,600,000
Employer contribution amount - defined benefit		$ 10,000,000
Non Qualified Pension
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			0	0
Interest cost			40,000	52,000
Expected return on plan assets			0	0
Amortization of prior service (credit) cost			52,000	58,000
Amortization of actuarial loss			20,000	21,000
Total			112,000	131,000
Additional contribution amounts			389,000
Employer contribution amount - defined benefit			100,000
Other Postretirement Benefit Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			294,000	295,000
Interest cost			321,000	369,000
Expected return on plan assets			(442,000)	(459,000)
Amortization of prior service (credit) cost			(83,000)	0
Amortization of actuarial loss			115,000	7,000
Total			205,000	$ 212,000
Additional contribution amounts			$ 1,300,000

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Employee Share-Based Plans (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended	3 Months Ended
	Dec. 15, 2015	Dec. 31, 2011	Jan. 31, 2016	Jan. 31, 2015	Dec. 14, 2015	Oct. 31, 2015	Oct. 24, 2015
Employee Share Based Plans Details [Line Items]
Compensation expense			$ 6,230	$ 2,230
Liability			$ 8,036			$ 22,037
Business Acquisition, Share Price							$ 60
ESPP exercise price as a percent			95.00%
Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Performance period			3 years
Share Price					$ 56.85
Retention Stock Unit Award President And Chief Executive Officer | Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Unvested Shares Issued To CEO		64,700
Retention stock unit award vesting period			5 years
Incentive Compensation Plan Percentage Of Common Stock Vested			In accordance with the vesting schedule, 20% of the units vested on December 15, 2014 and 30% of the units vested on December 15, 2015. The remaining 50% of the units that vest on December 15, 2016 (2016 RSU) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.
Retention Stock Unit Award President And Chief Executive Officer | Vested on December 15, 2014 | Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Common stock vesting percentage			20.00%
Retention Stock Unit Award President And Chief Executive Officer | Vest on December 15, 2015 | Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Stock Award Vested, Shares, Gross	22,434
Payments Related to Tax Withholding for Share-based Compensation	$ 600
Stock Issued During Period, Shares, Share-based Compensation, Gross	11,732
Share Price					$ 56.85
Common stock vesting percentage			30.00%
Retention Stock Unit Award President And Chief Executive Officer | Vest on December 15, 2016 | Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Stock Issued During Period, Shares, Restricted Nonvested Stock Award	19,554
Stock Issued During Period, Value, Restricted, Nonvested Stock Award	$ 1,100
Value Of Incentive Compensation Plan Award Issued Gross	$ 2,100
Common stock vesting percentage			50.00%
Long Term Incentive Plan Three Performance Measures | Stock Compensation Plan
Employee Share Based Plans Details [Line Items]
Acceleration And Payout Election Rate	96.00%
Stock Issued During Period, Shares, Restricted Nonvested Stock Award	162,390
Value of Incentive Compensation Plan Award Gross	$ 17,400
Stock Issued During Period, Value, Restricted, Nonvested Stock Award	$ 9,200

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Equity Method Investments (Details) - USD ($)		3 Months Ended
	Feb. 12, 2016	Jan. 31, 2016	Jan. 31, 2015	Oct. 31, 2015
Schedule of Equity Method Investments [Line Items]
Related party costs		$ 7,359,000	$ 7,472,000
Trade accounts payable		2,469,000		$ 2,473,000
Contributions to equity method investments		$ 9,107,000	10,019,000
Cardinal Pipeline Company
Schedule of Equity Method Investments [Line Items]
Membership interest percentage		21.49%
Related party costs		$ 2,203,000	2,214,000
Trade accounts payable		$ 740,000		744,000
Pine Needle Company
Schedule of Equity Method Investments [Line Items]
Membership interest percentage		45.00%
Related party costs		$ 2,834,000	2,936,000
Trade accounts payable		$ 955,000		955,000
South Star Energy Services
Schedule of Equity Method Investments [Line Items]
Membership interest percentage		15.00%
Operating revenues		$ 57,000	396,000
Trade accounts receivable		$ 54,000		183,000
Hardy Storage
Schedule of Equity Method Investments [Line Items]
Membership interest percentage		50.00%
Related party costs		$ 2,322,000	$ 2,322,000
Trade accounts payable		$ 774,000		$ 774,000
Constitution Pipeline Company
Schedule of Equity Method Investments [Line Items]
Membership interest percentage		24.00%
Estimated Pipeline Costs Including AFUDC		$ 977,000,000
Estimated Pipeline Costs Excluding AFUDC		857,000,000
Estimated Contributions For Pipeline And Construction Costs		205,800,000
Contributions to equity method investments		4,700,000
Total equity contribution for the project		$ 77,300,000
Target Pipeline In Service Date		2017
Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Membership interest percentage		10.00%
Contributions to equity method investments		$ 4,400,000
Total equity contribution for the project		$ 15,100,000
Target Pipeline In Service Date		2018
Long term purchase commitment time period		20 years
Estimated Percentage Project Financing		60.00%
Estimated Percentage Debt Financing		50.00%
Estimated Percentage Equity Financing		50.00%
Funding Obligation Under Equity Contribution Agreements		$ 15,200,000
Minimum | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs		4,500,000,000
Maximum | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs		$ 5,000,000,000
Subsequent Event | South Star Energy Services
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, subject to and effective with the consummation of the Acquisition. On February 12, 2016, we entered into a letter agreement with GNGC for the purchase of our interest for $160 million cash. The letter agreement provides that we and GNGC will execute a definitive agreement for the purchase, which will include the satisfaction of customary closing conditions and obtaining regulatory approvals or consents necessary to consummate the purchase of our interest, including approval from the Georgia Public Service Commission.
Equity Method Investment Agreement To Sell Interest	$ 160,000,000

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Variable Interest Entities (Details) - Variable Interest Entity, Not Primary Beneficiary - USD ($) $ in Thousands	Jan. 31, 2016	Oct. 31, 2015
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	$ 223,277	$ 206,956
Cardinal Pipeline Company
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	14,928	15,083
Pine Needle Company
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	18,118	18,396
South Star Energy Services
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	46,207	41,325
Hardy Storage
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	40,389	39,706
Constitution Pipeline Company
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	88,968	82,403
Atlantic Coast Pipeline
Variable Interest Entity [Line Items]
Total equity method investments in non-utility activities	$ 14,667	$ 10,043

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Business Segments (Details) $ in Thousands		3 Months Ended
		Jan. 31, 2016 USD ($) segment	Jan. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment		3
Segment Reporting Information [Abstract]
Revenues from external customers	[1]	$ 461,337	$ 607,271
Margin		286,249	270,070
Operations and maintenance expenses		71,371	66,219
Income from equity method investments		9,202	8,265
Operating income (loss) before income taxes		171,186	161,878
Income before income taxes for reportable segments		163,077	152,514
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes		171,186	161,878
Utility income taxes		(61,909)	(56,272)
Operating income		109,432	105,758
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments		163,077	152,514
Income taxes		(65,287)	(59,536)
Net Income		97,790	92,978
Regulated Utility
Segment Reporting Information [Abstract]
Revenues from external customers		461,337	607,271
Margin		286,249	270,070
Operations and maintenance expenses		71,300	66,150
Income from equity method investments		0	0
Operating income (loss) before income taxes		171,341	162,030
Income before income taxes for reportable segments		154,030	144,401
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes		171,341	162,030
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments		154,030	144,401
Regulated Non-Utility Activities
Segment Reporting Information [Abstract]
Revenues from external customers		0	0
Margin		0	0
Operations and maintenance expenses		16	31
Income from equity method investments		4,692	3,771
Operating income (loss) before income taxes		(16)	(31)
Income before income taxes for reportable segments		4,676	3,740
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes		(16)	(31)
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments		4,676	3,740
Unregulated Non-Utility Activities
Segment Reporting Information [Abstract]
Revenues from external customers		0	0
Margin		0	0
Operations and maintenance expenses		55	38
Income from equity method investments		4,510	4,494
Operating income (loss) before income taxes		(139)	(121)
Income before income taxes for reportable segments		4,371	4,373
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes		(139)	(121)
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments		$ 4,371	$ 4,373

[1] See Note 13 for amounts attributable to affiliates.