PIEDMONT NATURAL GAS CO INC - FORM 10-Q

Attached files

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EX-10.2 - EXHIBIT 10.2 - PIEDMONT NATURAL GAS CO INC	a20150731exhibit102.htm
EX-32.1 - EXHIBIT 32.1 - PIEDMONT NATURAL GAS CO INC	a20150731exhibit321.htm
EX-31.2 - EXHIBIT 31.2 - PIEDMONT NATURAL GAS CO INC	a20150731exhibit312.htm
EX-10.1 - EXHIBIT 10.1 - PIEDMONT NATURAL GAS CO INC	a20150731exhibit101.htm
EX-32.2 - EXHIBIT 32.2 - PIEDMONT NATURAL GAS CO INC	a20150731exhibit322.htm
EX-31.1 - EXHIBIT 31.1 - PIEDMONT NATURAL GAS CO INC	a20150731exhibit311.htm

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 July 31, 2015

¨ 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 September 1, 2015
Common Stock, no par value		79,205,112

Table of Contents

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 31, 2015

TABLE OF CONTENTS



		Page

Part I.	Financial Information

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations and 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	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	48

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

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)



	July 31, 2015		October 31, 2014
ASSETS
Utility Plant:
Utility plant in service	$	5,251,808	$	5,011,497
Less accumulated depreciation	1,244,236		1,166,922
Utility plant in service, net	4,007,572		3,844,575
Construction work in progress	214,507		141,693
Plant held for future use	3,155		3,155
Total utility plant, net	4,225,234		3,989,423
Other Physical Property, at cost (net of accumulated depreciation of $921 in 2015 and $904 in 2014	338		355
Current Assets:
Cash and cash equivalents	10,664		9,643
Trade accounts receivable(1) (less allowance for doubtful accounts of $2,971 in 2015 and $2,152 in 2014)	61,999		65,260
Income taxes receivable	10,679		36,100
Other receivables	6,887		3,361
Unbilled utility revenues	1,730		21,093
Inventories:
Gas in storage	64,205		84,081
Materials, supplies and merchandise	1,254		1,652
Gas purchase derivative assets, at fair value	1,140		4,898
Regulatory assets	12,434		29,088
Prepayments	24,419		39,030
Deferred income taxes	26,526		53,418
Other current assets	360		326
Total current assets	222,297		347,950
Noncurrent Assets:
Equity method investments in non-utility activities	195,812		170,171
Goodwill	48,852		48,852
Regulatory assets	179,187		184,779
Income taxes receivable	25,875		—
Marketable securities, at fair value	4,755		3,727
Overfunded postretirement asset	43,901		33,757
Other noncurrent assets	5,182		5,239
Total noncurrent assets	503,564		446,525
Total	$	4,951,433	$	4,784,253

⁽¹⁾ See Note 12 for amounts attributable to affiliates.

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)



	July 31, 2015			October 31, 2014
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: 79,195 in 2015 and 78,531 in 2014	660,721			636,835
Retained earnings	745,968			672,004
Accumulated other comprehensive loss	(628		)	(237		)
Total stockholders’ equity	1,406,061			1,308,602
Long-term debt	1,384,450			1,424,430
Total capitalization	2,790,511			2,733,032
Current Liabilities:
Current maturities of long-term debt	40,000			—
Short-term debt	370,000			355,000
Trade accounts payable ⁽¹⁾	88,123			85,299
Other accounts payable	40,783			54,349
Accrued interest	24,068			27,982
Customers’ deposits	20,770			19,994
General taxes accrued	21,041			23,828
Regulatory liabilities	34,815			46,231
Other current liabilities	7,215			9,303
Total current liabilities	646,815			621,986
Noncurrent Liabilities:
Deferred income taxes	861,947			809,467
Unamortized federal investment tax credits	1,067			1,193
Accumulated provision for postretirement benefits	15,383			15,471
Regulatory liabilities	587,648			558,598
Conditional cost of removal obligations	15,344			14,647
Other noncurrent liabilities	32,718			29,859
Total noncurrent liabilities	1,514,107			1,429,235
Commitments and Contingencies (Note 9)
Total	$	4,951,433		$	4,784,253

⁽¹⁾ See Note 12 for amounts attributable to affiliates.

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)



	Three Months Ended July 31						Nine Months Ended July 31
	2015			2014			2015			2014
Operating Revenues ⁽¹⁾	$	158,266		$	164,187		$	1,190,462		$	1,284,167
Cost of Gas ⁽¹⁾	46,694			59,340			583,199			706,285
Margin	111,572			104,847			607,263			577,882
Operating Expenses:
Operations and maintenance	69,587			68,605			207,162			199,437
Depreciation	32,317			29,960			95,900			87,947
General taxes	11,532			9,352			32,504			27,958
Utility income taxes	(7,097		)	(6,324		)	85,583			89,668
Total operating expenses	106,339			101,593			421,149			405,010
Operating Income	5,233			3,254			186,114			172,872
Other Income (Expense):
Income from equity method investments	5,801			5,043			29,908			29,345
Non-operating income	673			862			1,934			66
Non-operating expense	(1,196		)	(1,660		)	(3,093		)	(3,711		)
Income taxes	(2,097		)	(1,718		)	(11,277		)	(10,050		)
Total other income (expense)	3,181			2,527			17,472			15,650
Utility Interest Charges:
Interest on long-term debt	17,483			14,920			52,432			45,416
Allowance for borrowed funds used during construction	(2,859		)	(4,543		)	(7,935		)	(15,960		)
Other	2,050			2,748			7,969			6,298
Total utility interest charges	16,674			13,125			52,466			35,754
Net Income (Loss)	(8,260		)	(7,344		)	151,120			152,768
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $13 and ($7) for the three months ended July 31, 2015 and 2014, respectively, and ($787) and $328 for the nine months ended July 31, 2015 and 2014, respectively	33			(10		)	(1,227		)	516
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of $198 and ($59) for the three months ended July 31, 2015 and 2014, respectively, and $558 and ($199) for the nine months ended July 31, 2015 and 2014, respectively	307			(93		)	872			(315		)
Net current period benefit activities of equity method investments, net of tax of $1 and ($16) for the three months ended July 31, 2015 and 2014, respectively, and ($24) and ($16) for the nine months ended July 31, 2015 and 2014, respectively	2			(25		)	(36		)	(25		)
Total other comprehensive income (loss)	342			(128		)	(391		)	176
Comprehensive Income (Loss)	$	(7,918	)	$	(7,472	)	$	150,729		$	152,944
Average Shares of Common Stock:
Basic	79,039			78,185			78,826			77,715
Diluted	79,039			78,185			79,175			78,027
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.09	)	$	1.92		$	1.97
Diluted	$	(0.10	)	$	(0.09	)	$	1.91		$	1.96

⁽¹⁾ See Note 12 for amount attributable to affiliates.

See notes to condensed consolidated financial statements.

Table of Contents

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)



	Nine Months Ended July 31
	2015			2014
Cash Flows from Operating Activities:
Net income	$	151,120		$	152,768
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	104,510			95,550
Allowance for doubtful accounts	819			2,042
Net gain on sale of property	—			(75		)
Income from equity method investments	(29,908		)	(29,345		)
Distributions of earnings from equity method investments	22,401			17,443
Deferred income taxes, net	79,423			87,078
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	3,758			811
Receivables	18,371			15,376
Inventories	20,274			(5,190		)
Settlement of legal asset retirement obligations	(3,914		)	(2,284		)
Regulatory assets	14,192			41,083
Other assets	18,974			12,507
Accounts payable	(20,651		)	(9,670		)
Provision for postretirement benefits, net	(10,232		)	(20,042		)
Regulatory liabilities	5,180			63,642
Other liabilities	(1,134		)	(7,657		)
Net cash provided by operating activities	373,183			414,037
Cash Flows from Investing Activities:
Utility capital expenditures	(308,559		)	(348,416		)
Allowance for borrowed funds used during construction	(7,935		)	(15,960		)
Contributions to equity method investments	(20,063		)	(31,872		)
Distributions of capital from equity method investments	1,285			9,060
Proceeds from sale of property	372			792
Investments in marketable securities	(845		)	(550		)
Other	5,834			1,685
Net cash used in investing activities	(329,911		)	(385,261		)

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)



	Nine Months Ended July 31
	2015			2014
Cash Flows from Financing Activities:
Net borrowings – commercial paper	$	15,000		$	90,000
Repayment of long-term debt	—			(100,000		)
Expenses related to issuance of debt	(1		)	(456		)
Proceeds from issuance of common stock, net of expenses	—			47,290
Issuance of common stock through dividend reinvestment and employee stock plans	20,358			18,840
Dividends paid	(77,249		)	(74,076		)
Other	(359		)	12
Net cash used in financing activities	(42,251		)	(18,390		)
Net Increase in Cash and Cash Equivalents	1,021			10,386
Cash and Cash Equivalents at Beginning of Period	9,643			8,063
Cash and Cash Equivalents at End of Period	$	10,664		$	18,449
Cash Paid During the Period for:
Interest	$	58,147		$	55,998
Income Taxes:
Income taxes paid	$	2,984		$	6,867
Income taxes refunded	530			19
Income taxes, net	$	2,454		$	6,848
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	48,742		$	33,491

See notes to condensed consolidated financial statements.

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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, 2013	76,099	$	561,644		$	627,236		$	(284	)	$	1,188,596
Net Income					152,768						152,768
Other Comprehensive Income								176			176
Common Stock Issued	2,228	68,264									68,264
Expenses from Issuance of Common Stock		(12		)							(12		)
Tax Benefit from Dividends Paid on ESOP Shares					88						88
Dividends Declared ($.95 per share)					(74,076		)				(74,076		)
Balance at July 31, 2014	78,327	$	629,896		$	706,016		$	(108	)	$	1,335,804

Balance, October 31, 2014	78,531	$	636,835		$	672,004		$	(237	)	$	1,308,602
Net Income					151,120						151,120
Other Comprehensive Loss								(391		)	(391		)
Common Stock Issued	664	24,248									24,248
Expenses from Issuance of Common Stock		(362		)							(362		)
Tax Benefit from Dividends Paid on ESOP Shares					93						93
Dividends Declared ($.98 per share)					(77,249		)				(77,249		)
Balance, July 31, 2015	79,195	$	660,721		$	745,968		$	(628	)	$	1,406,061

See notes to condensed consolidated financial statements.

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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, 2014. Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2014. There were no significant changes to those accounting policies during the nine months ended July 31, 2015.

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 July 31, 2015 and October 31, 2014, the results of operations for three months and nine months ended July 31, 2015 and 2014, and cash flows and stockholders’ equity for the nine months ended July 31, 2015 and 2014.

Seasonality and Use of Estimates

Our business is seasonal in nature. The results of operations for the three months and nine months ended July 31, 2015 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 2 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 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.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the 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 8 to the condensed consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2014. 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, 2014. There were no significant changes to these fair value methodologies during the three months ended July 31, 2015.

Recently Issued Accounting Guidance



Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606)	Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers.	Annual periods beginning after December 15, 2017 (beginning November 1, 2018 for us) and interim periods within that period, with early adoption permitted for annual periods beginning after December 15, 2016.	We are currently evaluating the effect on our financial position, results of operations and cash flows, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are following the efforts of an accounting utility subgroup and its issuance of a revenue implementation guide.

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Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-15, August 2014, Presentation of Financial Statements - Going Concern (Subtopic 205-40)	The Financial Accounting Standards Board (FASB) issued accounting guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity must provide certain disclosures if there is a "substantial doubt about the entity's ability to continue as a going concern."	Annual periods ending after December 15, 2016 (October 31, 2017 for us), and interim and annual periods thereafter; early adoption is permitted.	The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. It will require establishing a going concern assessment process to meet the standard.
ASU 2015-01, January 2015, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20)	The FASB issued accounting guidance eliminating the concept of extraordinary items, thus eliminating the need to assess whether a particular event or transaction event is extraordinary. The presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring, with the amendments being applicable either prospectively or retrospectively, to all prior periods presented in the financial statements.	Annual periods beginning after December 15, 2015 (November 1, 2016 for us), and interim periods within those periods, with early adoption permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption.	The adoption of this guidance will be applied on a prospective basis. We have not had any extraordinary or unusual items that would impact our financial position, results of operations or cash flows.
ASU 2015-02, February 2015, Consolidation - Amendments to the Consolidation Analysis (Topic 810)	The FASB issued accounting guidance which amends the consolidation requirements in ASC 810. The amendments significantly change the consolidation analysis required under U.S. GAAP. The focus of this guidance is largely on the investment management industry related to limited partnerships becoming variable interest entities; however, it could have an impact on the consolidation conclusions of reporting entities in other industries.	Annual periods beginning after December 15, 2015 (November 1, 2016 for us), and interim periods within those periods, with early adoption permitted, provided that the guidance is applied from the beginning of the annual period containing the adoption date.	The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.
ASU 2015-03, April 2015, Interest: Imputation of Interest - Simplifying the Presentation of Debt Issuance Costs (Subtopic 835-30)	The FASB issued accounting guidance as part of its simplification initiative to reduce complexity in accounting standards. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this amendment.	Annual periods beginning after December 15, 2015 (November 1, 2016 for us), and interim periods within those fiscal years, with early adoption permitted for financial statements that have not been previously issued.	We plan to adopt this guidance in our fourth quarter of 2015. The adoption of this guidance will have no effect on the results of operations or cash flows. It will retrospectively affect the presentation of the balance sheet line items current and noncurrent "Regulatory assets," "Long-term debt" and "Short-term debt."

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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 FASB issued accounting guidance that amends ASC 350-40 to provide customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software.	Annual periods (and interim periods therein) beginning after December 15, 2015 (November 1, 2016 for us), with early adoption permitted. Entities may adopt the guidance (1) retrospectively or (2) prospectively to arrangements entered into, or materially modified, after the effective date.	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2015-07, May 2015, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (Topic 820)	The FASB issued accounting guidance that amends the required disclosure of investments for which fair value is measured at net asset value per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient.	Annual periods beginning after December 15, 2015 (November 1, 2016 for us), and interim periods within those fiscal years, with retrospective application to all periods presented and early adoption permitted.	The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. We will disclose certain benefit plan assets under the new guidance.
ASU 2015-11, July 2015, Inventory: Simplifying the Measurement of Inventory (Topic 330)	The FASB issued accounting guidance which modifies existing requirements regarding measuring inventory at the lower of cost or market where market could be replacement cost, net realizable value (NRV) or NRV less an approximately normal profit margin. The new ASU replaces market with NRV, defined as estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The ASU applies to all inventory except inventory measured using last-in, first-out or the retail inventory method.	Annual periods beginning after December 15, 2016 (November 1, 2017 for us), and interim periods within those fiscal years applied prospectively, with early adoption permitted as of the beginning of an interim or annual reporting period.	The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.
ASU 2015-12, July 2015, Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965)	The FASB issued a three-part standard providing guidance on certain aspects of the accounting by employee benefit plans. The ASU: (1) requires a pension plan to use contract value as the only measure for fully benefit-responsive investment contracts; (2) simplifies and increases the effectiveness of the investment disclosure requirements for employee benefit plans by grouping investments by general type; and (3) provides benefit plans with a measurement-date practical expedient on a month-end date nearest to the employer's fiscal year end.	Annual periods beginning after December 15, 2015 (November 1, 2016 for us) with early adoption permitted. The amendments in parts (1) and (2) are retrospectively applied to all periods presented, while the amendment in part (3) is applied prospectively.	The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. We will disclose certain benefit plan assets under the new guidance. Parts (1) and (2) are applicable to our Form 11-K filing; part (3) is not applicable to us.

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2.	Regulatory Matters

Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of July 31, 2015 and October 31, 2014 are as follows.



In thousands	July 31, 2015		October 31, 2014
Regulatory Assets:
Current:
Unamortized debt expense	$	1,480	$	1,490
Amounts due from customers	—		16,108
Environmental costs	1,527		1,568
Deferred operations and maintenance expenses	833		916
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,769
Robeson liquefied natural gas (LNG) development costs	515		917
Other	1,852		1,850
Total current	12,434		29,088
Noncurrent:
Unamortized debt expense	14,296		15,402
Environmental costs	5,439		6,470
Deferred operations and maintenance expenses	4,214		4,721
Deferred pipeline integrity expenses	27,219		24,694
Deferred pension and other retirement benefit costs	18,550		18,799
Amounts not yet recognized as a component of pension and other retirement benefit costs	89,140		94,265
Regulatory cost of removal asset	18,792		18,275
Robeson LNG development costs	223		509
Other	1,314		1,644
Total noncurrent	179,187		184,779
Total	$	191,621	$	213,867



Regulatory Liabilities:
Current:
Amounts due to customers	$	34,815	$	46,231
Noncurrent:
Regulatory cost of removal obligations	519,028		506,574
Deferred income taxes	68,533		51,930
Amounts not yet recognized as a component of pension and other retirement benefit costs	87		94
Total noncurrent	587,648		558,598
Total	$	622,463	$	604,829

Rate and Regulatory Actions

North Carolina

In December 2014, we filed a petition with the North Carolina Utilities Commission (NCUC) seeking authority to collect through adjusted rates an additional $26.6 million in annual integrity management rider (IMR) margin revenues effective February 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ended October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We are currently in discussion with the North Carolina Public Staff to complete their review and to jointly develop a future procedural schedule for the IMR audit/rate approval process.

In August 2015, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2015. A hearing has been scheduled for October 6, 2015.

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South Carolina

In June 2015, we filed testimony with the Public Service Commission of South Carolina (PSCSC) in support of our annual review of purchased gas adjustment (PGA) and gas purchasing policies for the twelve months ended March 31, 2015. On June 29, 2015, a settlement agreement with the Office of Regulatory Staff (ORS) was filed. On August 12, 2015, the PSCSC approved the settlement agreement finding that our gas purchasing policies were reasonable and prudent, that we properly adhered to the gas cost recovery provisions of our tariff and relevant PSCSC orders and that we managed our hedging program in a manner consistent with PSCSC orders. We are waiting on the PSCSC's written order at this time.

In June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the Rate Stabilization Act requesting a change in rates. On September 1, 2015, a settlement agreement with the ORS was filed that stipulated a $1.7 million annual increase in margin based on a return on equity of 10.2%, effective November 1, 2015. We are waiting on a ruling from the PSCSC at this time.

Tennessee

In February 2014, we filed a petition with the Tennessee Regulatory Authority (TRA) to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waiting on a ruling from the TRA at this time.

In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the Tennessee Incentive Plan (TIP). In March 2015, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report on the TIP with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report and issued their written order in May 2015.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a regulated service. We are waiting on the TRA's written order.

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

In August 2015, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2015 under the TIP. We are waiting on a ruling from the TRA at this time.


3.	Earnings per Share

We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans and forward sale agreements (FSAs) are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.

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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 the FSAs settle in shares, for the three months and nine months ended July 31, 2015 and 2014 is presented below.



	Three Months						Nine Months
In thousands, except per share amounts	2015			2014			2015		2014
Net Income (Loss)	$	(8,260	)	$	(7,344	)	$	151,120	$	152,768

Average shares of common stock outstanding for basic earnings per share	79,039			78,185			78,826		77,715
Contingently issuable shares under incentive compensation plans *	—			—			286		312
Contingently issuable shares under forward sale agreements *	—						63
Average shares of dilutive stock	79,039			78,185			79,175		78,027
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.09	)	$	1.92	$	1.97
Diluted	$	(0.10	)	$	(0.09	)	$	1.91	$	1.96
* For the three months ended July 31, 2015 and 2014, the inclusion of 301 contingently issuable shares under incentive compensation plans in both periods, and FSAs in 2015, would have been antidilutive.


4.	Long-Term Debt Instruments

In June 2014, we filed 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 statement up to $1 billion during its three-year life. As of July 31, 2015, before settlement of the FSAs expected in October 2015, we have $750 million remaining for debt and equity issuances as approved by the NCUC. For further information on equity transactions, see Note 6 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.

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.


5.	Short-Term Debt Instruments

We have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million of which $1.7 million and $1.8 million were issued and outstanding as of July 31, 2015 and October 31, 2014, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017, provided that we are in compliance with all terms of the agreement.

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 July 31, 2015, we had $370 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 7 to 14 days from their dates of issuance at a weighted average interest rate of .19%. As of October 31, 2014, our outstanding notes under the CP program, included in the Condensed Consolidated Balance Sheets as stated above, were $355 million at a weighted average interest rate of .17%.

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We did not have any borrowings under the revolving syndicated credit facility for the nine months ended July 31, 2015. A summary of the short-term debt activity under our CP program for the three months and nine months ended July 31, 2015 is as follows.



In millions	Three Months			Nine Months
Minimum amount outstanding during period	$	250		$	230
Maximum amount outstanding during period	$	370		$	580
Minimum interest rate during period	.16		%	.15		%
Maximum interest rate during period	.21		%	.30		%
Weighted average interest rate during period	.20		%	.21		%

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 56% at July 31, 2015.


6.	Stockholders’ Equity

Capital Stock

Changes in common stock for the nine months ended July 31, 2015 are as follows.



In thousands	Shares	Amount
Balance, October 31, 2014	78,531	$	636,835
Issued to participants in the Employee Stock Purchase Plan (ESPP)	24	900
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan	510	18,425
Issued to participants in the Incentive Compensation Plan (ICP)	130	4,923
Costs from issuance of common stock		(362		)
Balance, July 31, 2015	79,195	$	660,721

Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements, we may issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170 million (subject to certain exceptions) during the period ending October 31, 2016.

In addition to the issuance and sale of shares by us through the Agents, we may also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers will, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. We expect to enter into separate FSAs each fiscal quarter during the term of the Sales Agreements and have done so in our second and third quarters.

Under the Sales Agreements, we specify the maximum number of our shares to be sold and the minimum price per share. We will pay each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale price) a commission of 1.5% of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements may be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs.

Under a FSA that we executed with Merrill on March 10, 2015, 612,000 shares were borrowed from third parties and sold by Merrill, from March 10, 2015 to April 24, 2015, at a weighted average share price of $36.83, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $36.28.

Under a FSA that we executed with JP Morgan on June 8, 2015, 795,529 shares were borrowed from third parties and sold by JP Morgan, from June 10, 2015 to July 30, 2015, at a weighted average share price of $36.42, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $35.87.

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Under the terms of these FSAs, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation under the agreements. We expect to settle by delivering shares. We do not expect to physically settle these shares until October 2015; however, at our election, we can settle the shares under both agreements any time prior to December 15, 2015.

In accordance with ASC 815-40, Derivatives and Hedging - Contracts in Entity's Own Equity, we have classified the FSAs as equity transactions because the forward sale transactions are 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 FSAs.

Upon physical settlement of the FSAs, 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 FSAs 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 3 to the condensed consolidated financial statements in this Form 10-Q for the dilutive effect of the FSAs on our EPS at July 31, 2015 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 FSAs by delivery of the combined 1.4 million shares of our common stock to the forward counterparties at July 31, 2015, we would have received net proceeds of approximately $50.5 million based on the net settlement price of $35.87 per share. Upon settlement, we intend to use the net proceeds from these FSAs to finance capital expenditures, to repay outstanding short-term unsecured notes under our commercial paper program and for general corporate purposes.

Cash dividends paid per share of common stock for the three months and nine months ended July 31, 2015 and 2014 are as follows.



	Three Months				Nine Months
	2015		2014		2015		2014
Cash dividends paid per share of common stock	$	0.33	$	0.32	$	0.98	$	0.95

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 12 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 and nine months ended July 31, 2015 and 2014.



	Changes in Accumulated OCIL⁽¹⁾
	Three Months						Nine Months
In thousands	2015			2014			2015			2014
Accumulated OCIL beginning balance, net of tax	$	(970	)	$	20		$	(237	)	$	(284	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	33			(10		)	(1,227		)	516
Amounts reclassified from accumulated OCIL, net of tax	307			(93		)	872			(315		)
Total current period activity of hedging activities of equity method investments, net of tax	340			(103		)	(355		)	201
Net current period benefit activities of equity method investments, net of tax	2			(25		)	(36		)	(25		)
Accumulated OCIL ending balance, net of tax	$	(628	)	$	(108	)	$	(628	)	$	(108	)
⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

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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 and nine months ended July 31, 2015 and 2014.



	Reclassification Out of Accumulated OCIL ⁽¹⁾												Affected Line Items on Condensed Statements of Operations and Comprehensive Income
	Three Months						Nine Months
In thousands	2015			2014			2015			2014
Hedging activities of equity method investments	$	505		$	(152	)	$	1,430		$	(514	)	Income from equity method investments
Income tax expense	(198		)	59			(558		)	199			Income taxes
Hedging activities of equity method investments	307			(93		)	872			(315		)
Net benefit activities of equity method investments	3			(41		)	(60		)	(41		)	Income from equity method investments
Income tax expense	(1		)	16			24			16			Income taxes
Net benefit activities of equity method investments	2			(25		)	(36		)	(25		)
Total reclassification for the period, net of tax	$	309		$	(118	)	$	836		$	(340	)
⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.


7.	Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 10 to the 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 July 31, 2015 and October 31, 2014 is as follows.



	July 31, 2015				October 31, 2014
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	51	$	51	$	22	$	22
Mutual funds	117		199		106		192
Total current trading securities	168		250		128		214
Noncurrent trading securities:
Money markets	452		452		447		447
Mutual funds	3,610		4,303		2,598		3,280
Total noncurrent trading securities	4,062		4,755		3,045		3,727
Total trading securities	$	4,230	$	5,005	$	3,173	$	3,941


8.	Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of July 31, 2015 and October 31, 2014, we had long gas purchase

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options providing total coverage of 27.4 million dekatherms and 29.2 million dekatherms, respectively. The long gas purchase options held at July 31, 2015 are for the period from June 2015 through May 2016.

Fair Value Measurements

We use financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for our deferred compensation plans. 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, 2014.

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of July 31, 2015 and October 31, 2014. 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 July 31, 2015 and 2014. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.



Recurring Fair Value Measurements as of July 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 held for utility operations	$	1,140	$	—	$	—	$	—	$	1,140
Debt and equity securities held as trading securities:
Money markets	503		—		—		—		503
Mutual funds	4,502		—		—		—		4,502
Total fair value assets	$	6,145	$	—	$	—	$	—	$	6,145



Recurring Fair Value Measurements as of October 31, 2014
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives held for utility operations	$	4,898	$	—	$	—	$	—	$	4,898
Debt and equity securities held as trading securities:
Money markets	469		—		—		—		469
Mutual funds	3,472		—		—		—		3,472
Total fair value assets	$	8,839	$	—	$	—	$	—	$	8,839

Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 2 to the condensed consolidated financial statements. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets. Securities

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classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

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



In thousands	Carrying Amount ⁽¹⁾		Fair Value
As of July 31, 2015	$	1,425,000	$	1,615,953
As of October 31, 2014	1,425,000		1,617,453
⁽¹⁾ Excludes discount on issuance of notes of $550 and $570 as of July 31, 2015 and October 31, 2014, respectively.

Quantitative and Qualitative Disclosures

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value of our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of July 31, 2015 and October 31, 2014.

Fair Value of Derivative Instruments

	July 31,		October 31,
In thousands	2015		2014
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (September 2015 - July 2016)	$	1,140
Current Assets – Gas purchase derivative assets (December 2014 - November 2015)			$	4,898

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs are to use these financial instruments to reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 2 to the condensed consolidated financial statements and recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

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The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Condensed Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2015 and 2014, absent the regulatory treatment under our approved PGA procedures.



	Amount of Gain (Loss) Recognized on Derivative Instruments and Deferred Under PGA Procedures											Location of Gain (Loss) Recognized through PGA Procedures
	Three Months Ended July 31						Nine Months Ended July 31
In thousands	2015			2014			2015			2014
Gas purchase options	$	(1,007	)	$	(515	)	$	(3,296	)	$	7,311	Cost of Gas

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP as approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan as approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Credit and Counterparty Risk

Information regarding our credit and counterparty risk is set forth in Note 7 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2014. During the three months ended July 31, 2015, 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 $7.1 million, or approximately 11%, of our gross trade accounts receivable at July 31, 2015. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

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.


9.	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-one years. The time periods for fixed payments under gas supply contracts are up to two years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and

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software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the 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 Operations and 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 $1.7 million in letters of credit that were issued and outstanding as of July 31, 2015. Additional information concerning letters of credit is included in Note 5 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 July 31, 2015, we had open surety bonds with a total contingent obligation of $6.7 million.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded. There were no material changes in the status of environmental-related matters during the nine months ended July 31, 2015.

As of July 31, 2015, our estimated undiscounted environmental liability totaled $1.1 million for manufactured gas production sites for which we retain remediation responsibility and for our underground storage tanks, which have been removed and for which we are waiting on a decision from the North Carolina Department of Environment and Natural Resources as to their final disposition. 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 environmental liabilities 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 8 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2014.

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10.	Employee Benefit Plans

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 July 31, 2015 and 2014 are presented below.



	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2015			2014			2015		2014		2015			2014
Service cost	$	2,452		$	2,600		$	—	$	—	$	295		$	277
Interest cost	3,063			2,950			52		45		369			362
Expected return on plan assets	(5,860		)	(5,475		)	—		—		(459		)	(457		)
Amortization of prior service (credit) cost	(548		)	(550		)	58		20		—			—
Amortization of actuarial loss	2,407			2,025			21		12		7			—
Total	$	1,514		$	1,550		$	131	$	77	$	212		$	182

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2015 and 2014 are presented below.



	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2015			2014			2015		2014		2015			2014
Service cost	$	8,552		$	8,100		$	—	$	—	$	886		$	831
Interest cost	9,013			8,850			157		135		1,107			1,086
Expected return on plan assets	(17,710		)	(16,875		)	—		—		(1,378		)	(1,372		)
Amortization of prior service (credit) cost	(1,648		)	(1,650		)	173		61		—			—
Amortization of actuarial loss	6,507			5,775			64		35		22			—
Total	$	4,714		$	4,200		$	394	$	231	$	637		$	545

In November 2014, we contributed $10 million to the qualified pension plan, and in January 2015, we contributed $1.4 million to the money purchase pension plan. During the nine months ended July 31, 2015, we contributed $.4 million to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans in 2015.



In thousands
Nonqualified pension plans	$	146
OPEB plan	1,500

We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are funded annually. For the nine months ended July 31, 2015, we contributed $.5 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral 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 July 31, 2015, we have a liability of $5.3 million for these plans.

See Note 7 and Note 8 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.


11.	Employee Share-Based Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the three months and nine months ended July 31, 2015 and 2014, we recorded compensation expense, and as of July 31, 2015 and October 31, 2014, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

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Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the three months and nine months ended July 31, 2015 and 2014, we recorded compensation expense, and as of July 31, 2015 and October 31, 2014, we accrued a liability for this award based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value at the settlement date.

On December 15, 2014, 20% of the grant, including accrued dividends, vested for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.

At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed under the ICP is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in the Condensed Consolidated Statements of Stockholders’ Equity and in Note 6 to the condensed consolidated financial statements in this Form 10-Q.

The compensation expense related to the incentive compensation plans for the three months and nine months ended July 31, 2015 and 2014, 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 July 31, 2015 and October 31, 2014 are presented below.



	Three Months				Nine Months
In thousands	2015		2014		2015		2014
Compensation expense	$	1,317	$	822	$	4,596	$	5,025



	July 31, 2015		October 31, 2014
Liability	$	12,460	$	15,130

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.


12.	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 Operations and Comprehensive Income.

Ownership Interests

We have the following membership interests in these companies as of July 31, 2015 and October 31, 2014, respectively.

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Equity Method Investment	Interest		Activity
Atlantic Coast Pipeline, LLC (ACP)	10	%	To develop, construct, own and operate approximately 550 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC
Cardinal Pipeline Company, LLC (Cardinal)	21.49	%	Intrastate pipeline located in North Carolina; regulated by the NCUC
Constitution Pipeline Company LLC (Constitution)	24	%	To develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline, and related facilities, connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC
Hardy Storage Company (Hardy Storage)	50	%	Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
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

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 Operations and Comprehensive Income.

Related Party Transactions

We have related party transactions as a customer of our investments. For each period of the three months and nine months ended July 31, 2015 and 2014, these gas costs and the amounts we owed to our equity method investees, as of July 31, 2015 and October 31, 2014 are as follows.

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Related Party	Type of Expense	Cost of Gas ⁽¹⁾								Trade accounts payable ⁽²⁾
		Three Months				Nine Months				July 31,		October 31,
In thousands		2015		2014		2015		2014		2015		2014
Cardinal	Transportation costs	$	2,207	$	2,204	$	6,556	$	6,607	$	744	$	747
Hardy Storage	Gas storage costs	2,322		2,322		6,967		7,139		774		774
Pine Needle	Gas storage costs	2,833		2,935		8,609		8,429		955		989
Totals		$	7,362	$	7,461	$	22,132	$	22,175	$	2,473	$	2,510
⁽¹⁾In the Condensed Consolidated Statements of Operations and 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 and nine months ended July 31, 2015 and 2014, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2015 and October 31, 2014 are as follows.



	Operating Revenues ⁽¹⁾								Trade accounts receivable ⁽²⁾
	Three Months				Nine Months				July 31,		October 31,
In thousands	2015		2014		2015		2014		2015		2014
Operating revenues	$	475	$	1,402	$	1,058	$	2,309	$	158	$	460
⁽¹⁾ In the Condensed Consolidated Statements of Operations and Comprehensive Income.
⁽²⁾In the Condensed Consolidated Balance Sheets.

Other Information – Constitution

A subsidiary of The Williams Companies will be the operator of the pipeline. The total estimated cost of the project is $925 million, including an allowance for funds used during construction (AFUDC).

We have committed to contribute an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $830 million, excluding AFUDC, in total. Our total anticipated contributions are approximately $199.6 million. Our contributions for the quarter and fiscal year 2015 were $1.4 million and $11.2 million, respectively, with our total equity contribution for the project totaling $64.7 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is the second half of 2016, which has been extended due to a longer than expected regulatory and permitting process. The capacity of the pipeline is 100% subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

Other Information – ACP

A subsidiary of Dominion Resources, Inc. will be 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 70% 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 contribute an amount in proportion to our ownership interest for the development and construction of the new pipeline. If project financing is obtained, our total expected contributions would be between $225 million to $250 million. Our contributions for the quarter and fiscal year 2015 were $3.1 million and $8.9 million, respectively, with contributions to the project beginning November 2014.

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 by other utilities and their related companies under twenty-year contracts.

In November 2014, the FERC authorized the ACP pre-filing process. 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 expects to file its FERC application in September 2015, 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.


13.	Variable Interest Entities

As of July 31, 2015, 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 discussed in Note 12 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. As we are not the consolidating investor, 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. As of July 31, 2015 and October 31, 2014, our investment balances are as follows.



In thousands	July 31, 2015		October 31, 2014
Cardinal	$	15,320	$	16,073
Pine Needle	18,921		18,689
SouthStar	40,799		40,965
Hardy Storage	39,568		37,179
Constitution	72,769		57,255
ACP	8,435		10
Total equity method investments in non-utility activities	$	195,812	$	170,171

We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

14. 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.

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Operations of the regulated utility segment are reflected in “Operating Income” in the Condensed Consolidated Statements of Operations and Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Condensed Consolidated Statements of Operations and 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 from our cash flows in 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, 2014. The information for 2014 has been recast to align with management's view of the non-utility activities.

Operations by segment for the three months and nine months ended July 31, 2015 and 2014 are presented below.



	Regulated Utility						Regulated Non-Utility Activities						Unregulated Non-Utility Activities						Total
In thousands	2015			2014			2015			2014			2015			2014			2015			2014
Three Months
Revenues from external customers	$	158,266		$	164,187		$	—		$	—		$	—		$	—		$	158,266		$	164,187
Margin	111,572			104,847			—			—			—			—			111,572			104,847
Operations and maintenance expenses	69,587			68,605			19			9			49			47			69,655			68,661
Income from equity method investments	—			—			3,894			3,253			1,907			1,790			5,801			5,043
Operating loss before income taxes	(1,864		)	(3,070		)	(89		)	(59		)	(68		)	(67		)	(2,021		)	(3,196		)
Income (loss) before income taxes	(18,904		)	(16,867		)	3,805			3,194			1,839			1,723			(13,260		)	(11,950		)
Nine Months
Revenues from external customers	$	1,190,462		$	1,284,167		$	—		$	—		$	—		$	—		$	1,190,462		$	1,284,167
Margin	607,263			577,882			—			—			—			—			607,263			577,882
Operations and maintenance expenses	207,162			199,437			70			23			96			79			207,328			199,539
Income from equity method investments	—			—			11,242			8,828			18,666			20,517			29,908			29,345
Operating income (loss) before income taxes	271,697			262,540			(140		)	(74		)	(203		)	(186		)	271,354			262,280
Income before income taxes	218,414			223,401			11,102			8,754			18,464			20,331			247,980			252,486

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Reconciliations to the condensed consolidated statements of operations and comprehensive income for the three months and nine months ended July 31, 2015 and 2014 are presented below.



	Three Months						Nine Months
In thousands	2015			2014			2015			2014
Operating Income (Loss):
Segment operating income (loss) before income taxes	$	(2,021	)	$	(3,196	)	$	271,354		$	262,280
Utility income taxes	7,097			6,324			(85,583		)	(89,668		)
Regulated non-utility activities operating loss before income taxes	89			59			140			74
Unregulated non-utility activities operating loss before income taxes	68			67			203			186
Operating income	$	5,233		$	3,254		$	186,114		$	172,872



Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(13,260	)	$	(11,950	)	$	247,980		$	252,486
Income taxes	5,000			4,606			(96,860		)	(99,718		)
Total	$	(8,260	)	$	(7,344	)	$	151,120		$	152,768


15.	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, see Note 2 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, 2014. 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.

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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. 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 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


•	Changes in local building codes or appliance standards


•	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

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

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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 and the Tennessee Regulatory Authority 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 12 and Note 14, respectively, to the condensed consolidated financial statements in this Form 10-Q. The percentages of the assets as of July 31, 2015 and earnings before taxes by segments for the nine months ended July 31, 2015 are presented below.



	Assets		Earnings Before Taxes
Regulated Utility	96	%	88	%
Non-utility Activities:
Regulated non-utility activities	3	%	5	%
Unregulated non-utility activities	1	%	7	%
Total non-utility activities	4	%	12	%

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, 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 air emissions regulations that could be expanded to address 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 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 regulatory lag through rate stabilization adjustment (RSA) tariffs, 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 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 tariff mechanism that achieves the objective of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff 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

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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, on an annual basis outside general rate cases, costs associated with capital expenditures to comply with pipeline safety and integrity requirements. The first Tennessee IMR rate adjustment was recognized in earnings through customer billings beginning in January 2014, and the first North Carolina IMR rate adjustment was recognized in earnings through customer billings beginning in February 2014.

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 2 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2014. The following table presents the breakdown of our gas utility margin for the nine months ended July 31, 2015 and 2014.



	2015		2014
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers,
Tennessee and North Carolina IMRs and fixed-rate contracts)	74	%	71	%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)	16	%	17	%
Volumetric or periodic renegotiation (including secondary marketing activity)	10	%	12	%
Total	100	%	100	%

Our long-term strategic directives are the foundation of 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 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


•	Enhance our healthy high performance culture.

With a focus on these priorities, we believe we will continue to 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, 2014.

Executive Summary

Financial Performance – Quarter Ended 2015 Compared with Quarter Ended 2014

The following tables provide a comparison of the components of operations and comprehensive income and statistical information for the three months ended July 31, 2015 as compared with the three months ended July 31, 2014.

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Comprehensive Statement of Operations Components

	Three Months Ended July 31
In thousands, except per share amounts	2015			2014			Variance			Percent Change
Operating Revenues	$	158,266		$	164,187		$	(5,921	)	(3.6	)%
Cost of Gas	46,694			59,340			(12,646		)	(21.3	)%
Margin	111,572			104,847			6,725			6.4	%
Operations and Maintenance	69,587			68,605			982			1.4	%
Depreciation	32,317			29,960			2,357			7.9	%
General Taxes	11,532			9,352			2,180			23.3	%
Utility Income Taxes	(7,097		)	(6,324		)	(773		)	(12.2	)%
Total Operating Expenses	106,339			101,593			4,746			4.7	%
Operating Income	5,233			3,254			1,979			60.8	%
Other Income (Expense), net of tax	3,181			2,527			654			25.9	%
Utility Interest Charges	16,674			13,125			3,549			27.0	%
Net Loss	$	(8,260	)	$	(7,344	)	$	(916	)	(12.5	)%
Average Shares of Common Stock:
Basic	79,039			78,185			854			1.1	%
Diluted	79,039			78,185			854			1.1	%
Loss Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.09	)	$	(0.01	)	(11.1	)%
Diluted	$	(0.10	)	$	(0.09	)	$	(0.01	)	(11.1	)%

Margin by Customer Class

	Three Months Ended July 31
In thousands	2015				2014
Sales and Transportation:
Residential	$	44,897	40	%	$	41,333	39	%
Commercial	27,326		25	%	25,800		25	%
Industrial	11,909		11	%	10,994		11	%
Power Generation	19,352		17	%	19,323		18	%
For Resale	3,471		3	%	2,743		3	%
Total	106,955		96	%	100,193		96	%
Secondary Market Sales	3,269		3	%	3,223		3	%
Miscellaneous	1,348		1	%	1,431		1	%
Total	$	111,572	100	%	$	104,847	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Three Months Ended July 31
	2015		2014		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	2,687		2,651		36		1.4	%
Commercial	4,724		5,349		(625	)	(11.7	)%
Industrial	21,086		21,064		22		0.1	%
Power Generation	75,562		56,845		18,717		32.9	%
For Resale	855		858		(3	)	(0.3	)%
Throughput	104,914		86,767		18,147		20.9	%
Secondary Market Volumes	5,246		1,461		3,785		259.1	%
Customers Billed (at period end)	1,014,159		998,850		15,309		1.5	%
Gross Residential, Commercial and Industrial Customer Additions	3,745		3,671		74		2.0	%
Degree Days
Actual	12		33		(21	)	(63.6	)%
Normal	47		49		(2	)	(4.1	)%
Percent warmer than normal	(74.5	)%	(32.7	)%	n/a		n/a
Number of Employees (at period end)	1,939		1,868		71		3.8	%

We ended our third quarter with a 12% decrease in net income. Margin increased 6% due to: Tennessee and North Carolina 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. Depreciation expense increased 8% primarily due to increases in plant in service. General taxes increased 23% primarily due to increased state franchise taxes and property taxes. Utility interest charges increased 27% as a result of an increase in long-term debt outstanding and a decrease in capitalized interest recorded as income.

Financial Performance – Nine Months Ended 2015 Compared with Nine Months Ended 2014

The following tables provide a comparison of the components of operations and comprehensive income and statistical information for the nine months ended July 31, 2015 as compared with the nine months ended July 31, 2014.

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Comprehensive Statement of Operations Components
	Nine Months Ended July 31
In thousands, except per share amounts	2015		2014		Variance			Percent Change
Operating Revenues	$	1,190,462	$	1,284,167	$	(93,705	)	(7.3	)%
Cost of Gas	583,199		706,285		(123,086		)	(17.4	)%
Margin	607,263		577,882		29,381			5.1	%
Operations and Maintenance	207,162		199,437		7,725			3.9	%
Depreciation	95,900		87,947		7,953			9.0	%
General Taxes	32,504		27,958		4,546			16.3	%
Utility Income Taxes	85,583		89,668		(4,085		)	(4.6	)%
Total Operating Expenses	421,149		405,010		16,139			4.0	%
Operating Income	186,114		172,872		13,242			7.7	%
Other Income (Expense), net of tax	17,472		15,650		1,822			11.6	%
Utility Interest Charges	52,466		35,754		16,712			46.7	%
Net Income	$	151,120	$	152,768	$	(1,648	)	(1.1	)%
Average Shares of Common Stock:
Basic	78,826		77,715		1,111			1.4	%
Diluted	79,175		78,027		1,148			1.5	%
Earnings Per Share of Common Stock:
Basic	$	1.92	$	1.97	$	(0.05	)	(2.5	)%
Diluted	$	1.91	$	1.96	$	(0.05	)	(2.6	)%



Margin by Customer Class
	Nine Months Ended July 31
In thousands	2015				2014
Sales and Transportation:
Residential	$	324,561	54	%	$	299,850	52	%
Commercial	151,975		25	%	141,025		24	%
Industrial	37,941		6	%	39,427		7	%
Power Generation	57,961		10	%	58,275		10	%
For Resale	8,635		1	%	7,100		1	%
Total	581,073		96	%	545,677		94	%
Secondary Market Sales	19,219		3	%	23,809		4	%
Miscellaneous	6,971		1	%	8,396		2	%
Total	$	607,263	100	%	$	577,882	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Nine Months Ended July 31
	2015		2014		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	56,973		58,480		(1,507	)	(2.6	)%
Commercial	37,669		38,138		(469	)	(1.2	)%
Industrial	73,711		73,697		14		—	%
Power Generation	196,278		150,808		45,470		30.2	%
For Resale	6,203		6,005		198		3.3	%
Throughput	370,834		327,128		43,706		13.4	%
Secondary Market Volumes	26,230		17,864		8,366		46.8	%
Customers Billed (at period end)	1,014,159		998,850		15,309		1.5	%
Gross Residential, Commercial and Industrial Customer Additions	12,248		11,626		622		5.4	%
Degree Days
Actual	3,279		3,391		(112	)	(3.3	)%
Normal	3,062		3,070		(8	)	(0.3	)%
Percent colder than normal	7.1	%	10.5	%	n/a		n/a
Number of Employees (at period end)	1,939		1,868		71		3.8	%

We ended the first three quarters of fiscal year 2015 with a 1% decrease in net income. Margin increased 5% due to: new residential and commercial customer rates effective January 1, 2014 in North Carolina under a rate case settlement, Tennessee and North Carolina IMR rate adjustments and customer growth, partially offset by lower margin sales from secondary market activity. Operations and maintenance (O&M) expenses and depreciation expense increased 4% and 9%, respectively. The increase in O&M expenses was related to increases in contract labor, employee benefits, payroll and regulatory expenses, partially offset by a decrease in bad debt expense. Depreciation was higher due to increases in plant in service. General taxes increased 16% primarily due to increased state franchise taxes and property taxes. Other Income (Expense) increased 12% primarily due to an increase in income from equity method investments and a write-off in the prior year of a cost-basis investment. Utility interest charges increased 47% as a result of a decrease in capitalized interest recorded as income and increases in long-term debt outstanding and interest expense on net amounts due to customers.

Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we executed our financing program to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our strong investment grade credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. In January 2015, we established an at-the-market (ATM) equity sales program, including a forward sales component, under our effective shelf registration statement. 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 and will be completed by the end of fiscal 2016. We continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs.

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Customer Growth – We have added increasing numbers of customers in our service areas during the current fiscal year compared to the prior fiscal year. Affordable and stable wholesale natural gas costs continued 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 resulted in growth in both the residential new construction and conversion markets. Commercial and industrial markets decreased slightly, reflecting a reduction in new customer activity coupled with a longer sales cycle for commercial conversions and a decline in readily available opportunities for industrial conversions. Overall, total residential and commercial customers increased during the nine months ended July 31, 2015 as compared to the same period in 2014 as presented below.



	2015	2014	Percent Change
Residential new home construction	8,927	8,372	6.6	%
Residential conversion	2,076	1,969	5.4	%
Commercial	1,238	1,272	(2.7	)%
Industrial	7	13	(46.2	)%
Total new customers	12,248	11,626	5.4	%

We forecast gross customer growth of approximately 1.6 – 2% for fiscal 2015. Overall, total net customers billed increased 1.5% for the nine months ended July 31, 2015 as compared to the same period in 2014.

Capital Expenditures – We continue 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 new comprehensive work and asset management system.

We have IMR regulatory mechanisms in North Carolina and Tennessee to separately track and recover the 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 Operations and Comprehensive Income for 2015 is summarized below:



In millions	North Carolina		Tennessee
Incremental annual margin revenue - 2014 IMR	$	.8	$	13.1
Incremental annual margin revenue - 2015 IMR	26.6		6.5
Total cumulative incremental annual margin revenue	27.5		19.6

Amount recorded during quarter	4.5		2.4
Amount recorded year to date	13.6		15.9

Sustainable Business Practices – In February, the winter weather throughout our service area was the coldest in 37 years. For the month of February 2015, we experienced a record customer volume sendout for our 65-year history, with February 19, 2015 as a new, single-day volume sendout record of 2.6 million dekatherms. Our ability to provide safe and reliable natural gas service under these operating conditions was due to our ongoing investments in our pipeline delivery system through our system expansion and pipeline integrity management programs. 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 on our design-day requirements, which is the estimated volume of gas that firm customers could use when the weather is extremely cold. We evaluate recent cold weather conditions and the corresponding customer consumption patterns, as well as historical winter weather over the past 40 years, in developing our design-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 currently committed to invest as members in two ventures, which intend to construct interstate natural gas pipelines.

We are a 24% equity member of Constitution Pipeline Company LLC (Constitution), a FERC regulated interstate natural gas pipeline that plans to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. The

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forecasted in-service date of the project is the second half of 2016, which has been extended due to a longer than expected regulatory and permitting process. We expect our total 24% equity contributions will be an estimated $199.6 million, excluding an allowance for funds used during construction (AFUDC). We contributed $11.2 million during the nine months ended July 31, 2015 for a total of $64.7 million to date.

We are a 10% equity member of Atlantic Coast Pipeline, LLC (ACP), a FERC regulated interstate natural gas pipeline that plans to provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. We plan to invest an additional $190 million in 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 state will enhance geographical diversity of supply by providing direct access to the Marcellus and Utica shale regions, one of the most abundant known sources of natural gas. We expect our total 10% equity contributions in ACP to be an estimated $450 million to $500 million before any project financing. If project financing is obtained, our total expected contributions would be between $225 million to $250 million. We contributed $8.9 million during the nine months ended July 31, 2015.

For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the condensed consolidated financial statements in this Form 10-Q.

Additional information on operating results for the three months and nine months ended July 31, 2015 follows.

Operating Revenues

Changes in operating revenues for the three months and nine months ended July 31, 2015 compared with the same periods in 2014 are presented below.

Changes in Operating Revenues - Increase (Decrease)

In millions	Three Months			Nine Months
Residential and commercial customers	$	(19.7	)	$	(82.7	)
Industrial customers	(1.1		)	(8.4		)
Power generation customers	0.1			(0.2		)
Secondary market	8.6			(36.7		)
Margin decoupling mechanism	1.4			12.2
WNA mechanisms	—			2.0
IMR mechanisms	5.1			20.5
Other revenue	(0.3		)	(0.4		)
Total	$	(5.9	)	$	(93.7	)


•	Residential and commercial customers – the decreases for the three months and nine months are due to lower wholesale gas costs passed through to customers and lower consumption from warmer weather, slightly offset by customer growth.

•

Industrial customers – the decrease for the three months is primarily due to lower wholesale gas costs passed through to customers. The decrease for the nine months is primarily due to lower wholesale gas costs passed through to customers and lower industrial transportation rates in North Carolina as a result of cost allocation and rate design changes in the general rate case in North Carolina, effective January 1, 2014.

•

Secondary market – the increase for the three months is due to increased activity, slightly offset by lower secondary market sales. The decrease for the nine months is due to lower secondary market sales prices. 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 increases for the three months and nine months is primarily related to warmer weather in North Carolina as compared to the prior periods. 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 three month comparability is due to actual degree days being similar to normal degree days in the quarter. The increase for the nine months 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.

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•	IMR mechanisms – the increase for the three months is due to the IMR rate adjustments in Tennessee, effective in January 2015, and North Carolina, effective in February 2015. The increase for the nine months is due to the IMR rate adjustments in Tennessee, effective in January 2014 and 2015, and North Carolina, effective in February 2014 and 2015.

Cost of Gas

Changes in cost of gas for the three months and nine months ended July 31, 2015 compared with the same periods in 2014 are presented below.

Changes in Cost of Gas - Increase (Decrease)

In millions	Three Months			Nine Months
Commodity gas costs passed through to sales customers	$	(16.4	)	$	(114.4	)
Commodity gas costs in secondary market transactions	8.5			(32.1		)
Pipeline demand charges	(1.4		)	(12.3		)
Regulatory-approved gas cost mechanisms	(3.3		)	35.7
Total	$	(12.6	)	$	(123.1	)


•	Commodity gas costs passed through to sales customers – the decreases for the three months and nine months are primarily due to lower wholesale gas costs passed through to customers and lower consumption due to warmer weather, slightly offset by customer growth.


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


•	Pipeline demand charges – the decreases for the three months and nine months is primarily due to decreased demand costs and increased capacity release revenues, slightly offset by decreased asset manager payments.


•	Regulatory-approved gas cost mechanisms – the decrease for the three months is due to a decrease in commodity gas cost and demand true-ups, partially offset by other regulatory mechanisms. The increase for the nine months is primarily due to an increase 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 and are added to or deducted from cost of gas and are in current “Regulatory assets” or current “Regulatory liabilities” in the Condensed Consolidated Balance Sheets. For the amounts included in “Amounts due from customers” or “Amounts due to customers,” see Note 2 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 36% of revenues for the nine months ended July 31, 2015, and our pipeline transportation and storage costs accounted for 8%.

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.

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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.

Changes in margin for the three months and nine months ended July 31, 2015 compared with the same periods in 2014 are presented below.

Changes in Margin - Increase (Decrease)

In millions	Three Months			Nine Months
Residential and commercial customers	$	5.1		$	35.7
Industrial customers	1.6			—
Power generation customers	—			(0.3		)
Secondary market activity	0.1			(4.6		)
Net gas cost adjustments	(0.1		)	(1.4		)
Total	$	6.7		$	29.4

•

Residential and commercial customers – the increase for the three months is primarily due to IMR rate adjustments in Tennessee, effective in January 2015, and in North Carolina, effective in February 2015, as well as customer growth. The increase for the nine months is primarily due to the general rate case increase in North Carolina, effective January 1, 2014, IMR rate adjustments in Tennessee, effective in January 2014 and 2015, and North Carolina, effective in February 2014 and 2015, and customer growth in all three states.


•	Industrial customers – the increase for the three months is primarily due to IMR rate adjustments in Tennessee effective in January 2015, and North Carolina, effective in February 2015.


•	Secondary market activity – the decrease for the nine months is primarily due to lower margin sales, slightly offset by increased volumes.

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Operations and Maintenance Expenses

Changes in O&M expenses for the three months and nine months ended July 31, 2015 compared with the same periods in 2014 are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)

In millions	Three Months			Nine Months
Contract labor	$	1.7		$	4.1
Employee benefits	0.3			1.6
Payroll	0.6			1.4
Regulatory	0.2			1.2
Bad debt	(1.7		)	(1.6		)
Other	(0.1		)	1.0
Total	$	1.0		$	7.7


•	Contract labor – the increases for the three months and nine months are primarily due to increased process improvement projects and pipeline integrity maintenance and safety programs.


•	Employee benefits – the increase for the nine months is primarily due to a lower regulatory pension deferral in Tennessee in the current period related to lower funding of the defined benefit plan in 2015 versus 2014.


•	Payroll – the increases for the three months and nine months are primarily due to additional employees and employee overtime, partially offset by lower cash-based incentive plan accruals.


•	Regulatory – the increase for the nine months is primarily due to increased amortization of regulatory assets with approved amortization amounts established in the North Carolina general rate proceeding, effective January 1, 2014.


•	Bad debt – the decreases for the three months and nine months are primarily due to lower projected charge-offs than the prior periods.

Depreciation

Depreciation expense increased $2.4 million and $8 million for the three months and nine months ended July 31, 2015, respectively, compared with the same periods in 2014 primarily due to increases in plant in service, particularly related to major additions in system integrity investments and the development of a field operations work and asset management system and related computer systems.

General Taxes

General taxes increased $2.2 million and $4.5 million for the three months and nine months ended July 31, 2015, respectively, compared with the same periods in 2014 primarily due to increases in property taxes from increased investments in plant and state franchise taxes. There was a change to North Carolina law which resulted in us being liable for an additional $1.5 million in state franchise taxes for the nine months ended July 31, 2015, with the majority being recovered in rates.

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 July 31, 2015 was comparable to the same period in 2014.

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The primary changes to Other Income (Expense) for the nine months ended July 31, 2015 compared with the same period in 2014 were increases in income from equity method investments and non-operating income. Income from equity method investments increased $.6 million primarily due to an increase in income from Constitution of $2.8 million as a result of higher capitalized interest associated with increased capital expenditures with the project as development progresses, partially offset by a decrease in income from SouthStar of $1.9 million largely due to decreases in the value of hedged derivatives and lower usage in Georgia due to warmer weather, partially offset by favorable margins in Georgia, Illinois and Ohio.

The primary change to non-operating income for the nine months ended July 31, 2015 compared with the same period in 2014 was due to a $2 million write-off in 2014 of an investment that was accounted for on the cost basis.

Utility Interest Charges

Changes in utility interest charges for the three months and nine months ended July 31, 2015 compared with the same periods in 2014 are presented below.

Changes in Utility Interest Charges - Increase (Decrease)

In millions	Three Months			Nine Months
Borrowed AFUDC	$	1.7		$	8.0
Interest expense on long-term debt	2.5			7.0
Regulatory interest expense, net	(0.7		)	1.7
Total	$	3.5		$	16.7


•	Borrowed AFUDC – the increases for the three months and nine months are due to decreases in capitalized interest from lower capital expenditures.


•	Interest expense on long-term debt – the increases for the three months and nine months are primarily due to higher amounts of long-term debt outstanding in the current periods.


•	Regulatory interest expense, net – the changes for the three months and nine months are primarily due to interest expense charged on amounts due to customers on lower balances for the three months and on higher balances for the nine months. Both periods include the effect of the one-time bill credit to customers in April 2015, which lowered 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.

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

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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 infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee.

Short-Term Debt

We have an $850 million five-year revolving syndicated credit facility that expires in October 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The five-year revolving syndicated credit facility contains normal and customary financial covenants.

We are in discussions with the lenders under our existing $850 million five-year revolving syndicated credit facility to amend and extend the facility at substantially similar terms, plus an option for us to request an increase of the commitments to $1.05 billion, for five years from the effective date of the amendment. We have proposed that the amendment be effective in November 2015. The CP program will continue to be backstopped by the new credit facility.

We did not have any borrowings under the revolving syndicated credit facility for the three months ended July 31, 2015. Highlights for our short-term debt under our CP program as of July 31, 2015 and for the quarter ended July 31, 2015 are presented below.



In thousands
End of period (July 31, 2015):
Amount outstanding	$	370,000
Weighted average interest rate	.19		%

During the period (May 1, 2015 – July 31, 2015):
Average amount outstanding	$	299,076
Minimum amount outstanding	250,000
Maximum amount outstanding	370,000
Minimum interest rate	.16		%
Maximum interest rate	.21		%
Weighted average interest rate	.20		%

Maximum amount outstanding:
May 2015	$	290,000
June 2015	305,000
July 2015	370,000

As of July 31, 2015, we have $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.7 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of July 31, 2015, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $478.3 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

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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.

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 and in 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 provided by operating activities was $373.2 million and $414 million for the nine months ended July 31, 2015 and 2014, respectively. Net cash provided by operating activities reflects a decrease of $1.6 million in net income for 2015 compared with 2014 primarily due to higher operating expenses and utility interest charges, partially offset by increased margin. The effect of changes in working capital on net cash provided by operating activities is described below.

•

Trade accounts receivable and unbilled utility revenues decreased $21.8 million from October 31, 2014 primarily due to the decrease in unbilled volumes and amounts billed to customers. Volumes sold to weather-sensitive residential and commercial customers decreased 2 million dekatherms as compared with the same prior period primarily due to 3.3% warmer weather during the current period. Total throughput increased 43.7 million dekatherms as compared with the same prior period, largely from 45.5 million dekatherms, or 30.2%, increased deliveries to power generation customers, partially offset by decreased sales to residential and commercial customers.


•	Net amounts due to customers increased $4.7 million in the current period primarily due to deferred gas cost collections and refunds through rates, partially offset by a decrease in margin decoupling revenues and a $45.5 million one-time bill credit to North Carolina customers.


•	Gas in storage decreased $19.9 million in the current period primarily due to the withdrawal of storage volumes to meet customer sales during the winter heating season of 2014-2015 and a decrease in the weighted average cost of gas purchased for injections.


•	Prepaid gas costs decreased $15.8 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 $2.8 million from October 31, 2014 primarily due to timing of utility capital expenditures, partially offset by lower prices for natural gas purchases.

Primarily due to bonus depreciation, we generated federal NOLs in our tax years 2012, 2013 and 2014. We filed claims to carryback a portion of the NOLs to prior federal income tax returns. We are currently under audit by the Internal Revenue Service for our 2012 tax year. Due to the timing of the audit, we reclassified $26 million of current refundable income taxes to "Income taxes receivable" in "Noncurrent Assets" in the Condensed Consolidated Balance Sheets.

The Tax Increase Prevention Act of 2014 (the Act), enacted December 19, 2014, retroactively extended the 50% bonus depreciation that expired December 2013 for a year to December 2014. Under the Act, we are entitled to additional tax depreciation deductions for 2014. These additional deductions resulted in generating a federal NOL in 2014. As of July 31, 2015, we have $161 million of federal NOL carryforwards available to offset future taxable income. We anticipate that we will generate future taxable income sufficient to utilize this carryforward prior to the expiration of the loss carryforward period.

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In July 2015, the provision for a 1% state income tax rate reduction based on state tax collections exceeding certain thresholds under the North Carolina tax statutes was announced. Accordingly, the statutory income tax rate for North Carolina will decrease to 4% for our fiscal year 2017. We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the state income tax rate reduction, we adjusted our noncurrent deferred income taxes at July 31, 2015 by $14.1 million for temporary differences expected to reverse at the lower rate and recognized a tax benefit of $.6 million in net income, the majority of which relates to our non-utility activities. The balance of $13.5 million was recorded in deferred income taxes in "Regulatory Liabilities" as presented in Note 2 to the condensed consolidated financial statements in this Form 10-Q, reflecting a future benefit to our customers. The NCUC will determine the recovery period of this regulatory liability in future proceedings.

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 credits to customers of $7 million and $9 million in the nine months ended July 31, 2015 and 2014, 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 2 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 decreased margin by $27.5 million and $39.7 million in the nine months ended July 31, 2015 and 2014, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanisms.

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 $329.9 million and $385.3 million for the nine months ended July 31, 2015 and 2014, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital

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expenditures for the nine months ended July 31, 2015 and 2014 were $308.6 million and $348.4 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 new 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 2015 – 2017 capital expenditures, including AFUDC, 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 and bonus depreciation benefits.



In millions	2015		2016		2017
Customer growth and other	$	225	$	285	$	295
System integrity	255		245		295
Total forecasted capital expenditures	$	480	$	530	$	590

We have seen our utility capital expenditures program increase significantly over the past two years related to system integrity spend. These increases are primarily due to costs associated with the development and enhancement of programs and processes designed to mitigate risk on our system to comply with federally mandated pipeline safety and integrity requirements. Such programs include retrofitting transmission lines to facilitate internal inspections, transmission line replacements and repairs, corrosion control, casing remediation and distribution integrity management.

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 Corporation's W.S. Lee power generation facility near Anderson, South Carolina. Our total investment is estimated to be $36 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.

We are invested as equity members in two interstate natural gas pipeline projects that are in the process of development. As a member of each of these limited liability companies, we are committed to fund construction in proportion to our ownership interest. For further information on these equity investments, see Note 12 to the condensed consolidated financial statements in this Form 10-Q. Details of the project costs for these investments are presented below.



	Constitution			ACP
	(24% ownership interest)			(10% ownership interest)
Our total anticipated contributions for project costs	$199.6 million			$450 – $500 million
Anticipated in-service date	second half of 2016			late 2018
Our contributions:
For the nine months ended July 31, 2015		$11.2	million		$8.9	million
Over life of project to date		$64.7	million		$8.9	million

In connection with the ACP project, we plan to make additional utility capital investments, predominately in fiscal 2017 and 2018, in our utility natural gas delivery system of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets. Of that amount, approximately $170 million is supported by third-party contracts.

Cash Flows from Financing Activities

Net cash used in financing activities was $42.3 million and $18.4 million for the nine months ended July 31, 2015 and 2014, 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

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target capital structure of 40 – 50% equity to total capital. 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 $355 million as of October 31, 2014 to $370 million as of July 31, 2015 primarily due to utility capital expenditures, investments in our equity method investments and dividend payments. For further information on short-term debt, see Note 5 to the condensed consolidated financial statements in this Form 10-Q and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

In June 2014, we filed 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.

As of July 31, 2015, before settlement of the forward sale agreements (FSAs) under the ATM program expected in October 2015, we have $750 million remaining under the shelf registration statement for debt and equity issuances as approved by the NCUC. We plan to issue long-term debt and equity capital over fiscal years 2015 and 2016, at such amounts to support our capital investment program and maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. During the fourth fiscal quarter of 2015, we anticipate issuing $100 million to $200 million of long-term debt under our shelf registration statement, the timing and terms of which will be subject to then-current market conditions. In addition to issuing common stock under our DRIP and ESPP as described above, we established in January 2015 an ATM program that also includes sales with a forward component. Sales under this ATM program will not exceed an aggregate of $170 million, as market conditions permit, and will terminate by the end of fiscal 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 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 counterparty) under the related ATM program sales agreements. Shares sold pursuant to FSAs will settle on dates specified by us, which may be substantially after the sale occurs but not later than October 31, 2016, subject to certain exceptions.

During the nine months ended July 31, 2015, under the ATM program, we sold 1.4 million shares pursuant to two FSAs that must be settled no later than December 15, 2015. Under the terms of each FSA, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligations under the agreements. We expect to settle both FSAs by delivering shares in October 2015. If we physically settle by issuing the shares to the forward counterparties, the forward counterparties will, at settlement, pay us the proceeds less certain adjustments for their sales of the borrowed shares to the underwriters. If we had settled both FSAs by delivery of the combined 1.4 million shares of our common stock on July 31, 2015, we would have received net proceeds of approximately $50.5 million. During the quarter ended July 31, 2015, we did not pay any compensation to the sales agents.

We will not recognize the proceeds from the forward sales and will not record the issuance of such shares until the date of settlement. Upon settlement, we will use the net proceeds from these sales of our common stock to finance capital expenditures, repay outstanding notes under the unsecured CP program and for general corporate purposes. As of July 31, 2015, we have approximately $118.4 million remaining under the ATM program.

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 our fiscal year 2015.

During the nine months ended July 31, 2015 and 2014, we issued $20.4 million and $18.8 million, respectively, of common stock through DRIP and ESPP. Under an underwriting agreement entered into in January 2013, in December 2013, we physically settled two FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. For further information on our common stock, see Note 6 to the condensed consolidated financial statements in this Form 10-Q.

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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 July 31, 2015, our ability to pay dividends was not restricted. On September 2, 2015, the Board of Directors declared a quarterly dividend on common stock of $.33 per share, payable October 15, 2015 to shareholders of record at the close of business on September 24, 2015.

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) to our total capitalization as of July 31, 2015 and 2014, and October 31, 2014, are summarized in the table below.



	July 31				October 31				July 31
In thousands	2015		Percentage		2014		Percentage		2014		Percentage
Short-term debt	$	370,000	12	%	$	355,000	12	%	$	490,000	16	%
Current portion of long-term debt	40,000		1	%	—		—	%	—		—	%
Long-term debt	1,384,450		43	%	1,424,430		46	%	1,174,861		39	%
Total debt	1,794,450		56	%	1,779,430		58	%	1,664,861		55	%
Common stockholders’ equity	1,406,061		44	%	1,308,602		42	%	1,335,804		45	%
Total capitalization (including short-term debt)	$	3,200,511	100	%	$	3,088,032	100	%	$	3,000,665	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 July 31, 2015. 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 July 31, 2015, 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

Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. 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.

Estimated Future Contractual Obligations

During the three months ended July 31, 2015, 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, 2014.

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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 wholly-owned subsidiaries that hold 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 5 and Note 9, respectively, to the condensed consolidated financial statements in this Form 10-Q. The operating leases were discussed in Note 8 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2014. The credit support arrangement and indemnification agreement are discussed in Note 12 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, 2014 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 since October 31, 2014.

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.

In fiscal year 2014, the Board of Directors 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 nine months ended July 31, 2015. Our annual discussion of market risk was included in Item 7A of our Form 10-K as of October 31, 2014. 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 July 31, 2015, we had $370 million of short-term debt outstanding as commercial paper at an interest rate of .19%. 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 $2.7 million during the nine months ended July 31, 2015.

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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 third quarter of fiscal 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 nine months ended July 31, 2015, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2014.

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 July 31, 2015.



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
5/1/15 – 5/31/15	—	$	—	—	2,910,074
6/1/15 – 6/30/15	—	$	—	—	2,910,074
7/1/15 – 7/31/15	—	$	—	—	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 note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of July 31, 2015, our ability to pay dividends was not restricted.

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Item 6. Exhibits



10.1	Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, amended and restated effective March 31, 2015, dated May 1, 2015
10.2	Resolution of Board of Directors, June 5, 2015, establishing compensation for non-management directors
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 at July 31, 2015 and October 31, 2014; (3) Condensed Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2015 and 2014; (4) Condensed Consolidated Statements of Cash Flows for the nine months ended July 31, 2015 and 2014; (5) Condensed Consolidated Statements of Stockholders’ Equity for the nine months ended July 31, 2015 and 2014; and (6) Notes to Condensed Consolidated Financial Statements.

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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 September 3, 2015				/s/ Karl W. Newlin
				Karl W. Newlin
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)



Date September 3, 2015				/s/ Jose M. Simon
				Jose M. Simon
				Vice President and Controller
				(Principal Accounting Officer)

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Piedmont Natural Gas Company, Inc.

Form 10-Q

For the Quarter Ended July 31, 2015

Exhibits



10.1			Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, amended and restated effective March 31, 2015, dated May 1, 2015

10.2			Resolution of Board of Directors, June 5, 2015, establishing compensation for non-management directors

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

Attached files

PIEDMONT NATURAL GAS CO INC Reports

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