Piedmont Natural Gas (PNY) 10-Q 2016 Q3 Quarterly report

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, 2016

or

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

For the transition period from to

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

 (Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Class	Outstanding at September 1, 2016
Common Stock, no par value	83,090,909

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 31, 2016

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	33
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 4.	Controls and Procedures	56
Part II.	Other Information
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 6.	Exhibits	58
	Signatures	59

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)

	July 31, 2016		October 31, 2015
ASSETS
Utility Plant:
Utility plant in service	$	5,700,325	$	5,426,584
Less accumulated depreciation	1,327,811		1,251,940
Utility plant in service, net	4,372,514		4,174,644
Construction work in progress	252,471		170,250
Plant held for future use	7,751		3,155
Total utility plant, net	4,632,736		4,348,049
Other Physical Property, at cost (net of accumulated depreciation of $942 in 2016 and $926 in 2015	316		332
Current Assets:
Cash and cash equivalents	13,487		13,744
Trade accounts receivable(1) (less allowance for doubtful accounts of $3,043 in 2016 and $1,648 in 2015)	60,078		59,248
Income taxes receivable	38,906		11,447
Other receivables	10,345		10,667
Unbilled utility revenues	1,648		17,422
Inventories:
Gas in storage	41,980		68,240
Materials, supplies and merchandise	1,225		1,251
Gas purchase derivative assets, at fair value	4,231		1,343
Regulatory assets	78,420		10,936
Prepayments	19,247		28,903
Other current assets	389		344
Total current assets	269,956		223,545
Noncurrent Assets:
Equity method investments in non-utility activities	239,650		206,956
Goodwill	48,852		48,852
Regulatory assets	341,124		196,726
Income taxes receivable	—		26,023
Marketable securities, at fair value	5,136		4,666
Overfunded postretirement asset	30,320		17,770
Other noncurrent assets	6,618		5,439
Total noncurrent assets	671,700		506,432
Total	$	5,574,708	$	5,078,358
(1) See Note 13 for amounts attributable to affiliates.
See notes to condensed consolidated financial statements.

1

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)

	July 31, 2016			October 31, 2015
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock – no par value – 175 shares authorized	$	—		$	—
Common stock - no par value - shares authorized: 200,000 shares; outstanding: 81,283 in 2016 and 80,883 in 2015	744,131			721,419
Retained earnings	778,409			705,748
Accumulated other comprehensive loss	(344		)	(855		)
Total stockholders’ equity	1,522,196			1,426,312
Long-term debt	1,821,184			1,523,677
Total capitalization	3,343,380			2,949,989
Current Liabilities:
Current maturities of long-term debt	—			40,000
Short-term debt	240,000			340,000
Trade accounts payable (1)	93,835			99,895
Other accounts payable	38,794			52,149
Accrued interest	24,409			29,488
Customers’ deposits	17,006			20,896
General taxes accrued	21,144			27,940
Gas supply derivative liabilities, at fair value	33,300			—
Regulatory liabilities	3,908			13,367
Other current liabilities	8,846			11,861
Total current liabilities	481,242			635,596
Noncurrent Liabilities:
Deferred income taxes	932,338			829,223
Unamortized federal investment tax credits	905			1,027
Accumulated provision for postretirement benefits	15,055			14,975
Gas supply derivative liabilities, at fair value	149,600			—
Regulatory liabilities	598,749			590,301
Conditional cost of removal obligations	20,538			19,712
Other noncurrent liabilities	32,901			37,535
Total noncurrent liabilities	1,750,086			1,492,773
Commitments and Contingencies (Note 10)
Total	$	5,574,708		$	5,078,358
(1) See Note 13 for amounts attributable to affiliates.
See notes to condensed consolidated financial statements.

2

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended   July 31						Nine Months Ended   July 31
	2016			2015			2016			2015
Operating Revenues (1)	$	157,806		$	158,266		$	969,329		$	1,190,462
Cost of Gas (1)	43,035			46,694			343,944			583,199
Margin	114,771			111,572			625,385			607,263
Operating Expenses:
Operations and maintenance	68,867			69,587			215,675			207,162
Depreciation	34,485			32,317			102,215			95,900
General taxes	11,103			11,532			31,908			32,504
Utility income taxes	(6,339		)	(7,097		)	87,660			85,583
Total operating expenses	108,116			106,339			437,458			421,149
Operating Income	6,655			5,233			187,927			186,114
Other Income (Expense):
Income from equity method investments	4,238			5,801			28,025			29,908
Non-operating income	708			673			1,973			1,934
Non-operating expense	(734		)	(1,196		)	(2,972		)	(3,093		)
Income taxes	(1,876		)	(2,097		)	(11,089		)	(11,277		)
Total other income (expense)	2,336			3,181			15,937			17,472
Utility Interest Charges:
Interest on long-term debt	18,783			17,483			56,445			52,432
Allowance for borrowed funds used during construction	(3,819		)	(2,859		)	(9,917		)	(7,935		)
Other	757			2,050			2,844			7,969
Total utility interest charges	15,721			16,674			49,372			52,466
Net Income (Loss)	(6,730		)	(8,260		)	154,492			151,120
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $79 and $13 for the three months ended July 31, 2016 and 2015, respectively, and ($214) and ($787) for the nine months ended July 31, 2016 and 2015, respectively	102			33			(360		)	(1,227		)
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, net of tax of $124 and $198 for the three months ended July 31, 2016 and 2015, respectively, and $557 and $558 for the nine months ended July 31, 2016 and 2015, respectively	206			307			881			872
Net current period benefit activities of equity method investments, net of tax of ($7) and $1 for the three months ended July 31, 2016 and 2015, respectively, and ($5) and ($24) for the nine months ended July 31, 2016 and 2015, respectively	(12		)	2			(10		)	(36		)
Total other comprehensive income (loss)	296			342			511			(391		)
Comprehensive Income (Loss)	$	(6,434	)	$	(7,918	)	$	155,003		$	150,729
Average Shares of Common Stock:
Basic	81,214			79,039			81,095			78,826
Diluted	81,214			79,039			81,392			79,175
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.08	)	$	(0.10	)	$	1.91		$	1.92
Diluted	$	(0.08	)	$	(0.10	)	$	1.90		$	1.91
(1) See Note 13 for amounts attributable to affiliates.
See notes to condensed consolidated financial statements.

3

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Nine Months Ended   July 31
	2016			2015
Cash Flows from Operating Activities:
Net income	$	154,492		$	151,120
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	110,504			104,510
Provision for doubtful accounts	4,542			4,559
Income from equity method investments	(28,025		)	(29,908		)
Distributions of earnings from equity method investments	16,828			22,401
Deferred income taxes, net	102,657			79,423
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	(2,888		)	3,758
Receivables	10,286			14,631
Inventories	26,286			20,274
Settlement of legal asset retirement obligations	(4,836		)	(3,914		)
Regulatory assets	(218,285		)	14,192
Other assets	12,798			18,974
Accounts payable	(12,012		)	(20,651		)
Contributions to benefit plans	(10,392		)	(10,814		)
Accrued/deferred postretirement benefit costs	(2,078		)	582
Gas supply derivatives, at fair value	182,900			—
Regulatory liabilities	(13,377		)	5,180
Other liabilities	(17,288		)	(1,134		)
Net cash provided by operating activities	312,112			373,183
Cash Flows from Investing Activities:
Utility capital expenditures	(379,705		)	(308,559		)
Allowance for borrowed funds used during construction	(9,917		)	(7,935		)
Contributions to equity method investments	(30,642		)	(20,063		)
Distributions of capital from equity method investments	9,994			1,285
Proceeds from sale of property	684			372
Investments in marketable securities	(418		)	(845		)
Other	7,166			5,834
Net cash used in investing activities	(402,838		)	(329,911		)

4

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Nine Months Ended   July 31
	2016			2015
Cash Flows from Financing Activities:
Net (repayments) borrowings – commercial paper	$	(100,000	)	$	15,000
Proceeds from issuance of long-term debt	299,634			—
Repayment of long-term debt	(40,000		)	—
Expenses related to issuance of debt	(3,952		)	(1		)
Issuance of common stock through dividend reinvestment and employee stock plans	16,794			20,358
Dividends paid	(81,919		)	(77,249		)
Other	(88		)	(359		)
Net cash provided by (used in) financing activities	90,469			(42,251		)
Net (Decrease) Increase in Cash and Cash Equivalents	(257		)	1,021
Cash and Cash Equivalents at Beginning of Period	13,744			9,643
Cash and Cash Equivalents at End of Period	$	13,487		$	10,664
Cash Paid During the Period for:
Interest	$	64,422		$	58,147
Income Taxes:
Income taxes paid	$	3,436		$	2,984
Income taxes refunded	173			530
Income taxes, net	$	3,263		$	2,454
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	51,426		$	48,742
See notes to condensed consolidated financial statements.

5

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands, except per share amounts)

								Accumulated
								Other
	Common Stock				Retained			Comprehensive
	Shares	Amount			Earnings			Income (Loss)				Total
Balance, October 31, 2014	78,531	$	636,835		$	672,004		$	(237	)	$	1,308,602
Net Income					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
Balance, October 31, 2015	80,883	$	721,419		$	705,748		$	(855	)	$	1,426,312
Net Income					154,492						154,492
Other Comprehensive Income								511			511
Common Stock Issued	400	22,800									22,800
Expenses from Issuance of Common Stock		(88		)							(88		)
Tax Benefit from Dividends Paid on ESOP Shares					88						88
Dividends Declared ($1.01 per share)					(81,919		)				(81,919		)
Balance, July 31, 2016	81,283	$	744,131		$	778,409		$	(344	)	$	1,522,196
See notes to condensed consolidated financial statements.

6

Piedmont Natural Gas Company, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Summary of Significant Accounting Policies

Significant Accounting Policies

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

Unaudited Interim Financial Information

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

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, 2016 do not necessarily reflect the results to be expected for the full year.

In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

Rate-Regulated Basis of Accounting

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

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (loss) (OCIL). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings. Our regulatory assets and liabilities are detailed in Note 3 to the condensed consolidated financial statements in this Form 10-Q.

7

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Condensed Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Condensed Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans. As discussed below, effective in our first quarter 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information for the specific instrument, location or commodity being valued. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the maturity and settlement of our contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the fair value hierarchy levels as set forth in the fair value guidance.

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

On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our equity method investments for impairment. Each investment is recorded at cost plus post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment. For further information, see Note 13 to the condensed consolidated financial statements in this Form 10-Q.

8

Recently Issued Accounting Standards Update (ASU)

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606), including subsequent ASUs clarifying the guidance	Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect consideration expected to be received in exchange for those goods or services. In doing so, more judgment and estimates may be needed than under current guidance. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of the first period of adoption.	Annual periods (and interim periods within those periods) beginning after December 15, 2017, 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 monitoring specific developments for our industry.
ASU 2015-05, April 2015, Intangibles -Goodwill and Other - Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40)	The amendment provides customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software.	Annual periods (and interim periods within those periods) beginning after December 15, 2015, with early adoption permitted. Entities may adopt the guidance retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.	We intend to elect prospective transition upon adoption of this ASU, whereby we will disclose the effect of this change in accounting principle on the financial statement line items affected.
ASU 2016-01, January 2016, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	The amendment addresses aspects of recognition, measurement, presentation and disclosure of financial instruments. It affects investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment.	Annual periods (and interim periods within those periods) beginning after December 15, 2017.	We are currently evaluating the effect on our financial position, results of operations and cash flows.

9

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018, with early adoption permitted.	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-09, March 2016, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The amendment is intended to simplify several areas of accounting for share-based compensation arrangements. The standard requires that all tax effects of share-based payments at settlement (or expiration) be recorded in the income statement at the time the tax effects arise. The standard also clarifies that excess tax benefits of share-based payments should be classified along with other income tax cash flows as an operating activity in the statement of cash flows, permits employers to withhold shares upon settlement of an award to satisfy an employee's tax liability up to the employee's maximum individual interest tax rate in the relevant jurisdiction without resulting in liability classification of the award with the cash paid by employers classified as a financing activity in the statement of cash flows and permits entities to make an accounting policy election to estimate or use actual forfeitures when recognizing share-based compensation expense.	Annual periods (and interim periods within those periods) beginning after December 15, 2016. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.	We are currently evaluating the effect on our financial position, results of operations and cash flows.

10

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2016-13, June 2016, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	The amendment is intended to replace the incurred loss impairment methodology in current guidance with a methodology that reflects expected credit losses requiring a broader range of reasonable and supportable information for credit loss estimates. The amendment affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and other financial assets having the contractual right to receive cash that are not excluded from the scope. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial assets to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected credit losses that have occurred during the period.	Annual periods (and interim periods within those periods) beginning after December 15, 2019, with early adoption permitted beginning after December 15, 2018.	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-15, August 2016, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments	The amendment is intended to provide specific guidance on eight cash flow classification issues to reduce the diversity in practice. The eight issues are: 1) debt prepayment or debt extinguishment costs, 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, 3) contingent consideration payments made after a business combination, 4) proceeds from the settlement of life insurance claims, 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, 6) distributions received from equity method investees, 7) beneficial interests in securitization transactions and 8) separately identifiable cash flows and application of the predominance principle.	Annual periods (and interim periods within those periods) beginning after December 15, 2017. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.	We are currently evaluating the effect on the presentation of our cash flows.

Reclassifications and Changes in Presentation

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

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

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2. Proposed Acquisition by Duke Energy Corporation

On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy) and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provides for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). At the effective time of the Acquisition, subject to receipt of required regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. Upon consummation of the Acquisition, Piedmont common stock will be delisted from the New York Stock Exchange (NYSE).

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

For information on the January 15, 2016 filing with the North Carolina Utilities Commission (NCUC) for approval of the Acquisition, including the hearing on this matter in July 2016, see Note 3 to the condensed consolidated financial statements in this Form 10-Q. Also, on January 15, 2016, we and Duke Energy filed a joint application with the Tennessee Regulatory Authority (TRA) seeking approval to transfer Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statue due to the change in control. In March 2016, the TRA approved the transfer contingent upon NCUC approval of the Acquisition.

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

In connection with this transaction, during the three months and nine months ended July 31, 2016, we recorded Acquisition and integration-related expenses of $.6 million and $2.6 million, respectively, for costs paid to outside parties, which are reflected in “Operations and maintenance” in “Operating Expenses” in the Condensed Consolidated Statements of Operations and Comprehensive Income. These amounts do not include the cost of company personnel participating in Acquisition-related integration planning activities. Also during the three months and nine months ended July 31, 2016, we recorded incremental share-based compensation expense of $.6 million and $6 million, respectively, from the accelerated vesting, payment and taxation of certain share-based awards for our President and Chief Executive Officer (CEO) and other eligible officers and participants with the issuance of restricted nonvested shares of our common stock in December 2015. These share-based plan costs are reflected in "Operations and maintenance" and related payroll taxes in "General taxes" in "Operating Expenses" in the Condensed Consolidated Statements of Operations and Comprehensive Income. For further information on these accelerated share-based transactions, see Note 12 to the condensed consolidated financial statements in this Form 10-Q.

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3. Regulatory Matters

Rate Regulated Basis of Accounting

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

In thousands	July 31, 2016		October 31, 2015
Regulatory Assets:
Current:
Unamortized debt expense on reacquired debt	$	238	$	238
Amounts due from customers	34,621		—
Environmental costs	1,516		1,513
Deferred operations and maintenance expenses	889		847
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,757
Robeson liquefied natural gas (LNG) development costs	223		381
Derivatives - gas supply contracts held for utility operations	33,300		—
Other	1,406		1,730
Total current	78,420		10,936
Noncurrent:
Unamortized debt expense on reacquired debt	4,488		4,666
Environmental costs	3,989		5,107
Deferred operations and maintenance expenses	3,325		3,997
Deferred pipeline integrity expenses	31,533		29,824
Deferred pension and other retirement benefit costs	17,509		17,861
Amounts not yet recognized as a component of pension and other retirement benefit costs	109,884		114,854
Regulatory cost of removal asset	19,925		19,087
Robeson LNG development costs	—		127
Derivatives - gas supply contracts held for utility operations	149,600		—
Other	871		1,203
Total noncurrent	341,124		196,726
Total	$	419,544	$	207,662

Regulatory Liabilities:
Current:
Amounts due to customers	$	3,908	$	13,367
Noncurrent:
Regulatory cost of removal obligations	533,844		521,478
Deferred income taxes	64,827		68,738
Amounts not yet recognized as a component of pension and other retirement benefit costs	78		85
Total noncurrent	598,749		590,301
Total	$	602,657	$	603,668

Rate Oversight and Rate and Regulatory Actions

North Carolina

In November 2015, we filed a petition with the NCUC seeking authority, under the approved integrity management rider (IMR) mechanism, to change our rates effective December 1, 2015 to collect a total of $40.9 million in annual IMR margin revenues based on IMR-eligible capital investments in integrity and safety projects through September 30, 2015. In December 2015, the NCUC approved the requested IMR rate increase. In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers, which we began recording in January 2016. In May 2016, we filed a petition to update our rates effective June 1, 2016 to collect an additional $7.4 million in annual IMR margin revenues from that approved by the NCUC in December 2015.

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The June 2016 rate adjustment was based on $74.9 million of IMR-eligible capital investments in integrity and safety projects over the six-month period ended March 31, 2016. In May 2016, the NCUC approved the requested IMR rate increase.

In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. Subsequently, we, Duke Energy and the NCUC Public Staff reached an agreement of stipulation and settlement setting forth stipulations and conditions for approval of the proposed Acquisition, which was originally filed with the NCUC in June 2016. Among the stipulations contained in the agreement are:

• Funding by the combined company of annual charitable contributions totaling at least $17.5 million in North Carolina during each of the four years after the Acquisition;

• Commitment by the combined company of $7.5 million for low-income household energy assistance and workforce development programs in North Carolina during the first year after the Acquisition;

• Exclusion of expenses related to the Acquisition, including severance costs, from customer bills;

• Withdrawal of our March 2016 petition requesting approval of deferred accounting treatment for certain distribution integrity management program expenses; and

• A one-time bill credit to our North Carolina customers collectively of $10 million.

A hearing was held on July 18 and 19, 2016. On August 25, 2016, we, Duke Energy and the NCUC Public Staff filed a joint proposed order pursuant to the NCUC's procedural schedule. We are waiting on a ruling from the NCUC at this time.

In March 2016, we filed a petition with the NCUC requesting approval of deferred accounting treatment for certain distribution integrity management program expenses. We proposed this accounting treatment as an extension of the regulatory asset accounting treatment approved by the NCUC in December 2004 for our transmission integrity management program expenses. In June 2016, we agreed to withdraw this deferral request upon the NCUC’s approval of the agreement of stipulation and settlement in the proceeding seeking approval of the Acquisition as discussed above and upon closing of the Acquisition.

In August 2016, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2016. A hearing has been scheduled for October 3, 2016.

South Carolina

In June 2016, we filed testimony with the Public Service Commission of South Carolina (PSCSC) in support of our annual review of purchased gas adjustment and gas purchasing policies for the twelve months ended March 31, 2016. In June 2016, a settlement agreement with the Office of Regulatory Staff (ORS) was filed. A hearing was held on July 14, 2016. In August 2016, 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.

In June 2016, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2016 and a cost and revenue study under the Rate Stabilization Act requesting a change in rates. In August 2016, a settlement agreement was filed with the ORS stipulating an $8.3 million annual increase in margin based on a return on equity of 10.2%, effective November 1, 2016. We are waiting on a ruling from the PSCSC at this time.

Tennessee

In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. In June 2016, the TRA approved the deferred gas cost account balances and issued its written order.

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

In August 2016, 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, 2016 under the Tennessee Incentive Plan (TIP). We are waiting on a ruling from the TRA at this time.

In July 2016, the TRA Staff filed its compliance audit report for operation of our Weather Normalization Adjustment (WNA) rider during the 2015 – 2016 heating season, concluding that we had correctly implemented the WNA rider in all material aspects. The TRA Staff identified an immaterial error that resulted in an under-collection of our WNA revenues and

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recommended a correcting adjustment through the ACA mechanism which we recorded in August 2016. In August 2016, the TRA approved and adopted the TRA Staff’s compliance audit report.

4. Earnings per Share

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

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

	Three Months						Nine Months
In thousands, except per share amounts	2016			2015			2016		2015
Net Income (Loss)	$	(6,730	)	$	(8,260	)	$	154,492	$	151,120
Average shares of common stock outstanding for basic earnings per share	81,214			79,039			81,095		78,826
Contingently issuable shares under ICP awards *	—			—			87		286
Contingently issuable restricted nonvested shares under accelerated ICP awards *	—						182
Contingently issuable shares under FSAs *	—			—			28		63
Average shares of dilutive stock	81,214			79,039			81,392		79,175
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.08	)	$	(0.10	)	$	1.91	$	1.92
Diluted	$	(0.08	)	$	(0.10	)	$	1.90	$	1.91
* The inclusion of 306 and 301 contingently issuable shares in the three months ended July 31, 2016 and 2015, respectively, under ICP awards and FSAs would have been antidilutive.

We accelerated the issuance of shares of common stock under approved ICP awards as permitted under the terms of the Merger Agreement. This acceleration resulted in the issuance of 181,944 restricted nonvested shares of our common stock in December 2015, plus 3,288 restricted nonvested shares of our common stock from the reinvestment of dividends on these shares during the nine months ended July 31, 2016. These restricted nonvested shares of our common stock are included in the calculation of diluted EPS in the table above but excluded in basic EPS and shares of our common stock outstanding because of their restricted nonvested nature. For further information on the acceleration of these shares of our common stock under our employee share-based plans, see Note 12 to the condensed consolidated financial statements in this Form 10-Q.

5. Long-Term Debt Instruments

The NCUC approved debt and equity issuances under an effective debt and equity shelf registration statement up to $1 billion through June 6, 2017. As of July 31, 2016, we have $244.1 million remaining for debt and equity issuances as approved by the NCUC, including the issuance of debt discussed below. For further information on equity transactions, see Note 7 to the condensed consolidated financial statements in this Form 10-Q. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our commercial paper (CP) program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.

On June 6, 2016, we repaid $40 million of our 2.92% senior notes at maturity.

On July 28, 2016, we issued $300 million of unsecured senior notes maturing November 1, 2046 with an interest rate of 3.64% and at a discount of .122% or $366,000 under the registration statement in effect noted above. We have the option to redeem all or part of the notes before May 1, 2046, at a redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the

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indenture, as supplemented, plus 25 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes on or after May 1, 2046, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

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

In thousands	July 31, 2016			October 31, 2015
Principal	$	1,835,000		$	1,575,000
Unamortized debt issuance expenses and discounts	(13,816		)	(11,323		)
Total	1,821,184			1,563,677
Less current maturities	—			40,000
Total long-term debt	$	1,821,184		$	1,523,677

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements.

6. Short-Term Debt Instruments

We have an $850 million five-year revolving syndicated credit facility that expires on December 14, 2020 that has an option to request an expansion up to an additional $200 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million, of which $1.7 million and $1.6 million were issued and outstanding as of July 31, 2016 and October 31, 2015, 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 thirty-day London Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020, provided that we are in compliance with all terms of the agreement.

We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the period.

As of July 31, 2016, we had $240 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 .62%. As of October 31, 2015, our outstanding notes under the CP program, included in the Condensed Consolidated Balance Sheets as stated above, were $340 million at a weighted average interest rate of .22%.

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

In millions	Three Months			Nine Months
Minimum amount outstanding during period	$	240		$	240
Maximum amount outstanding during period	$	530		$	530
Minimum interest rate during period	.52		%	.20		%
Maximum interest rate during period	.68		%	.75		%
Weighted average interest rate during period	.60		%	.54		%

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

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7. Stockholders’ Equity

Capital Stock

Changes in common stock for the nine months ended July 31, 2016 are as follows.

In thousands	Shares	Amount
Balance, October 31, 2015	80,883	$	721,419
Issued to participants in the Employee Stock Purchase Plan (ESPP)	17	962
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (DRIP)	253	14,352
Issued to participants in the ICP	130	7,486
Costs from issuance of common stock		(88		)
Balance, July 31, 2016	81,283	$	744,131

In anticipation of the Acquisition by Duke Energy, we have suspended new investments in our DRIP and ESPP, effective July 31, 2016. During the suspension, we will not issue any common stock under these plans, except if the effective date of the Acquisition occurs on or after October 17, 2016, we will issue common stock for the reinvestment of dividends on the October 14, 2016 regular third-quarter dividend payment date. The DRIP and ESPP will be terminated at or prior to the effective date of the Acquisition.

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) through the end of fiscal year 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.

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 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.

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

Under a FSA that we executed with Merrill on March 11, 2016, 620,000 shares were borrowed from third parties and sold by Merrill, from March 14, 2016 to April 22, 2016, at a weighted average share price of $59.66, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $58.76.

Under a FSA that we executed with JP Morgan on June 10, 2016, 820,000 shares were borrowed from third parties and sold by JP Morgan, from June 13, 2016 to July 29, 2016, at a weighted average share price of $59.79, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $58.89.

In accordance with accounting guidance, we classified the FSAs as of July 31, 2016 as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control. As a result of this classification, no amounts were recorded in the condensed consolidated financial statements until the September 2016 settlement of the FSAs.

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Upon physical settlement of the FSAs, delivery of our shares will result in dilution to our EPS at the settlement date. In quarters prior to any 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 prices described above. See Note 4 to the condensed consolidated financial statements in this Form 10-Q for the dilutive effect of the FSAs on our EPS as of July 31, 2016 with the inclusion of the incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

If we had settled the FSAs by delivery of the combined 1.8 million shares of our common stock to the forward counterparties as of July 31, 2016, we would have received net proceeds of approximately $104.7 million.

On September 1, 2016, we issued 1.8 million shares of our common stock to the forward counterparties in order to physically settle all of the FSAs entered into during 2016 and received net proceeds of $104.7 million. In September 2016, we recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Condensed Consolidated Balance Sheets. Upon settlement, we used the net proceeds from the FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. We do not expect to enter into another FSA through the remainder of this fiscal year.

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

	Three Months				Nine Months
	2016		2015		2016		2015
Cash dividends paid per share of common stock	$	0.34	$	0.33	$	1.01	$	0.98

Other Comprehensive Income (Loss)

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

	Changes in Accumulated OCIL(1)
	Three Months						Nine Months
In thousands	2016			2015			2016			2015
Accumulated OCIL beginning balance, net of tax	$	(640	)	$	(970	)	$	(855	)	$	(237	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	102			33			(360		)	(1,227		)
Amounts reclassified from accumulated OCIL, net of tax	206			307			881			872
Total current period activity of hedging activities of equity method investments, net of tax	308			340			521			(355		)
Net current period benefit activities of equity method investments, net of tax	(12		)	2			(10		)	(36		)
Accumulated OCIL ending balance, net of tax	$	(344	)	$	(628	)	$	(344	)	$	(628	)
(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, 2016 and 2015.

	Reclassification Out of Accumulated OCIL (1)												Affected Line Items on Condensed Statements of Operations and Comprehensive Income
	Three Months						Nine Months
In thousands	2016			2015			2016			2015
Hedging activities of equity method investments	$	330		$	505		$	1,438		$	1,430		Income from equity method investments
Income tax expense	(124		)	(198		)	(557		)	(558		)	Income taxes
Hedging activities of equity method investments	206			307			881			872
Net benefit activities of equity method investments	(19		)	3			(15		)	(60		)	Income from equity method investments
Income tax expense	7			(1		)	5			24			Income taxes
Net benefit activities of equity method investments	(12		)	2			(10		)	(36		)
Total reclassification for the period, net of tax	$	194		$	309		$	871		$	836
(1) Amounts in parentheses indicate debits to accumulated OCIL.

8. Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 11 to the condensed consolidated financial statements in this Form 10-Q.

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

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, 2016 and October 31, 2015 is as follows.

	July 31, 2016				October 31, 2015
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	26	$	26	$	51	$	51
Mutual funds	217		250		114		185
Total current trading securities	243		276		165		236
Noncurrent trading securities:
Money markets	579		579		465		465
Mutual funds	4,045		4,557		3,625		4,201
Total noncurrent trading securities	4,624		5,136		4,090		4,666
Total trading securities	$	4,867	$	5,412	$	4,255	$	4,902

9. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans with the purchase of financial gas call option derivative instruments (gas purchase options). The accounting guidance related to derivatives and hedging

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requires that we use a gross presentation, based on our election, for the fair value amounts of our gas purchase options. 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, 2016 and October 31, 2015, we had long gas purchase options providing total coverage of 22.2 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held as of July 31, 2016 are for the period from September 2016 through May 2017.

Derivative Assets and Liabilities - Gas Supply Contracts

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

Fair Value Measurements and Quantitative and Qualitative Disclosures

We use gas purchase options as financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these long-dated, fixed quantity gas supply contracts that became effective in the period ended January 31, 2016 should be recorded at fair value.

The costs of our gas cost hedging plans 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, 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 our gas purchase options held for our utility operations. There are no gas purchase options 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 gas purchase options held for utility operations. Our gas purchase options held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivative contracts presented at fair value that are held for our utility operations.

We also have trading securities that are held in rabbi trusts established for certain deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

We classify fair value balances based on the observance of inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. For an updated discussion of our fair value methodology, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.

The following table sets forth, by level of the fair value hierarchy, our financial and nonfinancial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2016 and October 31, 2015. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the three months ended July 31, 2016 and 2015.

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Recurring Fair Value Measurements as of July 31, 2016
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - gas purchase options held for utility operations	$	4,231	$	—	$	—	$	—	$	4,231
Debt and equity securities held as trading securities:
Money markets	605		—		—		—		605
Mutual funds	4,807		—		—		—		4,807
Total fair value assets	$	9,643	$	—	$	—	$	—	$	9,643
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	182,900	$	—	$	182,900

Recurring Fair Value Measurements as of October 31, 2015
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives - gas purchase options held for utility operations	$	1,343	$	—	$	—	$	—	$	1,343
Debt and equity securities held as trading securities:
Money markets	516		—		—		—		516
Mutual funds	4,386		—		—		—		4,386
Total fair value assets	$	6,245	$	—	$	—	$	—	$	6,245

In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our gas supply derivative contracts in the mid to later years of contract terms ranged from $2.62 to $4.80 per dekatherm.

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

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the three months and nine months ended July 31, 2016.

In thousands	Three Months		Nine Months
Gas supply derivative liabilities, beginning balance	$	164,900	$	—
Realized and unrealized losses:
Recorded to regulatory assets *	18,000		182,900
Purchases, sales and settlements (net)	—		—
Transfer in/out of Level 3	—		—
Gas supply derivative liabilities, ending balance	$	182,900	$	182,900
* Included are the actual costs recorded in "Cost of Gas" in the Condensed Consolidated Statements of Operations and Comprehensive Income due to the confidential nature of contract pricing.

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

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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.

Our regulated utility segment gas purchase options 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 gas purchase options are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these gas purchase options 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 operation of the hedging programs of the regulated utility segment as a result of the use of these gas purchase options is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 3 to the condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates. These gas purchase options are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

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

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

Fair Value of Derivative Instruments
	July 31,		October 31,
In thousands	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Financial Asset Instruments:
Current Assets – Gas purchase derivative assets	$	4,231	$	1,343
Nonfinancial Liability Instruments:
Current Liabilities – Gas supply derivative liabilities	33,300
Noncurrent Liabilities – Gas supply derivative liabilities	149,600

The following table presents the impact that our gas purchase options 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, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.

	Amount of Loss Recognized on Derivative Instruments and Deferred Under PGA Procedures												Location of Loss Recognized through PGA Procedures
	Three Months Ended   July 31						Nine Months Ended   July 31
In thousands	2016			2015			2016			2015
Gas purchase options	$	(886	)	$	(1,007	)	$	(4,428	)	$	(3,296	)	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.

We would have recorded an unrealized loss of $18 million and $182.9 million related to our gas supply derivative contracts in the Condensed Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2016, respectively, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas

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supply derivative contracts in the Condensed Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of Gas" in the month purchased.

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

In thousands	Principal		Fair Value
As of July 31, 2016	$	1,835,000	$	2,131,778
As of October 31, 2015	1,575,000		1,720,586

Credit and Counterparty Risk

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

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Condensed Consolidated Balance Sheets attributable to these entities amounted to $9.2 million, or approximately 15%, of our gross trade accounts receivable as of July 31, 2016. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

Risk Management

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

10. Commitments and Contingent Liabilities

Long-term Contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are fully recoverable subject to our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to twenty years. The time periods for fixed payments of reservation fees under gas supply contracts are up to one year. The time periods for the gas supply purchase commitments is up to fifteen years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to maintain our right to access the natural gas storage or the pipeline

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

Surety Bonds

In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of July 31, 2016, we had open surety bonds with a total contingent obligation of $6.5 million.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and have recorded estimated environmental liabilities, including those for our manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs). There were no material changes in the status of environmental-related matters during the nine months ended July 31, 2016.

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

Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

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

11. Employee Benefit Plans

Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). Under the new HRA, participating eligible retirees and their dependents will receive a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical and dental expenses.

Beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We replaced the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to

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determine the benefit obligations of the relevant projected cash flows. This change improves the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provides a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

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

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2016			2015			2016		2015		2016			2015
Service cost	$	2,750		$	2,452		$	—	$	—	$	294		$	295
Interest cost	2,400			3,063			40		52		321			369
Expected return on plan assets	(6,000		)	(5,860		)	—		—		(442		)	(459		)
Amortization of prior service (credit) cost	(550		)	(548		)	52		58		(83		)	—
Amortization of actuarial loss	2,100			2,407			20		21		115			7
Total	$	700		$	1,514		$	112	$	131	$	205		$	212

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2016			2015			2016		2015		2016			2015
Service cost	$	8,250		$	8,552		$	—	$	—	$	883		$	886
Interest cost	7,200			9,013			118		157		962			1,107
Expected return on plan assets	(18,000		)	(17,710		)	—		—		(1,325		)	(1,378		)
Amortization of prior service (credit) cost	(1,650		)	(1,648		)	156		173		(249		)	—
Amortization of actuarial loss	6,300			6,507			61		64		344			22
Total	$	2,100		$	4,714		$	335	$	394	$	615		$	637

In November 2015, we contributed $10 million to the qualified pension plan, and in January 2016, we contributed $1.8 million to the money purchase pension plan. During the nine months ended July 31, 2016, we contributed $.4 million to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans in 2016.

In thousands
Nonqualified pension plans	$	129
OPEB plan	1,300

We have a non-qualified defined contribution restoration plan (DCR plan) for certain officers at the vice president level and above where benefits payable under the plan are funded from time to time, typically annually. For the nine months ended July 31, 2016, we contributed $.5 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As of July 31, 2016, we have a liability of $5.7 million for these plans.

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

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12. Employee Share-Based Plans

Liability Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. We have granted three series of awards, each with a three-year performance period ending October 31, 2016 (2016 plan), October 31, 2017 (2017 plan) and October 31, 2018 (2018 plan). 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, 2016 and 2015, we recorded compensation expense, and as of July 31, 2016 and October 31, 2015, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value each quarter and at the settlement date. The award with the performance period that ended October 31, 2015 was paid out to participants in December 2015. The 2016 plan and 2017 plan were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.

The 2018 plan was approved subsequent to the execution of the Merger Agreement with Duke Energy. Under the Merger Agreement, the 2018 plan performance awards will be converted into Duke Energy restricted stock unit awards (Duke Energy RSU Award) upon consummation of the Acquisition. Vesting under the Duke Energy RSU Award will be subject to the participant remaining continuously employed by Duke Energy or its affiliates through the performance period ending October 31, 2018. The Duke Energy RSU Award will be subject to 100% accelerated vesting upon certain types of terminations of employment and prorated accelerated vesting upon retirement.

Also under our approved ICP, 64,700 nonvested restricted stock units (RSUs) were granted to our President and CEO in December 2011. During the five-year vesting period, any dividend equivalents accrue on these stock units and are converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The RSUs vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014 and 30% of the units vested on December 15, 2015. The remaining 50% of the units that vest on December 15, 2016 (2016 RSU) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below. For the three months and nine months ended July 31, 2016 and 2015, we recorded compensation expense, and as of July 31, 2016 and October 31, 2015, we accrued a liability for nonvested RSUs, as applicable, based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value each quarter and at the settlement date.

The December 15, 2015 vesting covered 30% of the grant, including accrued dividends, for a total of 22,434 shares of common stock. After withholdings of $.6 million for federal and state income taxes, our President and CEO received 11,732 shares of our common stock at the NYSE composite closing price on December 14, 2015 of $56.85 per share.

The compensation expense related to the incentive compensation plans for the three months and nine months ended July 31, 2016 and 2015, and the amounts recorded as liabilities in “Other noncurrent liabilities” in “Noncurrent Liabilities” with the current portion recorded in “Other current liabilities” in “Current Liabilities” in the Condensed Consolidated Balance Sheets as of July 31, 2016 and October 31, 2015 are presented below.

	Three Months				Nine Months
In thousands	2016		2015		2016		2015
Compensation expense	$	1,534	$	1,317	$	9,400	$	4,596

	July 31, 2016		October 31, 2015
Liability	$	12,895	$	22,037

The Merger Agreement provides for the conversion of the shares subject to the RSUs and ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the 2016 RSU for our President and CEO (accelerated RSU) and the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at his and their elections to accelerate, in the form of restricted nonvested shares of our common stock, net of

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shares withheld for applicable taxes. The acceleration of the vesting and payment of these awards will mitigate the effects of Section 280G of the Internal Revenue Code of 1986, as amended, including increasing the deductibility of such payments for the Company. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, and the 2016 RSU, per the election of our President and CEO, occurred on December 15, 2015.

In connection with the election to accelerate the ICP awards and the 2016 RSU, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of common stock resulting from the reinvestment of dividends paid with respect to these shares of common stock that are required to be reinvested in additional shares of common stock, to the extent the shares of common stock would not otherwise have been earned or payable absent the acceleration. Under the share repayment agreements, the restricted nonvested shares of common stock delivered to the participants, including dividends paid by the Company and reinvested as discussed above, may not be transferred or encumbered until such shares of common stock are no longer subject to repayment under the applicable repayment agreement.The restricted nonvested shares of common stock and dividends earned on those shares of common stock are subject to full or partial cancellation if the Acquisition is not consummated or the participant leaves the Company prior to consummation of the Acquisition. In accordance with accounting guidance, we have not presented these restricted nonvested shares as shares outstanding or included them in our calculation of basic EPS as they are contingent shares until earned; as applicable, they are included in our calculation of diluted EPS in Note 4 to the condensed consolidated financial statements in this Form 10-Q. The participants otherwise have all rights of shareholders with respect to the restricted nonvested shares of common stock.

The accelerated ICP awards and the accelerated RSU were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted nonvested shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes. The gross value of the shares issued for the accelerated ICP awards was $17.4 million, or $9.2 million net of federal and state tax withholdings.

Under the accelerated 2016 RSU, 19,554 restricted nonvested shares of our common stock were issued to our President and CEO, net of shares withheld for applicable federal and state income taxes. The gross value of the shares issued for the accelerated RSU was $2.1 million, or $1.1 million net of federal and state tax withholdings.

Equity Plan

On a quarterly basis, we issue shares of common stock under the ESPP and account for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the average of the high and low trading prices on the purchase date.

In anticipation of the consummation of the Acquisition, we suspended new investments in the ESPP and resulting issuances of common stock under the ESPP, effective July 31, 2016. The ESPP will be terminated at or prior to the effective date of the Acquisition.

13. Equity Method Investments

The condensed consolidated financial statements include the accounts of wholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Condensed Consolidated Statements of Operations and Comprehensive Income.

Ownership Interests

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

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Entity Name	Interest	Activity
Cardinal Pipeline Company, LLC (Cardinal)	21.49%	Intrastate pipeline located in North Carolina; regulated by the NCUC
Pine Needle LNG Company, LLC (Pine Needle)	45%	Interstate LNG storage facility located in North Carolina; regulated by the FERC
SouthStar Energy Services LLC (SouthStar)	15%	Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois
Hardy Storage Company (Hardy Storage)	50%	Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
Constitution Pipeline Company LLC (Constitution)	24%	To develop, construct, own and operate 124 miles of interstate natural gas pipeline and related facilities, connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC
Atlantic Coast Pipeline, LLC (ACP)	10%	To develop, construct, own and operate approximately 600 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of diverse eastern gas supplies into southeastern markets; regulated by the FERC

Accumulated Other Comprehensive Income (Loss)

As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. SouthStar uses financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts is based on selected market indices. Retirement benefits are allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. For these transactions with these equity method investees, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Condensed Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments and the retirement benefits are presented in “Other Comprehensive Income (Loss), net of tax” in the Condensed Consolidated Statements of 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, 2016 and 2015, these gas costs and the amounts we owed to our equity method investees as of July 31, 2016 and October 31, 2015 are as follows.

Related Party	Type of Expense	Cost of Gas (1)								Trade accounts payable (2)
		Three Months				Nine Months				July 31, 2016		October 31, 2015
In thousands		2016		2015		2016		2015
Cardinal	Transportation costs	$	2,198	$	2,207	$	6,550	$	6,556	$	741	$	744
Hardy Storage	Gas storage costs	2,322		2,322		6,967		6,967		774		774
Pine Needle	Gas storage costs	2,535		2,833		8,141		8,609		854		955
Totals		$	7,055	$	7,362	$	21,658	$	22,132	$	2,369	$	2,473
(1) In the Condensed Consolidated Statements of Operations and Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

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

	Operating Revenues (1)								Trade accounts receivable (2)
	Three Months				Nine Months				July 31, 2016		October 31, 2015
In thousands	2016		2015		2016		2015
Operating revenues	$	34	$	475	$	286	$	1,058	$	2	$	183
(1) In the Condensed Consolidated Statements of Operations and Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

Other Information

SouthStar

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

Constitution

A subsidiary of The Williams Companies is the operator of the Constitution pipeline project. The total estimated cost of the project is $1.1 billion, including an allowance for funds used during construction (AFUDC).

On April 22, 2016, the New York State Department of Environmental Conservation (NYSDEC) denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution filed legal actions in the U.S District Court for the Northern District of New York and in the U.S Court of Appeals for the Second Circuit challenging the legality and appropriateness of the NYSDEC’s decision. Both courts granted Constitution's motions to expedite the schedules for the legal actions.

Constitution has stated that it remains steadfastly committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC's decision. In light of the denial of the certification, Constitution revised its target in-service date to the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded.

In July 2016, Constitution requested and the FERC approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. The NYAG filed a motion for reconsideration of this order.

Our investment in Constitution totaled $93.6 million as of July 31, 2016. We evaluated our investment in the Constitution project for OTTI since the NYSDEC denied Constitution’s application for the water quality certification. Our impairment assessment uses a discounted cash flow income approach, including consideration of the severity and duration of any decline in fair value of our investment in the project. Our key inputs involve significant management judgments and estimates, including projections of the project’s cash flows, selection of a discount rate and probability weighting of potential outcomes of legal and regulatory proceedings. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are at very early stages given the recent actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory

29

actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. For information on our evaluation process, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.

We believe that the denial of the certification and resulting delay in the project’s in-service date will not have a material impact on the Acquisition by Duke Energy that is expected to close by the end of 2016.

Pending the outcome of the matters described above, and when construction proceeds, we remain committed to fund the project in an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $955 million, excluding AFUDC, subject to the terms of the LLC agreement. Our total anticipated contributions are approximately $229.3 million. As of July 31, 2016, our contributions for the quarter and fiscal year 2016 were $.5 million and $10.2 million, respectively, with our total equity contribution for the project totaling $82.9 million to date. The capacity of the pipeline is 100% subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

ACP

A subsidiary of Dominion Resources, Inc. (Dominion) is the operator of the ACP pipeline project. The total cost of the project is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 60% of the total costs during the construction period, and a project capitalization ratio of 50% debt and 50% equity when operational.

We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline. As of July 31, 2016, our contributions for the quarter and fiscal year 2016 were $10 million and $20.4 million, respectively, with our total equity contributions for the project totaling $31 million to date.

ACP is regulated by the FERC and subject to state and other federal approvals with a target in-service date that has moved into 2019. The capacity of ACP is substantially subscribed by affiliates of the members of ACP and another utility under twenty-year contracts.

ACP filed its application in September 2015 to request FERC authorization to construct and operate the project facilities under the previously FERC-approved pre-filing process, including the environmental review for the natural gas pipeline. FERC approval of the application of the certificate of public convenience and necessity is expected in mid-2017 with construction projected to begin in late summer of 2017.

On April 15, 2016, Dominion, on behalf of ACP, filed an updated application with the FERC. The filing included, among other items, updated alignment sheets, tables and information regarding the alternative routes adopted by the partners since filing a certificate application in September.

On August 12, 2016, the FERC issued its notice of schedule for environmental review of the project. Under the notice of schedule, we anticipate that the FERC will issue a draft of its environmental impact statement (EIS) in December 2016 and the final EIS in the summer of 2017. Based on this schedule, ACP is reviewing the timing of the project, as well as refining the project cost estimates.

On March 2, 2015, ACP entered into a Precedent Agreement with Dominion Transmission, Inc. (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

30

under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company.

On October 24, 2015, Piedmont entered into a Merger Agreement with Duke Energy. The ACP Limited Liability Company Agreement includes provisions that grant Dominion an option, exercisable following consummation of the Acquisition, to purchase additional ownership interests in ACP from Duke Energy to maintain a majority ownership percentage relative to all other members. After consummation of the Acquisition, Duke Energy, together with our ownership, would have a 50% membership interest unless Dominion exercises its option.

14. Variable Interest Entities

As of July 31, 2016, we have determined that we are not the primary beneficiary under variable interest entity (VIE) accounting guidance in any of our equity method investments, as presented in Note 13 to the condensed consolidated financial statements in this Form 10-Q. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance, and we will continue to apply equity method accounting to these investments.

Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity included in "Equity method investments in non-utility activities" in "Noncurrent Assets" in the Condensed Consolidated Balance Sheets. As of July 31, 2016 and October 31, 2015, our investment balances are as follows.

In thousands	July 31, 2016		October 31, 2015
Cardinal	$	14,456	$	15,083
Pine Needle	17,155		18,396
SouthStar	41,371		41,325
Hardy Storage	41,753		39,706
Constitution	93,587		82,403
ACP	31,328		10,043
Total equity method investments in non-utility activities	$	239,650	$	206,956

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

15.     Business Segments

We have three reportable business segments, regulated utility, regulated non-utility and unregulated non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.

Operations of the regulated utility segment are reflected in “Operating Income” in the Condensed Consolidated Statements of 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

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and assess performance of our three business segments. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the regulated and unregulated non-utility activities segments based on earnings and cash flows from the ventures.

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

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

	Regulated Utility						Regulated Non-Utility Activities						Unregulated Non-Utility Activities						Total
In thousands	2016			2015			2016			2015			2016			2015			2016			2015
Three Months
Revenues from external customers	$	157,806		$	158,266		$	—		$	—		$	—		$	—		$	157,806		$	158,266
Margin	114,771			111,572			—			—			—			—			114,771			111,572
Operations and maintenance expenses	68,867			69,587			16			19			58			49			68,941			69,655
Income from equity method investments	—			—			1,229			3,894			3,009			1,907			4,238			5,801
Operating income (loss) before income taxes	316			(1,864		)	(121		)	(89		)	(76		)	(68		)	119			(2,021		)
Income (loss) before income taxes	(15,233		)	(18,904		)	1,108			3,805			2,932			1,839			(11,193		)	(13,260		)
Nine Months
Revenues from external customers	$	969,329		$	1,190,462		$	—		$	—		$	—		$	—		$	969,329		$	1,190,462
Margin	625,385			607,263			—			—			—			—			625,385			607,263
Operations and maintenance expenses	215,675			207,162			49			70			126			96			215,850			207,328
Income from equity method investments	—			—			9,495			11,242			18,530			18,666			28,025			29,908
Operating income (loss) before income taxes	275,587			271,697			(154		)	(140		)	(232		)	(203		)	275,201			271,354
Income before income taxes	225,601			218,414			9,341			11,102			18,299			18,464			253,241			247,980

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

	Three Months					Nine Months
In thousands	2016		2015			2016			2015
Operating Income (Loss):
Segment operating income (loss) before income taxes	$	119	$	(2,021	)	$	275,201		$	271,354
Utility income taxes	6,339		7,097			(87,660		)	(85,583		)
Regulated non-utility activities operating loss before income taxes	121		89			154			140
Unregulated non-utility activities operating loss before income taxes	76		68			232			203
Operating income	$	6,655	$	5,233		$	187,927		$	186,114

Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(11,193	)	$	(13,260	)	$	253,241		$	247,980
Income taxes	4,463			5,000			(98,749		)	(96,860		)
Total	$	(6,730	)	$	(8,260	)	$	154,492		$	151,120

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16. Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters, stockholders' equity and equity method investments, see Note 3, Note 7 and Note 13, respectively, to the condensed consolidated financial statements in this Form 10-Q.

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

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

Forward-Looking Statements

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

• Economic conditions in our markets.

• Wholesale price of natural gas.

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

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

• Competition from other companies that supply energy.

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

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

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

• Weather conditions.

• Operational interruptions to our gas distribution and transmission activities.

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

• Elevated levels of capital expenditures.

• Changes to our credit ratings.

• Availability and cost of capital.

• Federal and state fiscal, tax and monetary policies.

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

• Ability to satisfy all of our outstanding debt obligations.

• Ability of counterparties to meet their obligations to us.

• Costs of providing pension benefits.

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

• Ability to attract and retain professional and technical employees.

• Cybersecurity breaches or failure of technology systems.

• Ability to obtain and maintain sufficient insurance.

• Change in number of outstanding shares.

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

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

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

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

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

• future shareholder suits could delay or prevent the closing of the Acquisition or otherwise adversely impact our business and operations.

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

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

Overview

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

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

	Assets		Earnings Before Taxes
Regulated Utility	96	%	89	%
Non-utility Activities:
Regulated non-utility activities	3	%	4	%
Unregulated non-utility activities	1	%	7	%
Total non-utility activities	4	%	11	%

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

34

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 proposed air emissions regulations that would expand to include emissions of methane. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

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

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

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

	2016		2015
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers,
Tennessee and North Carolina IMRs and fixed-rate contracts)	76	%	74	%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)	15	%	16	%
Volumetric or periodic renegotiation (including secondary marketing activity)	9	%	10	%
Total	100	%	100	%

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

• Promote the benefits of natural gas,

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

• Be the energy service provider of choice,

• Achieve excellence in customer service every time,

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• Preserve financial strength and flexibility,

• Execute sustainable business practices, and

• Enhance our healthy high performance culture.

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

Executive Summary

Financial Performance – Quarter Ended 2016 Compared with Quarter Ended 2015

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

Comprehensive Statement of Operations Components
	Three Months Ended July 31
In thousands, except per share amounts	2016			2015			Variance			Percent Change
Operating Revenues	$	157,806		$	158,266		$	(460	)	—	%
Cost of Gas	43,035			46,694			(3,659		)	(8	)%
Margin	114,771			111,572			3,199			3	%
Operations and Maintenance	68,867			69,587			(720		)	(1	)%
Depreciation	34,485			32,317			2,168			7	%
General Taxes	11,103			11,532			(429		)	(4	)%
Utility Income Taxes	(6,339		)	(7,097		)	758			11	%
Total Operating Expenses	108,116			106,339			1,777			2	%
Operating Income	6,655			5,233			1,422			27	%
Other Income (Expense), net of tax	2,336			3,181			(845		)	(27	)%
Utility Interest Charges	15,721			16,674			(953		)	(6	)%
Net Loss	$	(6,730	)	$	(8,260	)	$	1,530		19	%
Average Shares of Common Stock:
Basic	81,214			79,039			2,175			3	%
Diluted	81,214			79,039			2,175			3	%
Loss Per Share of Common Stock:
Basic	$	(0.08	)	$	(0.10	)	$	0.02		20	%
Diluted	$	(0.08	)	$	(0.10	)	$	0.02		20	%

Margin by Customer Class
	Three Months Ended July 31
In thousands	2016				2015
Sales and Transportation:
Residential	$	47,951	42	%	$	44,897	40	%
Commercial	28,145		25	%	27,326		25	%
Industrial	11,593		10	%	11,909		11	%
Power Generation	19,361		17	%	19,352		17	%
For Resale	2,636		2	%	3,471		3	%
Total	109,686		96	%	106,955		96	%
Secondary Market Sales	3,646		3	%	3,269		3	%
Miscellaneous	1,439		1	%	1,348		1	%
Total	$	114,771	100	%	$	111,572	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees
	Three Months Ended July 31
	2016		2015		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	3,112		2,687		425		16	%
Commercial	5,191		4,724		467		10	%
Industrial	21,422		21,086		336		2	%
Power Generation	75,335		75,562		(227	)	—	%
For Resale	918		855		63		7	%
Throughput	105,978		104,914		1,064		1	%
Secondary Market Volumes	13,601		5,246		8,355		159	%
Customers Billed (at period end)	1,029,698		1,014,159		15,539		2	%
Gross Residential, Commercial and Industrial Customer Additions	3,920		3,745		175		5	%
Degree Days
Actual	49		12		37		308	%
Normal	46		47		(1	)	(2	)%
Percent colder (warmer) than normal	7	%	(74	)%	n/a		n/a
Number of Employees (at period end)	1,975		1,939		36		2	%

We closed our third quarter with a lower net loss in the current period, a 19% increase in net income. Margin increased 3% due to IMR rate adjustments and customer growth. Depreciation increased 7% primarily due to increases in plant in service.

Financial Performance – Nine Months Ended 2016 Compared with Nine Months Ended 2015

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

Comprehensive Statement of Operations Components
	Nine Months Ended July 31
In thousands, except per share amounts	2016		2015		Variance			Percent Change
Operating Revenues	$	969,329	$	1,190,462	$	(221,133	)	(19	)%
Cost of Gas	343,944		583,199		(239,255		)	(41	)%
Margin	625,385		607,263		18,122			3	%
Operations and Maintenance	215,675		207,162		8,513			4	%
Depreciation	102,215		95,900		6,315			7	%
General Taxes	31,908		32,504		(596		)	(2	)%
Utility Income Taxes	87,660		85,583		2,077			2	%
Total Operating Expenses	437,458		421,149		16,309			4	%
Operating Income	187,927		186,114		1,813			1	%
Other Income (Expense), net of tax	15,937		17,472		(1,535		)	(9	)%
Utility Interest Charges	49,372		52,466		(3,094		)	(6	)%
Net Income	$	154,492	$	151,120	$	3,372		2	%
Average Shares of Common Stock:
Basic	81,095		78,826		2,269			3	%
Diluted	81,392		79,175		2,217			3	%
Earnings Per Share of Common Stock:
Basic	$	1.91	$	1.92	$	(0.01	)	(1	)%
Diluted	$	1.90	$	1.91	$	(0.01	)	(1	)%

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Margin by Customer Class
	Nine Months Ended July 31
In thousands	2016				2015
Sales and Transportation:
Residential	$	340,397	55	%	$	324,561	54	%
Commercial	157,708		25	%	151,975		25	%
Industrial	39,485		6	%	37,941		6	%
Power Generation	57,817		9	%	57,961		10	%
For Resale	8,888		2	%	8,635		1	%
Total	604,295		97	%	581,073		96	%
Secondary Market Sales	14,773		2	%	19,219		3	%
Miscellaneous	6,317		1	%	6,971		1	%
Total	$	625,385	100	%	$	607,263	100	%

Gas Deliveries, Customers, Weather Statistics and Number of Employees
	Nine Months Ended July 31
	2016		2015		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	45,070		56,973		(11,903	)	(21	)%
Commercial	32,336		37,669		(5,333	)	(14	)%
Industrial	73,584		73,711		(127	)	—	%
Power Generation	224,555		196,278		28,277		14	%
For Resale	5,184		6,203		(1,019	)	(16	)%
Throughput	380,729		370,834		9,895		3	%
Secondary Market Volumes	48,292		26,230		22,062		84	%
Customers Billed (at period end)	1,029,698		1,014,159		15,539		2	%
Gross Residential, Commercial and Industrial Customer Additions	12,593		12,248		345		3	%
Degree Days
Actual	2,512		3,279		(767	)	(23	)%
Normal	3,069		3,062		7		—	%
Percent (warmer) colder than normal	(18	)%	7	%	n/a		n/a
Number of Employees (at period end)	1,975		1,939		36		2	%

We closed the first three quarters of fiscal year 2016 with a 2% increase in net income. Margin increased 3% due to IMR rate adjustments and customer growth, partially offset by lower margin sales from secondary market transactions. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Operations and maintenance (O&M) expenses and depreciation expense increased 4% and 7%, respectively. The increase in O&M expenses was related to increases in payroll and direct and indirect Acquisition and integration-related expenses. Depreciation was higher due to increases in plant in service. Other Income (Expense) decreased 9% due to a decrease in income from equity method investments. Utility interest charges decreased 6% as a result of recording interest income on net amounts due from customers compared with interest expense in the prior period and an increase in capitalized interest recorded as income, partially offset by an increase in long-term debt outstanding.

Financial Strength and Flexibility –In order to prudently fund our investment in growth and our ongoing capital needs, we continue to execute our financing program to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%.

In January, March and June 2016, we entered into forward sale agreements (FSAs) under our at-the-market (ATM) equity sales program that was established in January 2015. On September 1, 2016, we issued 1.8 million shares under our ATM equity sales program settling these FSAs, receiving net proceeds of $104.7 million. In July 2016, we issued $300 million of unsecured senior notes maturing November 1, 2046, receiving net proceeds of $297 million. We continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs.

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Managing Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have adequate and reliable supplies of competitively priced natural gas to meet the needs of our utility customers. In order to provide additional diversification, reliability and gas cost benefits to our customers, we have long-term supply and capacity contracts to buy and transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These competitive long-term sources of gas supply became available during the winter 2015 – 2016 season from the Williams – Transco Leidy Southeast expansion project and its Virginia Southside expansion project and replaced other sources of gas within our supply portfolio, supporting our supply diversification strategy. Additional gas supplies from diverse eastern gas supply basins are anticipated to be available under a long-term pipeline capacity firm transportation agreement with Atlantic Coast Pipeline, LLC (ACP) upon completion of the project.

Customer Growth –We continued to have solid customer growth in the third quarter. Affordable and stable wholesale natural gas costs continue to favorably position natural gas relative to other energy sources. Continued targeted marketing programs on the benefits of natural gas should help us to sustain growth comparable to prior years. Residential conversion growth has slowed compared to demand for residential new home construction, impacting growth in these markets during the current period as compared to the same prior period as presented below.

	2016	2015	Percent Change
Residential new home construction	9,574	8,927	7	%
Residential conversion	1,755	2,076	(15	)%
Commercial	1,258	1,238	2	%
Industrial	6	7	(14	)%
Total new customers	12,593	12,248	3	%

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

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

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

In millions	North Carolina			Tennessee
Incremental annual margin revenue - 2014 IMR	$	1.0	(1)	$	13.1
Incremental annual margin revenue - 2015 IMR	24.4		(1)	6.5
Incremental annual margin revenue - 2016 IMR	22.9		(2)	1.7
Total cumulative incremental annual margin revenue as of July 31, 2016 (3)	$	48.3	(1)	$	21.3
Amount recorded during three months ended July 31, 2016	$	7.5		$	2.6
Amount recorded during nine months ended July 31, 2016	33.1			18.5
(1) Amounts reflect incremental annual IMR margin revenue, as adjusted per audit by the NCUC Public Staff under the approved IMR settlement agreement and procedural schedule, which may differ from the amounts reflected in the filed and approved rate adjustments. For further information on the current rate adjustment, see Note 3 to the condensed consolidated financial statements in this Form 10-Q. For further information on the IMR settlement agreement, see Note 3 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015.
(2) Amount reflects additional annual margin revenues of $15.5 million effective December 1, 2015 and $7.4 million effective June 1, 2016 as approved by the NCUC.
(3) IMR recovery periods in both jurisdictions do not align with our fiscal year. For further information on these periods, see Note 3 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015.

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

Equity Method Investments –Our investments in complementary energy-related businesses continue to be an attractive way to generate earnings growth and long-term shareholder returns. We are a member of two ventures that propose to construct interstate natural gas pipelines, subject to the jurisdiction of the FERC. We are a 24% equity member of Constitution Pipeline Company LLC (Constitution) that plans to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. We are a 10% equity member of ACP that plans to transport diverse eastern gas supplies into southeastern markets. The project would also require us to expand our utility natural gas delivery system in eastern North Carolina to provide redelivery of ACP volumes to retail natural gas markets. Having a second major interstate pipeline in the state will enhance the reliability and diversity of gas supplies to our Carolina market area. For further information on our anticipated contributions for these project costs, anticipated in-service dates, contributions made to date and project updates, and our assessment of our investment in Constitution, see "Cash Flows from Investing Activities" in this Form 10-Q. For further information on equity method investments and business segments, see Note 13 and Note 15, respectively, to the condensed consolidated financial statements in this Form 10-Q.

Proposed Acquisition by Duke Energy – In October 2015, we entered into a Merger Agreement with Duke Energy. At the effective time of the Acquisition, subject to receipt of required regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. For further information on the Acquisition, see "Forward-Looking Statements" in Item 2 and Note 2, Note 3 and Note 13 to the condensed consolidated financial statements in this Form 10-Q. In the Merger Agreement, we agreed to covenants, none of which we expect to materially impact our financial condition or results of operations, affecting the conduct of our business between the date of the Merger Agreement and the effective date of the Acquisition. We anticipate the Acquisition to close in 2016.

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

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

On June 21, 2016, Karl Newlin, our Senior Vice President and Chief Financial Officer, was designated by Duke Energy to lead its Gas Commercial Operations, Victor Gaglio, our Senior Vice President and Chief Utility Operations Officer, was designated by Duke Energy to lead its Gas Utility Operations, and Bruce Barkley, our Vice President-Regulatory Affairs, Rates and Gas Cost Accounting, was designated by Duke Energy to lead its Rates and Regulatory and Community Relations for its gas business in our three-state service territory and State Legislative Affairs in Tennessee for its gas business, each effective, and contingent, upon the closing of the Acquisition. Also on June 21, 2016, Jane Lewis-Raymond, Senior Vice President and Chief Legal, Compliance and External Relations Officer of Piedmont, and Kevin M. O’Hara, Senior Vice President and Chief Administrative Officer of Piedmont, each notified Mr. Skains and Duke Energy, of their respective intent to terminate their employment from Piedmont effective, and contingent, upon the closing of the Acquisition.

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

Required filings were made with our state regulatory commissions in January 2016. We and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. In June 2016, an agreement of stipulation and settlement between us, Duke Energy and the NCUC Public Staff was filed, setting forth stipulations and conditions for approval of the proposed Acquisition. For further information on the agreement of stipulation and settlement, see Note 3 to the condensed consolidated financial statements in this Form 10-Q. A hearing was held on July 18 and 19, 2016. We are waiting on a ruling from the NCUC at this time. We and Duke Energy filed a joint application seeking approval from the TRA to transfer our operating license to Duke Energy. In March 2016, the TRA approved the transfer contingent upon NCUC approval of the Acquisition. We and Duke Energy discussed the Acquisition of Piedmont with the PSCSC.

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

Additional information on operating results for the three months and nine months ended July 31, 2016 follows.

Operating Revenues

Changes in operating revenues for the three months and nine months ended July 31, 2016 compared with the same periods in 2015 are presented below.

Changes in Operating Revenues - Increase (Decrease)
In millions	Three Months			Nine Months
Residential and commercial customers	$	2.8		$	(246.9	)
Industrial customers	0.5			(6.4		)
Power generation customers	(0.1		)	(0.5		)
Secondary market	(4.8		)	(60.5		)
Margin decoupling mechanism	(2.1		)	51.2
WNA mechanisms	—			20.2
IMR mechanisms	3.2			22.0
Other revenue	—			(0.2		)
Total	$	(0.5	)	$	(221.1	)

• Residential and commercial customers – the increase for the three months is due to higher consumption from colder May weather and customer growth, partially offset by lower wholesale gas costs passed through to customers. The decrease for the nine months is due to lower consumption from warmer weather and lower wholesale gas costs passed through to customers, slightly offset by customer growth.

• Industrial customers – the increase for the three months is primarily due to higher volumes from colder May weather, slightly offset by 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 volumes from warmer weather.

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

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

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

• IMR mechanisms – the increases for the three months and nine months are due to the IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and in North Carolina, effective in February 2015, December 2015 and June 2016.

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Cost of Gas

Changes in cost of gas for the three months and nine months ended July 31, 2016 compared with the same periods in 2015 are presented below.

Changes in Cost of Gas - Increase (Decrease)
In millions	Three Months			Nine Months
Commodity gas costs passed through to sales customers	$	(4.6	)	$	(154.6	)
Commodity gas costs in secondary market transactions	(5.2		)	(56.0		)
Pipeline demand charges	0.2			0.2
Regulatory-approved gas cost mechanisms	5.9			(28.9		)
Total	$	(3.7	)	$	(239.3	)

• Commodity gas costs passed through to sales customers – the decrease for the three months is primarily due to lower wholesale gas costs passed through to sales customers, partially offset by higher consumption due to colder May weather and customer growth. The decrease for the nine months is primarily due to lower wholesale gas costs passed through to sales customers and lower consumption due to warmer weather, slightly offset by customer growth.

• Commodity gas costs in secondary market transactions – the decreases for the three months and nine months are primarily due to lower average wholesale gas costs, slightly offset by increased volumes.

• Pipeline demand charges – the increases for the three months and nine months are due to increased demand costs, partially offset by increased capacity release revenues and asset manager payments.

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

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

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory pass through of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 26% of revenues for the nine months ended July 31, 2016, and our pipeline transportation and storage costs accounted for 10%.

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

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

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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, 2016 compared with the same periods in 2015 are presented below.

Changes in Margin - Increase (Decrease)
In millions	Three Months			Nine Months
Residential and commercial customers	$	3.9		$	21.6
Industrial customers	(1.2		)	1.8
Power generation customers	—			(0.1		)
Secondary market activity	0.4			(4.5		)
Net gas cost adjustments	0.1			(0.7		)
Total	$	3.2		$	18.1

• Residential and commercial customers – the increases for the three months and nine months are primarily due to IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and in North Carolina, effective in February 2015, December 2015 and June 2016, and customer growth in all three states.

• Industrial customers – the decrease for the three months is primarily due to decreased margin recognized from special contracts, partially offset by IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and in North Carolina, effective in February 2015, December 2015 and June 2016. The increase for the nine months is primarily due to IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and in North Carolina, effective in February 2015, December 2015 and June 2016.

• Secondary market activity – the increase for the three months is primarily due to increased volumes, partially offset by lower margin sales. 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, 2016 compared with the same periods in 2015 are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)
In millions	Three Months			Nine Months
Payroll	$	0.9		$	8.6
Acquisition and integration-related expenses	0.6			2.6
Employee benefits	(0.2		)	(1.1		)
Employee expenses	(0.3		)	(1.2		)
Vehicles and transportation	(0.5		)	(1.3		)
Other	(1.2		)	0.9
Total	$	(0.7	)	$	8.5

• Payroll – the increase for the nine months is primarily due to higher equity incentive plan accruals, including $5.6 million incremental expense from the accelerated vesting and payment of incentive awards under provisions in the Merger Agreement, merit increases and additional employees.

• Acquisition and integration-related expenses – the increase for the nine months is due to integration costs paid to outside parties.

• Employee benefits – the decrease for the nine months is primarily due to lower defined benefit plan accruals due to incorporating updated mortality tables and a change in the methodology to calculate net periodic benefit cost.

• Employee expenses – the decrease for the nine months is primarily due to the effectiveness of a management cost savings initiative.

• Vehicles and transportation – the decrease for the nine months is primarily due to lower gasoline and diesel fuel prices.

Depreciation

Depreciation expense increased $2.2 million and $6.3 million for the three months and nine months ended July 31, 2016, respectively, compared with the same periods in 2015 primarily due to increases in plant in service, particularly related to major additions in system integrity investments and natural gas infrastructure.

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.

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Changes in Other Income (Expense) for the three months and nine months ended July 31, 2016 compared with the same periods in 2015 are presented below.

In millions	Three Months			Nine Months
Income from equity method investments:
Constitution	$	(3.3	)	$	(3.4	)
SouthStar	1.1			(0.1		)
ACP	0.4			1.4
Other	0.3			0.3
Total	(1.5		)	(1.8		)
Non-operating income/expense	0.5			0.1
Income taxes	0.2			0.2
Total	$	(0.8	)	$	(1.5	)

• Income from equity method investments from Constitution – the decreases in the three months and nine months are primarily due to suspending capitalized interest costs recorded as income and expensing project development costs after the New York State Department of Environmental Conservation's (NYSDEC) denial of Constitution's application for a necessary water application certification for the New York portion of the Constitution pipeline.

• Income from equity method investments from SouthStar – the increase in the three months is primarily due to a higher value of hedged derivatives and lower operating expenses.

• Income from equity method investments from ACP – the increase in the nine months is primarily due to higher capitalized interest costs.

Utility Interest Charges

Changes in utility interest charges for the three months and nine months ended July 31, 2016 compared with the same periods in 2015 are presented below.

Changes in Utility Interest Charges - Increase (Decrease)
In millions	Three Months			Nine Months
Regulatory interest expense, net	$	(1.7	)	$	(6.3	)
Borrowed AFUDC	(1.0		)	(2.0		)
Interest expense on long-term debt	1.3			4.0
Interest expense on short-term debt	0.5			1.2
Other	(0.1		)	—
Total	$	(1.0	)	$	(3.1	)

• Regulatory interest expense, net – the changes for the three months and nine months are primarily due to interest income on net amounts due from customers compared with interest expense in the prior periods on net amounts due to customers.

• Borrowed allowance for funds used during construction (AFUDC) – the changes for the three months and nine months are primarily due to increased capitalized interest from higher 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.

• Interest expense on short-term debt – the increase for the nine months is primarily due to higher average daily borrowings and higher average interest rates of 33 basis points over the prior period.

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.

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The need for long-term capital is driven by the level of and timing of capital expenditures and long-term debt maturities. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to completion of the Acquisition. Among other restrictions, the Merger Agreement limits, beyond previously budgeted and planned amounts and allowed exceptions, our total capital spending and the extent to which we can obtain financing through long-term debt and equity. It also caps our cash dividend to no more than the current annual per share dividend plus an increase of not more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practices but allows for a stub period dividend payment to holders of record of our shares of common stock immediately prior to consummation of the Acquisition. At this time, as a result of the pending Acquisition, we have not modified our 2016 financing strategy discussed below and do not expect a significant impact on our cash requirements and sources of liquidity.

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

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

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by reduced tax payments due to the generation of federal net operating loss (NOL) carryforwards resulting from bonus depreciation, as well as the ability to recover and earn on investments in infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee. For further information on bonus depreciation, see the following discussion of "Cash Flows from Operating Activities" in this Form 10-Q.

Short-Term Debt

We have an $850 million five-year revolving syndicated credit facility that expires in December 2020 that has an option to request an expansion of financing commitments by an additional $200 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $850 million. The five-year revolving syndicated credit facility contains normal and customary financial covenants and expressly permits the Acquisition by Duke Energy.

We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsecured debt.

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

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In thousands
End of period (July 31, 2016):
Amount outstanding	$	240,000
Weighted average interest rate	.62		%
During the period (May 1, 2016 – July 31, 2016):
Average amount outstanding	$	443,700
Minimum amount outstanding	240,000
Maximum amount outstanding	530,000
Minimum interest rate	.52		%
Maximum interest rate	.68		%
Weighted average interest rate	.60		%
Maximum amount outstanding:
May 2016	$	435,000
June 2016	475,000
July 2016	530,000

As of July 31, 2016, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.7 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of July 31, 2016, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $608.3 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 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 as amounts due to or from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

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

Net cash provided by operating activities was $312.1 million and $373.2 million for the nine months ended July 31, 2016 and 2015, respectively. Net cash provided by operating activities reflects an increase of $3.4 million in net income for 2016

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compared with 2015 primarily due to increased margin and a decrease in utility interest charges, partially offset by increased operating expenses. The effect of changes in cash provided by operating activities is described below.

• Trade accounts receivable and unbilled utility revenues decreased $13.5 million from October 31, 2015 primarily due to a decrease in unbilled revenues.

• Net amounts due from customers increased $44.1 million in the current period primarily due to an increase in margin decoupling revenues, deferred gas cost collections and refunds through rates.

• Gas in storage decreased $26.3 million in the current period primarily due to the withdrawal of storage volumes to meet customer sales during the winter heating season of 2015 – 2016 and a decrease in the weighted average cost of gas purchased for injections.

• Prepaid gas costs decreased $9.9 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 decreased $6.1 million in the current period primarily due to timing of utility capital expenditures.

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

In April 2016, the Internal Revenue Service (IRS) completed their field audit of our 2012 NOL carryback claim, providing their audit report. Accordingly, we reclassified $26 million of noncurrent refundable income taxes to “Income taxes receivable” in “Current Assets” in the Condensed Consolidated Balance Sheets. Since then, the Congressional Joint Committee on Taxation supported the conclusions in the IRS audit report.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee generated charges to customers of $13.2 million and credits to customers of $7 million in the nine months ended July 31, 2016 and 2015, respectively. In Tennessee, adjustments are made directly to individual customer monthly bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities,” as presented in Note 3 to the condensed consolidated financial statements in this Form 10-Q, for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin decoupling mechanism increased margin by $23.7 million and decreased margin by $27.5 million in the nine months ended July 31, 2016 and 2015, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanisms.

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

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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.

On March 17, 2016, the Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation, issued a Notice of Proposed Rulemaking (NPRM) that proposes to revise the pipeline safety regulations applicable to the safety of onshore gas transmission and gathering pipelines. If enacted as proposed, this rulemaking could result in an increase to our O&M expenses. We and others in the natural gas industry provided comments on this NPRM to the PHMSA on July 7, 2016.

Cash Flows from Investing Activities

Net cash used in investing activities was $402.8 million and $329.9 million for the nine months ended July 31, 2016 and 2015, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures for the nine months ended July 31, 2016 and 2015 were $379.7 million and $308.6 million, respectively, primarily for system integrity projects, including natural gas infrastructure projects in 2016.

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

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

In millions	2016		2017		2018
Customer growth and other	$	310	$	325	$	385
System integrity	260		275		195
Total forecasted utility capital expenditures	570		600		580
Forecasted funding of construction in equity method investments	60		40		200
Total	$	630	$	640	$	780

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

Also, in May 2015, we executed an agreement to construct a delivery station and associated compression to provide additional service to Duke Energy’s power generation facility at their Sutton site near Wilmington, North Carolina. Our total investment is estimated to be $13 million with expenditures occurring primarily in our fiscal years 2016 and 2017, and is included in the

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table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges and has a target in-service date of June 2017.

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

	Constitution		ACP
In millions	(24% ownership interest)		(10% ownership interest)
Our anticipated contributions for total project costs	$	229.3	$	450 – 500	(1)
Anticipated in-service date	second half of 2018			2019
Our contributions:
For the nine months ended July 31, 2016	$	10.2	$	20.4
Over life of project to date	$	82.9	$	31.0
(1) Our share of anticipated contributions for total project costs will be revised once the project operator re-evaluates the project costs in relation to changing the in-service date.

In connection with the ACP project, we plan to make additional utility capital investments in our natural gas delivery system, predominately in fiscal 2017 and 2018, of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets we serve. Of that amount, approximately $170 million will be supported by third-party contracts. These expenditures are driving the increase in utility capital expenditures for fiscal 2018 for customer growth as shown above in the schedule of forecasted capital expenditures. With the timing of the in-service date of the project changing as noted above into 2019, we will update our related forecasted capital expenditures as the project estimates are provided by the operator.

Assessment of Our Investment in Constitution

On April 22, 2016, the NYSDEC denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution has filed legal actions in the U.S District Court for the Northern District of New York and in the U.S Court of Appeals for the Second Circuit challenging the legality and appropriateness of the NYSDEC’s decision. Both courts have granted Constitution's motions to expedite the schedules for the legal actions.

In July 2016, Constitution requested and the FERC approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. The NYAG filed a motion for reconsideration of this order.

Constitution has revised its target in-service date to the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded. Failure to ultimately win the legal actions as well as other efforts to obtain the necessary permit would result in recording a non-cash impairment charge of substantially all of our investment in the capitalized project costs. Our investment totaled $93.6 million as of July 31, 2016, the write-off of which could materially adversely impact our earnings.

Based on the NYSDEC’s actions, we evaluated our investment in the Constitution project for other-than-temporary impairment (OTTI). We evaluate our equity method investments for OTTI on a quarterly basis when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss has occurred, we compare our estimate of fair value of the investment to our carrying value and if our consideration of the decline in value is deemed to be other-than-temporary, we would record a non-cash impairment charge that would reduce income and our investment in the joint venture. Generally, an income approach is used where significant judgments and assumptions include future cash flows of the project and the appropriate discount rate. If a comparable investment is available, a market approach could be used to validate the income approach. Different assumptions could affect the timing and amount of any charge recorded in a period.

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Given the nature of the equity method investment, our impairment assessment uses a discounted cash flow income approach, including consideration of the severity and duration of any decline in fair value of our investment in the project. Our key inputs involve significant management judgments and estimates, including projections of the project’s cash flows, selection of a discount rate and probability weighting of potential outcomes of legal and regulatory proceedings. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are at very early stages given the recent actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period.

Qualitative factors that we considered in our OTTI analysis included, but are not limited to:

• The legal actions filed by Constitution and anticipated duration of the proceedings,

• The commitment of the members to the project,

• The commitment of the customers/shippers to the project, one of whom is a 25% member,

• Prior FERC approval of the project,

• The economic viability of the project to move extensive supplies of Marcellus gas into New England markets, considering the lack of alternative capacity in the region, even considering potentially higher costs resulting from delays in the project.

We believe that the denial of the certification and resulting delay in the project’s in-service date will not have a material impact on the Acquisition by Duke Energy that is expected to close by the end of 2016.

With the project on hold, our funding of project costs is on hold until the resolution of the legal actions. We are contractually obligated to provide funding of required operating costs, including our ownership percentage of legal expenses to obtain the necessary permitting for the project and project costs incurred prior to the denial of the water permit. Fiscal 2016 pre-tax earnings from our Constitution investment are expected to be approximately $9 million less than previously forecasted as a result of no capitalized costs being recorded to income and additional legal expenses and other O&M costs, and we expect significantly reduced earnings from the Constitution investment to continue into 2017 until resolution of the legal and regulatory actions. If the legal actions result in the most severe outcome where the project is abandoned, Constitution is obligated under various contracts to pay breakage fees that we would be obligated to fund up to our ownership percentage of 24%, or potentially up to approximately $10 million for us.

Cash Flows from Financing Activities

Net cash provided by (used in) financing activities was $90.5 million and $(42.3) million for the nine months ended July 31, 2016 and 2015, respectively. Funds are primarily provided from long-term debt securities, short-term borrowings, and until July 31, 2016, from the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). We may sell common stock and long-term debt, when market and other conditions favor such long-term financing to maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. Funds are primarily used to finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program when required to maintain target capital structure, pay quarterly dividends on our common stock and for other general corporate purposes.

Outstanding debt under our CP program decreased from $340 million as of October 31, 2015 to $240 million as of July 31, 2016 primarily due to net proceeds received from the issuance of long-term debt. For further information on short-term debt, see Note 6 to the condensed consolidated financial statements in this Form 10-Q and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

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

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Under this shelf registration statement, we established an ATM equity sales program, including a forward sale component, by entering into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or principals (Agents). Under the terms of the Sales Agreements, we may issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170 million (subject to certain exceptions) during the period that began in January 2015 and ending October 31, 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.

A variety of circumstances, including equity market conditions, trading volume in our common stock and other factors outside our control impacted our ability to sell our common stock under the program. The ATM program allowed us, at our option, to sell shares pursuant to FSAs with affiliates of our sales agents (forward counterparties) under the related ATM program sales agreements. Shares sold pursuant to FSAs settled on dates specified by us, which may be substantially after the sales occur but not later than October 31, 2016, subject to certain exceptions. Historically, we have elected to settle any FSAs in shares rather than cash or net settle for all or a portion of our obligation under the agreement. In September 2016, we settled all of the 2016 FSAs in shares as presented below. Under the terms of the Merger Agreement, we would need to obtain Duke Energy's prior consent to cash or net settle a FSA. During the period ended July 31, 2016, we did not pay any compensation to the sales agents.

The table below presents the September 2016 share settlement of the FSAs under the ATM program that were open as of July 31, 2016.

Equity Issuance Transaction	Number of Shares	Settled	Net Proceeds Before Issuance Costs (In thousands)		Net Settlement Price (1) (Per Share)
FSA - executed January 2016	360,000	September 2016	$	20,250	$	56.2494
FSA - executed March 2016	620,000	September 2016	36,178		58.3518
FSA - executed June 2016	820,000	September 2016	48,276		58.8732
Total ATM Program	1,800,000		$	104,704
(1) Net of 1.5% commission plus other adjustments

We used the net proceeds from the FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. As of July 31, 2016, we have approximately $7.1 million remaining under the ATM program. For further information on our common stock and for more details on equity issuance transactions, see Note 7 to the condensed consolidated financial statements in this Form 10-Q.

During the nine months ended July 31, 2016 and 2015, we issued $16.8 million and $20.4 million, respectively, of common stock through DRIP and ESPP. In anticipation of the Acquisition by Duke Energy, we have suspended new investments in our DRIP and ESPP, effective July 31, 2016. During the suspension, we will not issue any common stock under these plans, except if the effective date of the Acquisition occurs on or after October 17, 2016, we will issue common stock for the reinvestment of dividends on the October 14, 2016 regular third-quarter dividend payment date. The DRIP and ESPP will be terminated at or prior to the effective date of the Acquisition.

On June 6, 2016, we repaid $40 million of our 2.92% senior notes at maturity.

On July 28, 2016, we issued $300 million of thirty-year, unsecured senior notes with an interest rate of 3.64%, and at a discount of .122% or $366,000. We used the net proceeds of $297 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

As of July 31, 2016, we have $244.1 million remaining under the shelf registration statement for debt and equity issuances as approved by the NCUC. We issued equity and debt capital in our fiscal year 2016, at such amounts to support our capital investment program and maintain our target capital structure as discussed above. We will continue to monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional funds. However, we do not expect to issue common stock for new investments under our DRIP, ESPP or our ATM program or long-term debt under our debt program as described above during the remainder of fiscal 2016.

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

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, 2016, our ability to pay dividends was not restricted by these note agreements. On September 7, 2016, the Board of Directors declared the regular third quarter dividend on common stock of $.34 per share, payable on the earlier of the effective date of the Acquisition and October 14, 2016. This dividend will be payable to shareholders of record at the close of business on the earlier of the business day immediately preceding the Acquisition and September 23, 2016.

Additionally, on September 7, 2016, the Board of Directors declared a special contingent dividend on common stock of $.34 per share. This special dividend is contingent on the effective date of the Acquisition occurring after September 23, 2016 and is intended to cover the period, if any, between September 23, 2016 (the regular record date of the regular third quarter dividend) and completion of the Acquisition, and will be prorated accordingly. The special contingent dividend will be payable to shareholders of record at the close of business on the earlier of the business day immediately preceding the effective date of the Acquisition and December 23, 2016 and will be payable on the earlier of the effective date of the Acquisition and January 13, 2017. The special contingent dividend is in addition to Piedmont's regular third quarter dividend of $0.34 per share of common stock. In the event that the effective date of the Acquisition occurs after December 23, 2016, this special contingent dividend will constitute the regular fourth quarter dividend.

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 gross long-term debt) to our total capitalization as of July 31, 2016 and 2015, and October 31, 2015, are summarized in the table below.

	July 31				October 31				July 31
In thousands	2016		Percentage		2015		Percentage		2015		Percentage
Short-term debt	$	240,000	7	%	$	340,000	10	%	$	370,000	12	%
Current portion of long-term debt	—		—	%	40,000		1	%	40,000		1	%
Long-term debt, principal	1,835,000		51	%	1,535,000		46	%	1,385,000		43	%
Total debt	2,075,000		58	%	1,915,000		57	%	1,795,000		56	%
Common stockholders’ equity	1,522,196		42	%	1,426,312		43	%	1,406,061		44	%
Total capitalization (including short-term debt)	$	3,597,196	100	%	$	3,341,312	100	%	$	3,201,061	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, 2016. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

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

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

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

debt. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, a change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such

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borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of July 31, 2016, there has been no event of default giving rise to acceleration of our debt.

The Acquisition would constitute a change in control under the note agreements under which our $160 million of 4.24% Senior Notes due 2021, $100 million of 3.47% Senior Notes due 2027 and $200 million of 3.57% Senior Notes due 2027 were issued. While the Acquisition would not constitute an event of default, upon closing of the Acquisition, we would be required to offer to prepay these notes to the noteholders. Within fifteen business days after the change in control, we must send to each noteholder an offer to prepay 100% of the notes, with a prepayment date that is between twenty and thirty days after the date of the offer. In order to accept the offer to prepay, the noteholder must provide a notice of acceptance to us at least five business days prior to the proposed prepayment date. We must prepay noteholders, who have properly accepted the offer, at 100% of the principal amount of the notes, plus interest on the notes accrued to the date of prepayment. A failure of a noteholder to accept the offer to prepay will be deemed a rejection of the offer.

Estimated Future Contractual Obligations

During the three months ended July 31, 2016, we issued $300 million of unsecured senior notes maturing November 1, 2046 with interest payable on May 1 and November 1 of each year, beginning May 1, 2017, through the maturity date of November 1, 2046, at an annual rate of 3.64%. There were no other material changes to our estimated future contractual obligations in Management’s Discussion and Analysis in this Form 10-Q compared to the disclosure provided in our Form 10-K for the year ended October 31, 2015. For an updated schedule of forecasted capital contributions to joint ventures related to a shift in the planned funding for construction related to our equity method investment in Constitution, see the previous discussions of "Cash Flows from Investing Activities" and "Assessment of Our Investment in Constitution" in this Form 10-Q.

Off-balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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

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

As discussed in our Form 10-K for the year ended October 31, 2015 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We replaced the zero-coupon spot rate yield curve as the basis to

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estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. This change improves the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provides a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

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

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

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

We evaluated our investment in the Constitution project for OTTI since the NYSDEC denied Constitution’s application for the water quality certification on April 22, 2016. Our investment is accounted for under the equity method and is recorded at cost plus post-acquisition contributions and earnings based on our ownership share less any distributions received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of the equity method investment, our impairment assessment uses a discounted cash flow income approach, including consideration of the severity and duration of any decline in fair value of our investment in the project. Our key inputs involve significant management judgments and estimates, including projections of the project’s cash flows, selection of a discount rate and probability weighting of potential outcomes of legal and regulatory proceedings. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are at very early stages given the recent actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. For further information on this investment, see Note 13 to the condensed consolidated financial statements in this Form 10-Q.

Accounting Guidance

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

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

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

As of July 31, 2016, we had $240 million of short-term debt outstanding as commercial paper at an interest rate of .63%. 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 $3.2 million during the nine months ended July 31, 2016.

Item 4. Controls and Procedures

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

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the third quarter of fiscal 2016 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, 2016, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2015.

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

c) Issuer Purchases of Equity Securities.

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

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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
5/1/16 – 5/31/16					2,910,074
6/1/16 – 6/30/16					2,910,074
7/1/16 – 7/31/16					2,910,074
Total	—	$	—	—
(1) The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. On that date, the Board also approved an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of July 31, 2016, our ability to pay dividends was not restricted.

Per a provision in the Merger Agreement of the proposed Acquisition with Duke Energy, our cash dividend cannot exceed the current annual per share dividend rate by more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practice. Also, provision is made for a stub period dividend payment to holders of record of our shares of common stock immediately prior to consummation of the Acquisition.

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Item 6. Exhibits

4.1	Eighth Supplemental Indenture, dated July 28, 2016, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated July 28, 2016).
4.2	Form of 3.64% Senior Notes due 2046 (incorporated by reference to Exhibit 4.2, Form 8-K dated July 28, 2016).
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.DEF	XBRL Taxonomy Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Condensed Consolidated Balance Sheets as of July 31, 2016 and October 31, 2015; (3) Condensed Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2016 and 2015; (4) Condensed Consolidated Statements of Cash Flows for the nine months ended July 31, 2016 and 2015; (5) Condensed Consolidated Statements of Stockholders’ Equity for the nine months ended July 31, 2016 and 2015; 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 7, 2016	/s/ Karl W. Newlin
	Karl W. Newlin
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

Date September 7, 2016	/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, 2016

Exhibits

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

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