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EX-31.2 - EXHIBIT 31.2 - PIEDMONT NATURAL GAS CO INCa20160131exhibit312.htm
EX-32.2 - EXHIBIT 32.2 - PIEDMONT NATURAL GAS CO INCa20160131exhibit322.htm
EX-10.4 - EXHIBIT 10.4 - PIEDMONT NATURAL GAS CO INCa20160131exhibit104.htm
EX-31.1 - EXHIBIT 31.1 - PIEDMONT NATURAL GAS CO INCa20160131exhibit311.htm
EX-32.1 - EXHIBIT 32.1 - PIEDMONT NATURAL GAS CO INCa20160131exhibit321.htm
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended January 31, 2016
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                  to                                 
Commission File Number 1-6196
Piedmont Natural Gas Company, Inc.
 (Exact name of registrant as specified in its charter)
North Carolina
 
56-0556998
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
 
 
4720 Piedmont Row Drive, Charlotte, North Carolina
 
28210
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code (704) 364-3120
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ýYes    ¨No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ýYes    ¨No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer  ý
  
Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)
  
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨Yes    ýNo
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 
Class
 
Outstanding at March 1, 2016
Common Stock, no par value
 
81,076,199




Piedmont Natural Gas Company, Inc.
Form 10-Q
for
January 31, 2016
TABLE OF CONTENTS
 
 
 
Page
 
 
 
Part I.
 
 
 
 
Item 1.
 
 
   Condensed Consolidated Balance Sheets
 
   Condensed Consolidated Statements of Comprehensive Income
 
   Condensed Consolidated Statements of Cash Flows
 
   Condensed Consolidated Statements of Stockholders’ Equity
 
   Notes to Condensed Consolidated Financial Statements
Item 2.
Item 3.
Item 4.
 
 
 
Part II.
 
 
 
 
Item 1.
Item 1A.
Item 2.
Item 6.
 
 
 
 



Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(In thousands)
 
January 31,
2016
 
October 31,
2015
ASSETS
 
 
 
Utility Plant:
 
 
 
Utility plant in service
$
5,495,303

 
$
5,426,584

Less accumulated depreciation
1,278,629

 
1,251,940

Utility plant in service, net
4,216,674

 
4,174,644

Construction work in progress
204,628

 
170,250

Plant held for future use
3,155

 
3,155

Total utility plant, net
4,424,457

 
4,348,049

Other Physical Property, at cost (net of accumulated depreciation of $932 in 2016 and $926 in 2015
327

 
332

Current Assets:
 
 
 
Cash and cash equivalents
20,448

 
13,744

Trade accounts receivable(1) (less allowance for doubtful accounts of $3,762 in 2016 and $1,648 in 2015)
158,492

 
59,248

Income taxes receivable
12,877

 
11,447

Other receivables
18,701

 
10,667

Unbilled utility revenues
74,632

 
17,422

Inventories:
 
 
 
Gas in storage
61,135

 
68,240

Materials, supplies and merchandise
1,251

 
1,251

Gas purchase derivative assets, at fair value
1,602

 
1,343

Regulatory assets
61,815

 
10,936

Prepayments
10,697

 
28,903

Other current assets
271

 
344

Total current assets
421,921

 
223,545

Noncurrent Assets:
 
 
 
Equity method investments in non-utility activities
223,277

 
206,956

Goodwill
48,852

 
48,852

Regulatory assets
322,310

 
196,726

Income taxes receivable
26,023

 
26,023

Marketable securities, at fair value
4,842

 
4,666

Overfunded postretirement asset
28,620

 
17,770

Other noncurrent assets
5,751

 
5,439

Total noncurrent assets
659,675

 
506,432

Total
$
5,506,380

 
$
5,078,358

 
 
 
 
(1) See Note 13 for amounts attributable to affiliates.
 
 
 
 
 
 
 
See notes to condensed consolidated financial statements.
 
 
 

1


Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(In thousands)
 
January 31,
2016
 
October 31,
2015
CAPITALIZATION AND LIABILITIES
 
 
 
Capitalization:
 
 
 
Stockholders’ equity:
 
 
 
Cumulative preferred stock – no par value – 175 shares authorized
$

 
$

Common stock - no par value - shares authorized: 200,000 shares; outstanding: 81,072 in 2016 and 80,883 in 2015
732,056

 
721,419

Retained earnings
776,839

 
705,748

Accumulated other comprehensive loss
(487
)
 
(855
)
Total stockholders’ equity
1,508,408

 
1,426,312

Long-term debt
1,523,896

 
1,523,677

Total capitalization
3,032,304

 
2,949,989

Current Liabilities:
 
 
 
Current maturities of long-term debt
40,000

 
40,000

Short-term debt
495,000

 
340,000

Trade accounts payable (1)
120,954

 
99,895

Other accounts payable
38,377

 
52,149

Accrued interest
26,293

 
29,488

Customers’ deposits
22,212

 
20,896

General taxes accrued
12,734

 
27,940

Gas supply derivative liabilities, at fair value
28,300

 

Regulatory liabilities
5,680

 
13,367

Other current liabilities
7,541

 
11,861

Total current liabilities
797,091

 
635,596

Noncurrent Liabilities:
 
 
 
Deferred income taxes
894,429

 
829,223

Unamortized federal investment tax credits
987

 
1,027

Accumulated provision for postretirement benefits
14,944

 
14,975

Gas supply derivative liabilities, at fair value
127,000

 

Regulatory liabilities
590,400

 
590,301

Conditional cost of removal obligations
19,984

 
19,712

Other noncurrent liabilities
29,241

 
37,535

Total noncurrent liabilities
1,676,985

 
1,492,773

Commitments and Contingencies (Note 10)

 

Total
$
5,506,380

 
$
5,078,358

 
 
 
 
(1) See Note 13 for amounts attributable to affiliates.
 
 
 
 
 
 
 
See notes to condensed consolidated financial statements.
 
 
 



2


Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
(In thousands, except per share amounts)
 
Three Months Ended 
 January 31
 
2016
 
2015
Operating Revenues (1)
$
461,337

 
$
607,271

Cost of Gas (1)
175,088

 
337,201

Margin
286,249


270,070

Operating Expenses:
 
 
 
Operations and maintenance
71,300

 
66,150

Depreciation
33,686

 
31,893

General taxes
9,922

 
9,997

Utility income taxes
61,909

 
56,272

Total operating expenses
176,817

 
164,312

Operating Income
109,432


105,758

Other Income (Expense):
 
 
 
Income from equity method investments
9,202

 
8,265

Non-operating income
329

 
630

Non-operating expense
(727
)
 
(700
)
Income taxes
(3,378
)
 
(3,264
)
Total other income (expense)
5,426


4,931

Utility Interest Charges:
 
 
 
Interest on long-term debt
18,839

 
17,489

Allowance for borrowed funds used during construction
(2,805
)
 
(2,272
)
Other
1,034

 
2,494

Total utility interest charges
17,068


17,711

Net Income
97,790

 
92,978

Other Comprehensive Income (Loss), net of tax:
 
 
 
Unrealized loss from hedging activities of equity method investments, net of tax of ($91) and ($600) for the three months ended January 31, 2016 and 2015, respectively
(138
)
 
(944
)
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, net of tax of $327 and $75 for the three months ended January 31, 2016 and 2015, respectively
505

 
117

Net current period benefit activities of equity method investments, net of tax of $1 for the three months ended January 31, 2016
1

 

Total other comprehensive income (loss)
368

 
(827
)
Comprehensive Income
$
98,158

 
$
92,151

Average Shares of Common Stock:
 
 
 
Basic
80,963

 
78,620

Diluted
81,266

 
78,945

Earnings Per Share of Common Stock:
 
 
 
Basic
$
1.21


$
1.18

Diluted
$
1.20


$
1.18

 
 
 
 
(1) See Note 13 for amounts attributable to affiliates.
 
 
 
 
 
 
 
See notes to condensed consolidated financial statements.
 
 
 

3



Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands)
 
Three Months Ended 
 January 31
 
2016
 
2015
Cash Flows from Operating Activities:
 
 
 
Net income
$
97,790

 
$
92,978

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
36,491

 
34,760

Provision for doubtful accounts
2,147

 
2,163

Income from equity method investments
(9,202
)
 
(8,265
)
Distributions of earnings from equity method investments
2,041

 
1,788

Deferred income taxes, net
64,929

 
53,825

Changes in assets and liabilities:
 
 
 
Gas purchase derivatives, at fair value
(259
)
 
3,885

Receivables
(166,935
)
 
(240,738
)
Inventories
7,105

 
(4,997
)
Settlement of legal asset retirement obligations
(895
)
 
(1,024
)
Regulatory assets
(178,598
)
 
14,561

Other assets
19,516

 
28,731

Accounts payable
13,516

 
31,655

Contributions to benefit plans
(10,132
)
 
(10,254
)
Accrued/deferred postretirement benefit costs
(748
)
 
345

Gas supply derivatives, at fair value
155,300

 

Regulatory liabilities
(12,408
)
 
36,369

Other liabilities
(23,761
)
 
(14,183
)
Net cash (used in) provided by operating activities
(4,103
)
 
21,599

Cash Flows from Investing Activities:
 
 
 
Utility capital expenditures
(112,262
)
 
(104,068
)
Allowance for borrowed funds used during construction
(2,805
)
 
(2,272
)
Contributions to equity method investments
(9,107
)
 
(10,019
)
Distributions of capital from equity method investments
551

 
837

Proceeds from sale of property
308

 
112

Investments in marketable securities
(440
)
 
(848
)
Other
2,850

 
85

Net cash used in investing activities
(120,905
)
 
(116,173
)

4


Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands)
 
Three Months Ended 
 January 31
 
2016
 
2015
Cash Flows from Financing Activities:
 
 
 
Net borrowings – commercial paper
$
155,000

 
$
125,000

Expenses related to issuance of debt
(1,161
)
 
(1
)
Issuance of common stock through dividend reinvestment and employee stock plans
4,653

 
5,106

Dividends paid
(26,729
)
 
(25,168
)
Other
(51
)
 
(89
)
Net cash provided by financing activities
131,712

 
104,848

Net Increase in Cash and Cash Equivalents
6,704

 
10,274

Cash and Cash Equivalents at Beginning of Period
13,744

 
9,643

Cash and Cash Equivalents at End of Period
$
20,448

 
$
19,917

 
 
 
 
Cash Paid During the Period for:
 
 
 
Interest
$
22,852

 
$
22,641

Income Taxes:

 

Income taxes paid
$
2,027

 
$
1,378

Income taxes refunded
173

 
530

Income taxes, net
$
1,854

 
$
848

Noncash Investing and Financing Activities:
 
 
 
Accrued capital expenditures
$
52,738

 
$
27,368

 
 
 
 
See notes to condensed consolidated financial statements.
 
 
 

5




Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
(In thousands, except per share amounts)
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
Other
 
 
 
Common Stock
 
Retained
 
Comprehensive
 
 
Shares
 
Amount
 
Earnings
Income (Loss)
 
Total
Balance, October 31, 2014
78,531

 
$
636,835

 
$
672,004

 
$
(237
)
 
$
1,308,602

Net Income
 
 
 
 
92,978

 
 
 
92,978

Other Comprehensive Loss
 
 
 
 
 
 
(827
)
 
(827
)
Common Stock Issued
236

 
8,995

 
 
 
 
 
8,995

Expenses from Issuance of Common Stock
 
 
(137
)
 
 
 
 
 
(137
)
Tax Benefit from Dividends Paid on ESOP Shares
 
 
 
 
32

 
 
 
32

Dividends Declared ($.32 per share)
 
 
 
 
(25,168
)
 
 
 
(25,168
)
Balance, January 31, 2015
78,767


$
645,693


$
739,846


$
(1,064
)

$
1,384,475

 
 
 
 
 
 
 
 
 
 
Balance, October 31, 2015
80,883

 
$
721,419

 
$
705,748

 
$
(855
)
 
$
1,426,312

Net Income
 
 
 
 
97,790

 
 
 
97,790

Other Comprehensive Income
 
 
 
 
 
 
368

 
368

Common Stock Issued
189

 
10,658

 
 
 
 
 
10,658

Expenses from Issuance of Common Stock
 
 
(21
)
 
 
 
 
 
(21
)
Tax Benefit from Dividends Paid on ESOP Shares
 
 
 
 
30

 
 
 
30

Dividends Declared ($.33 per share)
 
 
 
 
(26,729
)
 
 
 
(26,729
)
Balance, January 31, 2016
81,072

 
$
732,056

 
$
776,839

 
$
(487
)
 
$
1,508,408

 
 
 
 
 
 
 
 
 
 
See notes to condensed consolidated financial statements.



6



Piedmont Natural Gas Company, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)
 
1.
Summary of Significant Accounting Policies

Significant Accounting Policies

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

Unaudited Interim Financial Information

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

Seasonality and Use of Estimates

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

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

Rate-Regulated Basis of Accounting

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

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

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 classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we used a discounted cash flow technique to calculate our valuation. We incorporated the following inputs and assumptions in our model: contract volume, forward market prices from third party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. There were no other significant changes to these fair value methodologies during the three months ended January 31, 2016.

Recently Issued Accounting Standards Update (ASU)
Guidance
Description
Effective date
Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606)
Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of the first period of adoption.
Annual periods beginning after December 15, 2017 (beginning November 1, 2018 for us) and interim periods within that period, with early adoption permitted for annual periods beginning after December 15, 2016.
We are currently evaluating the effect on our financial position, results of operations and cash flows, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are following the development of guidance from our industry.

8


Guidance
Description
Effective date
Effect on the financial statements or other significant matters
ASU 2015-05, April 2015, Intangibles -Goodwill and Other - Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40)
The amendment provides customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software.
Annual periods (and interim periods therein) beginning after December 15, 2015 (November 1, 2016 for us), with early adoption permitted. Entities may adopt the guidance retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.
We are analyzing our cloud computing arrangements to identify any internal-use software and are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-01, January 2016, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
The amendment addresses aspects of recognition, measurement, presentation and disclosure of financial instruments. It affects investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment.
Annual periods (and interim periods within those periods) beginning after December 15, 2017 (November 1, 2018 for us).
We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2016-02, February 2016, Leases (Topic 842)
Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for existing capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.
Annual periods (and interim periods within those periods) beginning after December 15, 2018 (November 1, 2019 for us), with early adoption permitted.
We are currently evaluating the effect on our financial position, results of operations and cash flows.

Reclassifications and Changes in Presentation

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

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

9


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

2.
Proposed Acquisition by Duke Energy Corporation

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

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

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

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

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


10


3.
Regulatory Matters

Rate Regulated Basis of Accounting

Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are as follows.
In thousands
January 31,
2016
 
October 31,
2015
Regulatory Assets:
 
 
 
Current:
 
 
 
Unamortized debt expense on reacquired debt
$
238

 
$
238

Amounts due from customers
22,956

 

Environmental costs
1,522

 
1,513

Deferred operations and maintenance expenses
860

 
847

Deferred pipeline integrity expenses
3,470

 
3,470

Deferred pension and other retirement benefit costs
2,757

 
2,757

Robeson liquefied natural gas (LNG) development costs
382

 
381

Derivatives - gas supply contracts held for utility operations
28,300

 

Other
1,330

 
1,730

Total current
61,815

 
10,936

Noncurrent:
 
 
 
Unamortized debt expense on reacquired debt
4,607

 
4,666

Environmental costs
4,587

 
5,107

Deferred operations and maintenance expenses
3,777

 
3,997

Deferred pipeline integrity expenses
29,767

 
29,824

Deferred pension and other retirement benefit costs
18,887

 
17,861

Amounts not yet recognized as a component of pension and other retirement benefit costs
113,197

 
114,854

Regulatory cost of removal asset
19,363

 
19,087

Robeson LNG development costs
32

 
127

Derivatives - gas supply contracts held for utility operations
127,000

 

Other
1,093

 
1,203

Total noncurrent
322,310

 
196,726

Total
$
384,125

 
$
207,662

Regulatory Liabilities:
 
 
 
Current:
 
 
 
Amounts due to customers
$
5,680

 
$
13,367

Noncurrent:
 
 
 
Regulatory cost of removal obligations
526,299

 
521,478

Deferred income taxes
64,019

 
68,738

Amounts not yet recognized as a component of pension and other retirement benefit costs
82

 
85

Total noncurrent
590,400

 
590,301

Total
$
596,080


$
603,668


Rate Oversight and Rate and Regulatory Actions

North Carolina

In November 2015, we filed a petition with the NCUC seeking authority, under the approved integrity management riders (IMR) settlement agreement and procedural schedule, to change our rates effective December 1, 2015 to collect a total of $40.9 million in annual IMR margin revenues, representing an additional $13.4 million in annual IMR margin revenues from rate adjustments approved by the NCUC in its January 2015 order. The rate adjustment was based on $161.9 million of IMR-eligible capital investments in integrity and safety projects over the eleven-month period ended September 30, 2015. In December 2015, the NCUC approved the requested IMR rate increase. In February 2016, the NCUC Public Staff filed their

11


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

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

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

South Carolina

In June 2015, we filed with the Public Service Commission of South Carolina (PSCSC) a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study as permitted under the Natural Gas Rate Stabilization Act requesting a change in our rates from those approved by the PSCSC in its October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2015.

In January 2016, we and Duke Energy discussed the Acquisition of Piedmont by Duke Energy with the PSCSC pursuant to its procedures for an allowable ex-parte communication briefing in accordance with state statute. The PSCSC's approval of the Acquisition is not required.

Tennessee

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

In November 2015, we filed an annual report for the twelve months ended June 30, 2014 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order.

In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue, effective January 2016, based on $18.4 million of IMR-eligible capital investments in integrity and safety projects over the twelve-month period ended October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. In November 2015, we filed a settlement agreement with the Tennessee Consumer Advocate stipulating that we refund the $4.7 million to customers over a twelve-month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve-month period beginning January 2016. In February 2016, the TRA issued its written order on this matter.

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

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

4.
Earnings per Share

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


12


A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest and any FSAs settle, for the three months ended January 31, 2016 and 2015 is presented below.
 
Three Months
In thousands, except per share amounts
2016
 
2015
Net Income
$
97,790

 
$
92,978

 
 
 
 
Average shares of common stock outstanding for basic earnings per share
80,963

 
78,620

Contingently issuable shares under ICP awards
117

 
325

Contingently issuable restricted nonvested shares under accelerated ICP awards
182

 

Contingently issuable shares under FSAs
4

 

Average shares of dilutive stock
81,266

 
78,945

 
 
 
 
Earnings Per Share of Common Stock:
 
 
 
Basic
$
1.21

 
$
1.18

Diluted
$
1.20

 
$
1.18

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

5.
Long-Term Debt Instruments

The NCUC approved debt and equity issuances under an effective debt and equity shelf registration statement up to $1 billion through June 6, 2017. As of January 31, 2016, we have $544.1 million remaining for debt and equity issuances as approved by the NCUC. For further information on equity transactions, see Note 7 to the condensed consolidated financial statements in this Form 10-Q. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our commercial paper (CP) program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.

Our long-term debt as of January 31, 2016 and October 31, 2015 is presented below.
In thousands
January 31, 2016
 
October 31, 2015
Principal
$
1,575,000

 
$
1,575,000

Unamortized debt issuance expenses and discounts
(11,104
)
 
(11,323
)
Total
1,563,896

 
1,563,677

Less current maturities
40,000

 
40,000

Total long-term debt
$
1,523,896

 
$
1,523,677


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

6.
Short-Term Debt Instruments

On December 14, 2015, we amended and restated the agreement underlying our $850 million five-year revolving syndicated credit facility as an $850 million five-year revolving syndicated credit facility that expires on December 14, 2020 and has an option to request an expansion up to an additional $200 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million, of which $1.6 million was issued and outstanding as of January 31, 2016 and October 31, 2015. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London

13


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

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

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

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2016. A summary of the short-term debt activity under our CP program for the three months ended January 31, 2016 is as follows.
In millions
Three Months
Minimum amount outstanding during period
$
340

Maximum amount outstanding during period
$
500

Minimum interest rate during period
.20
%
Maximum interest rate during period
.75
%
Weighted average interest rate during period
.44
%

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

7.
Stockholders’ Equity

Capital Stock

Changes in common stock for the three months ended January 31, 2016 are as follows.
In thousands
Shares
 
Amount
Balance, October 31, 2015
80,883

 
$
721,419

Issued to participants in the Employee Stock Purchase Plan (ESPP)
6

 
342

Issued to participants in the Dividend Reinvestment and Stock Purchase Plan
77

 
4,260

Issued to participants in the ICP
106

 
6,056

Costs from issuance of common stock
 
 
(21
)
Balance, January 31, 2016
81,072


$
732,056


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

In addition to the issuance and sale of shares by us through the Agents, we may also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers will, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. We expect to enter into separate FSAs through July 31, 2016.

14



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

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

Under the terms of this FSA, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation under the agreement. We expect to settle by delivering shares. At our election, we intend to physically settle the shares under this agreement prior to the closing date of the Acquisition or October 31, 2016, whichever occurs first.
 
In accordance with accounting guidance, we have classified the FSA as an equity transaction because the FSA is indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts will be recorded in the consolidated financial statements until settlement of the FSA.

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

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

Cash dividends paid per share of common stock for the three months ended January 31, 2016 and 2015 are as follows. 
 
Three Months
 
2016
 
2015
Cash dividends paid per share of common stock
$
0.33

 
$
0.32


Other Comprehensive Income (Loss)

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


15


 
Changes in Accumulated OCIL(1)
 
Three Months
In thousands
2016
 
2015
Accumulated OCIL beginning balance, net of tax
$
(855
)
 
$
(237
)
Hedging activities of equity method investments:
 
 
 
 OCIL before reclassifications, net of tax
(138
)
 
(944
)
 Amounts reclassified from accumulated OCIL, net of tax
505

 
117

Total current period activity of hedging activities of equity method investments, net of tax
367


(827
)
Net current period benefit activities of equity method investments, net of tax
1

 

Accumulated OCIL ending balance, net of tax
$
(487
)

$
(1,064
)
(1) Amounts in parentheses indicate debits to accumulated OCIL.
 
 
 

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the three months ended January 31, 2016 and 2015.
 
Reclassification Out of Accumulated OCIL (1)
 
Affected Line Items on Condensed
Statements of Comprehensive Income
 
Three Months
 
In thousands
2016
 
2015
 
Hedging activities of equity method investments
$
832

 
$
192

 
Income from equity method investments
Income tax expense
(327
)
 
(75
)
 
Income taxes
Hedging activities of equity method investments
505


117

 
 
Net benefit activities of equity method investments
2

 

 
Income from equity method investments
Income tax expense
(1
)
 

 
Income taxes
Net benefit activities of equity method investments
1

 

 
 
Total reclassification for the period, net of tax
$
506

 
$
117

 
 
 
 
 
 
 
 
(1) Amounts in parentheses indicate debits to accumulated OCIL. 

8.
Marketable Securities

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

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


16


The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of January 31, 2016 and October 31, 2015 is as follows.
 
January 31, 2016
 
October 31, 2015
In thousands
Cost
 
Fair
Value
 
Cost
 
Fair
Value
Current trading securities:
 
 
 
 
 
 
 
Money markets
$
28

 
$
28

 
$
51

 
$
51

Mutual funds
77

 
109

 
114

 
185

Total current trading securities
105

 
137

 
165

 
236

Noncurrent trading securities:
 
 
 
 
 
 
 
Money markets
536

 
536

 
465

 
465

Mutual funds
4,233

 
4,306

 
3,625

 
4,201

Total noncurrent trading securities
4,769

 
4,842

 
4,090

 
4,666

Total trading securities
$
4,874


$
4,979


$
4,255


$
4,902


9.
Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans with the purchase of call option derivatives. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our gas purchase derivative instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of January 31, 2016 and October 31, 2015, we had long gas purchase options providing total coverage of 33.6 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held at January 31, 2016 are for the period from March 2016 through January 2017.

Derivative Assets and Liabilities - Gas Supply Contracts

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

Fair Value Measurements and Quantitative and Qualitative Disclosures

We use purchased call options as financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain deferred compensation plans. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these contracts that became effective in the period ended January 31, 2016 should be recorded at fair value. We classify fair value balances based on the observance of inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. For an updated discussion of our fair value methodology, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2016 and October 31, 2015. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their

17


consideration within the fair value hierarchy levels. We have had no transfers between any level during the three months ended January 31, 2016 and 2015. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no purchased call option derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our purchased call option derivatives held for utility operations. Our purchased call option derivatives held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivatives presented at fair value that are held for our utility operations.
Recurring Fair Value Measurements as of January 31, 2016
In thousands
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Effects of
Netting and
Cash Collateral
Receivables /
Payables
 
Total
Carrying
Value
Assets:
 
 
 
 
 
 
 
 
 
Derivatives - purchased call options held for utility operations
$
1,602

 
$

 
$

 
$

 
$
1,602

Debt and equity securities held as trading securities:
 
 
 
 
 
 
 
 
 
Money markets
564

 

 

 

 
564

Mutual funds
4,415

 

 

 

 
4,415

Total fair value assets
$
6,581

 
$

 
$

 
$

 
$
6,581

 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
Derivatives - gas supply contracts held for utility operations
$

 
$

 
$
155,300

 
$

 
$
155,300

Recurring Fair Value Measurements as of October 31, 2015
In thousands
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Effects of
Netting and
Cash Collateral
Receivables /
Payables
 
Total
Carrying
Value
Assets:
 
 
 
 
 
 
 
 
 
Derivatives - purchased call options held for utility operations
$
1,343

 
$

 
$

 
$

 
$
1,343

Debt and equity securities held as trading securities:
 
 
 
 
 
 
 
 
 
Money markets
516

 

 

 

 
516

Mutual funds
4,386

 

 

 

 
4,386

Total fair value assets
$
6,245

 
$

 
$

 
$

 
$
6,245


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

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

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy.
In thousands
 
 
Balance, October 31, 2015
 
$

Realized and unrealized gains (losses):
 
 
Recorded to regulatory assets
 
(155,300
)
Purchases, sales and settlements (net)
 

Transfer in/out of Level 3
 

Balance, January 31, 2016
 
$
(155,300
)

18



Our regulated utility segment purchased call option derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 3 to the condensed consolidated financial statements in this Form 10-Q. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

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

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

Our long-term debt is presented at net cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The principal and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.
In thousands
Principal
 
Fair Value
As of January 31, 2016
$
1,575,000

 
$
1,734,319

As of October 31, 2015
1,575,000

 
1,720,586


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

The following table presents the fair value and balance sheet classification of our financial options and gas supply contracts for natural gas as of January 31, 2016 and October 31, 2015.
Fair Value of Derivative Instruments
 
January 31,
 
October 31,
In thousands
2016
 
2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
 
 
 
Asset Financial Instruments:
 
 
 
Current Assets – Gas purchase derivative assets (March 2016 - January 2017)
$
1,602

 
 
Current Assets – Gas purchase derivative assets (December 2015 - October 2016)
 
 
$
1,343

Liability Financial Instruments:
 
 
 
Current Liabilities – Gas supply derivative liabilities
$
28,300

 
 
Noncurrent Liabilities – Gas supply derivative liabilities
127,000

 
 

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs are to use these financial instruments to reduce gas cost volatility for our customers. Accordingly, the

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operation of the hedging programs of the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 3 to the condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

The following table presents the impact that our gas purchase option financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.
 
Amount of Loss Recognized
on Derivative Instruments and Deferred Under PGA Procedures
 
Location of Loss
Recognized through
PGA Procedures
 
Three Months Ended 
 January 31
 
 
In thousands
2016
 
2015
 
 
Purchased call options
$
(1,901
)
 
$
(558
)
 
Cost of Gas

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

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

Credit and Counterparty Risk

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

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Condensed Consolidated Balance Sheets attributable to these entities amounted to $18.6 million, or approximately 11%, of our gross trade accounts receivable as of January 31, 2016. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

Risk Management

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

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


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10.
Commitments and Contingent Liabilities

Long-term Contracts

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

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Condensed Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Legal

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.6 million in letters of credit that were issued and outstanding as of January 31, 2016. Additional information concerning letters of credit is included in Note 6 to the condensed consolidated financial statements in this Form 10-Q.

Surety Bonds

In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of January 31, 2016, we had open surety bonds with a total contingent obligation of $6.6 million.

Environmental Matters

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

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

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

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

11.
Employee Benefit Plans

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

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

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended January 31, 2016 and 2015 are presented below.
 
Qualified Pension
 
Nonqualified
Pension
 
Other Benefits
In thousands
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Service cost
$
2,750

 
$
3,050

 
$

 
$

 
$
294

 
$
295

Interest cost
2,400

 
2,975

 
40

 
52

 
321

 
369

Expected return on plan assets
(6,000
)
 
(5,925
)
 

 

 
(442
)
 
(459
)
Amortization of prior service (credit) cost
(550
)
 
(550
)
 
52

 
58

 
(83
)
 

Amortization of actuarial loss
2,100

 
2,050

 
20

 
21

 
115

 
7

Total
$
700

 
$
1,600

 
$
112

 
$
131

 
$
205

 
$
212


In November 2015, we contributed $10 million to the qualified pension plan, and in January 2016, we contributed $1.8 million to the money purchase pension plan. During the three months ended January 31, 2016, we contributed $.1 million to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans in 2016.
In thousands
 
Nonqualified pension plans
$
389

OPEB plan
1,300


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

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


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12.
Employee Share-Based Plans

Liability Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the three months ended January 31, 2016 and 2015, we recorded compensation expense, and as of January 31, 2016 and October 31, 2015, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value each quarter and at the settlement date. The award with the performance period that ended October 31, 2015 was paid out to participants in December 2015. Two other awards with performance periods ending October 31, 2016 (2016 plan) and October 31, 2017 (2017 plan) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.

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

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

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2016 and 2015, and the amounts recorded as liabilities in “Other noncurrent liabilities” in “Noncurrent Liabilities” with the current portion recorded in “Other current liabilities” in “Current Liabilities” in the Condensed Consolidated Balance Sheets as of January 31, 2016 and October 31, 2015 are presented below.
 
Three Months
In thousands
2016
 
2015
Compensation expense
$
6,230

 
$
2,230

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

 
$
22,037


The Merger Agreement provides for the conversion of the shares subject to the RSUs and ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the 2016 RSU for our President and CEO (accelerated RSU) and the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at his and their elections to accelerate, in the form of restricted nonvested shares of our common stock, net of shares withheld for applicable taxes. The acceleration of the vesting and payment of these awards will mitigate the effects of Section 280G of the Internal Revenue Code of 1986, as amended, including increasing the deductibility of such payments for the Company. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, and the 2016 RSU, per the election of our President and CEO, occurred on December 15, 2015.

In connection with the election to accelerate the ICP awards and the 2016 RSU, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of

23


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

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

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

Equity Plan

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

13.
Equity Method Investments

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

Ownership Interests

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

24


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

Accumulated Other Comprehensive Income (Loss)

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

Related Party Transactions
We have related party transactions as a customer of our investments. For each period of the three months ended January 31, 2016 and 2015, these gas costs and the amounts we owed to our equity method investees, as of January 31, 2016 and October 31, 2015 are as follows.
Related Party
 
Type of Expense
 
Cost of Gas (1)
 
Trade accounts payable (2)
 
 
 
 
Three Months
 
January 31,
 
October 31,
In thousands
 
 
 
2016
 
2015
 
2016
 
2015
Cardinal
 
Transportation costs
 
$
2,203

 
$
2,214

 
$
740

 
$
744

Hardy Storage
 
Gas storage costs
 
2,322

 
2,322

 
774

 
774

Pine Needle
 
Gas storage costs
 
2,834

 
2,936

 
955

 
955

  Totals
 
 
 
$
7,359

 
$
7,472

 
$
2,469

 
$
2,473

(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.


25


We have related party transactions as we sell wholesale gas supplies to SouthStar. For each period of the three months ended January 31, 2016 and 2015, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2016 and October 31, 2015 are as follows.
 
 
Operating Revenues (1)
 
Trade accounts receivable (2)
 
 
Three Months
 
January 31,
 
October 31,
In thousands
 
2016
 
2015
 
2016
 
2015
Operating revenues
 
$
57

 
$
396

 
$
54

 
$
183

(1) In the Condensed Consolidated Statements of Comprehensive Income.
(2) In the Condensed Consolidated Balance Sheets.

Other Information

SouthStar

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

Constitution

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

We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $857 million, excluding AFUDC, in total. Our total anticipated contributions are approximately $205.8 million. As of January 31, 2016, our fiscal year contributions were $4.7 million, with our total equity contribution for the project totaling $77.3 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is the second half of 2017, reflecting a delay in the issuance of remaining outstanding permits. The capacity of the pipeline is 100% subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

ACP

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

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

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

In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015, and expects to receive the FERC certificate of public convenience and necessity in the summer of 2016 and begin construction thereafter.


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On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI has informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. This commitment is capped at $15.2 million. This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP.

On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company.

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

14.
Variable Interest Entities

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

Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity included in "Equity method investments in non-utility activities" in "Noncurrent Assets" in the Condensed Consolidated Balance Sheets. As of January 31, 2016 and October 31, 2015, our investment balances are as follows.
In thousands
January 31,
2016
 
October 31,
2015
Cardinal
$
14,928

 
$
15,083

Pine Needle
18,118

 
18,396

SouthStar
46,207

 
41,325

Hardy Storage
40,389

 
39,706

Constitution
88,968

 
82,403

ACP
14,667

 
10,043

  Total equity method investments in non-utility activities
$
223,277

 
$
206,956


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

15.     Business Segments

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

27


joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.

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

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

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

Operations by segment for the three months ended January 31, 2016 and 2015 are presented below.
 
Regulated Utility
 
Regulated
Non-Utility
Activities
 
Unregulated
Non-Utility
Activities
 
Total
In thousands
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Revenues from external customers
$
461,337

 
$
607,271

 
$

 
$

 
$

 
$

 
$
461,337

 
$
607,271

Margin
286,249

 
270,070

 

 

 

 

 
286,249

 
270,070

Operations and maintenance expenses
71,300

 
66,150

 
16

 
31

 
55

 
38

 
71,371

 
66,219

Income from equity method investments

 

 
4,692

 
3,771

 
4,510

 
4,494

 
9,202

 
8,265

Operating income (loss) before income taxes
171,341

 
162,030

 
(16
)
 
(31
)
 
(139
)
 
(121
)
 
171,186

 
161,878

Income before income taxes
154,030

 
144,401

 
4,676

 
3,740

 
4,371

 
4,373

 
163,077

 
152,514


Reconciliations to the condensed consolidated statements of comprehensive income for the three months ended January 31, 2016 and 2015 are presented below.
 
Three Months
In thousands
2016
 
2015
Operating Income:
 
 
 
Segment operating income before income taxes
$
171,186

 
$
161,878

Utility income taxes
(61,909
)
 
(56,272
)
Regulated non-utility activities operating loss before income taxes
16

 
31

Unregulated non-utility activities operating loss before income taxes
139

 
121

Operating income
$
109,432


$
105,758

 
Net Income:
 
 
 
Income before income taxes for reportable segments
$
163,077

 
$
152,514

Income taxes
(65,287
)
 
(59,536
)
Total
$
97,790

 
$
92,978



28


16.
Subsequent Events

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

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

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

Forward-Looking Statements

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

Economic conditions in our markets.
Wholesale price of natural gas.
Availability of adequate interstate pipeline transportation capacity and natural gas supply.
Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis.
Competition from other companies that supply energy.
Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated.
Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us.
Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities.
Weather conditions.
Operational interruptions to our gas distribution and transmission activities.
Inability to complete necessary or desirable pipeline expansion or infrastructure development projects.
Elevated levels of capital expenditures.
Changes to our credit ratings.
Availability and cost of capital.
Federal and state fiscal, tax and monetary policies.
Ability to generate sufficient cash flows to meet all our cash needs.
Ability to satisfy all of our outstanding debt obligations.
Ability of counterparties to meet their obligations to us.
Costs of providing pension benefits.
Earnings from the joint venture businesses in which we invest.
Ability to attract and retain professional and technical employees.
Cybersecurity breaches or failure of technology systems.
Ability to obtain and maintain sufficient insurance.
Change in number of outstanding shares.
Certain risks and uncertainties associated with the Acquisition, including, without limitation:
the possibility that the Acquisition does not close due to the failure to satisfy the closing conditions, including, but not limited to, a failure to obtain the required regulatory approvals;

29


delays caused by the required regulatory approvals, which may delay the Acquisition or cause the companies to abandon the transaction;
uncertainties and disruptions caused by the Acquisition that make it more difficult to maintain our business and operational relationships as well as maintain our relationships with employees, suppliers or customers, and the risk that unexpected costs will be incurred during this process;
the diversion of management time on Acquisition-related issues, and;
future shareholder suits could delay or prevent the closing of the Acquisition or otherwise
adversely impact our business and operations.

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

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

Overview

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

We operate with three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities. Factors critical to the success of the regulated utility segment include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The regulated non-utility activities segment consists of our equity method investments in joint venture regulated energy-related pipeline and storage businesses that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in SouthStar Energy Services LLC (SouthStar) that is held by a wholly-owned subsidiary. For further information on equity method investments and business segments, see Note 13 and Note 15, respectively, to the condensed consolidated financial statements in this Form 10-Q. The percentages of the assets as of January 31, 2016 and earnings before taxes by segments for the three months ended January 31, 2016 are presented below.
 
Assets
 
Earnings
Before Taxes
Regulated Utility
96
%
 
94
%
Non-utility Activities:
 
 
 
Regulated non-utility activities
3
%
 
3
%
Unregulated non-utility activities
1
%
 
3
%
Total non-utility activities
4
%
 
6
%

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

30


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

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

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

In all three states, the gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the margin decoupling mechanism or the WNA mechanism. Through the use of various tariff mechanisms and fixed-rate contracts, we are able to achieve a higher degree of margin stabilization. For further information on state commission regulation, see Note 3 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015. The following table presents the breakdown of our gas utility margin for the three months ended January 31, 2016 and 2015.
 
2016
 
2015
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers,
 
 
 
  Tennessee and North Carolina IMRs and fixed-rate contracts)
74
%
 
73
%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)
19
%
 
20
%
Volumetric or periodic renegotiation (including secondary marketing activity)
7
%
 
7
%
Total
100
%
 
100
%

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

Promote the benefits of natural gas,
Expand our core natural gas and complementary energy-related businesses to enhance shareholder value,
Be the energy service provider of choice,
Achieve excellence in customer service every time,
Preserve financial strength and flexibility,
Execute sustainable business practices, and

31


Enhance our healthy high performance culture.

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

Executive Summary

Financial Performance – Quarter Ended 2016 Compared with Quarter Ended 2015
The following tables provide a comparison of the components of comprehensive income and statistical information for the three months ended January 31, 2016 as compared with the three months ended January 31, 2015.
Comprehensive Income Statement Components

 
Three Months Ended January 31
In thousands, except per share amounts
2016
 
2015
 
Variance
 
Percent Change
Operating Revenues
$
461,337

 
$
607,271

 
$
(145,934
)
 
(24.0
)%
Cost of Gas
175,088

 
337,201

 
(162,113
)
 
(48.1
)%
Margin
286,249

 
270,070

 
16,179

 
6.0
 %
Operations and Maintenance
71,300

 
66,150

 
5,150

 
7.8
 %
Depreciation
33,686

 
31,893

 
1,793

 
5.6
 %
General Taxes
9,922

 
9,997

 
(75
)
 
(0.8
)%
Utility Income Taxes
61,909

 
56,272

 
5,637

 
10.0
 %
Total Operating Expenses
176,817

 
164,312

 
12,505

 
7.6
 %
Operating Income
109,432

 
105,758

 
3,674

 
3.5
 %
Other Income (Expense), net of tax
5,426

 
4,931

 
495

 
10.0
 %
Utility Interest Charges
17,068

 
17,711

 
(643
)
 
(3.6
)%
Net Income
$
97,790

 
$
92,978

 
$
4,812

 
5.2
 %
Average Shares of Common Stock:
 
 
 
 


 


Basic
80,963

 
78,620

 
2,343

 
3.0
 %
Diluted
81,266

 
78,945

 
2,321

 
2.9
 %
Earnings Per Share of Common Stock:
 
 
 
 


 


Basic
$
1.21

 
$
1.18

 
$
0.03

 
2.5
 %
Diluted
$
1.20

 
$
1.18

 
$
0.02

 
1.7
 %
 
Margin by Customer Class
 
Three Months Ended January 31
In thousands
2016
 
2015
Sales and Transportation:
 
 
 
 
 
 
 
Residential
$
167,960

 
59
%
 
$
158,484

 
59
%
Commercial
73,101

 
25
%
 
68,874

 
25
%
Industrial
14,409

 
5
%
 
13,177

 
5
%
Power Generation
19,270

 
7
%
 
19,245

 
7
%
For Resale
3,187

 
1
%
 
2,642

 
1
%
Total
277,927

 
97
%
 
262,422

 
97
%
Secondary Market Sales
6,425

 
2
%
 
5,553

 
2
%
Miscellaneous
1,897

 
1
%
 
2,095

 
1
%
Total
$
286,249

 
100
%
 
$
270,070

 
100
%

32


Gas Deliveries, Customers, Weather Statistics and Number of Employees

 
Three Months Ended January 31
  
2016
 
2015
 
Variance
 
Percent Change
Deliveries in Dekatherms (in thousands):
 
 
 
 
 
 
 
Residential
24,252

 
31,473

 
(7,221
)
 
(22.9
)%
Commercial
15,229

 
18,389

 
(3,160
)
 
(17.2
)%
Industrial
26,966

 
27,264

 
(298
)
 
(1.1
)%
Power Generation
69,255

 
60,711

 
8,544

 
14.1
 %
For Resale
2,290

 
2,950

 
(660
)
 
(22.4
)%
Throughput
137,992

 
140,787

 
(2,795
)
 
(2.0
)%
Secondary Market Volumes
16,530

 
11,169

 
5,361

 
48.0
 %
Customers Billed (at period end)
1,038,369

 
1,023,245

 
15,124

 
1.5
 %
Gross Residential, Commercial and Industrial Customer Additions
4,672

 
4,892

 
(220
)
 
(4.5
)%
Degree Days
 
 
 
 
 
 
 
Actual
1,455

 
1,945

 
(490
)
 
(25.2
)%
Normal
1,840

 
1,838

 
2

 
0.1
 %
Percent (warmer) colder than normal
(20.9
)%
 
5.8
%
 
n/a

 
n/a

Number of Employees (at period end)
1,926

 
1,902

 
24

 
1.3
 %

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

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

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


33


Customer Growth – We continued to have solid customer growth in the first quarter. Affordable and stable wholesale natural gas costs continue to favorably position natural gas relative to other energy sources. Continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas should help us to sustain growth comparable to prior years. Extremely wet weather conditions delayed construction projects in residential and commercial markets, affecting growth in these markets during the current period as compared to the same prior period as presented below.
 
2016
 
2015
 
Percent
Change
Residential new home construction
3,306

 
3,302

 
0.1
 %
Residential conversion
792

 
1,008

 
(21.4
)%
Commercial
572

 
580

 
(1.4
)%
Industrial
2

 
2

 
 %
Total new customers
4,672

 
4,892

 
(4.5
)%

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

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

With significant capital costs incurred under our ongoing system integrity programs, we have IMR regulatory mechanisms in North Carolina and Tennessee to separately track and recover certain costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity programs, as well as additional state safety and integrity requirements in Tennessee. The IMR orders by jurisdiction and the amount reflected in "Operating Revenues" in the Condensed Consolidated Statements of Comprehensive Income is summarized below:
In millions
North Carolina
 
 
Tennessee
Incremental annual margin revenue - 2014 IMR
$
1.0

(1) 
 
$
13.1

Incremental annual margin revenue - 2015 IMR
24.4

(1) 
 
6.5

Incremental annual margin revenue - 2016 IMR
15.5

 
 
1.7

Total cumulative incremental annual margin revenue (2)
$
40.9

(1 
) 
 
$
21.3

 
 
 
 
 
Amount recorded during first fiscal quarter in 2016
$
12.5

 
 
$
8.1

 
 
 
 
 
(1) Amounts reflect incremental annual IMR margin revenue, as adjusted per audit by the NCUC Public Staff under the approved IMR settlement agreement and procedural schedule, which may differ from the amounts reflected in the filed and approved rate adjustments. For further information on the current rate adjustment, see Note 3 to the condensed consolidated financial statements in this Form 10-Q. For further information on the IMR settlement agreement, see Note 3 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2015.
(2) IMR recovery periods in both jurisdictions do not align with our fiscal year. For further information on these periods, see Note 3 to the condensed consolidated financial statements in this Form 10-Q.

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

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

34


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

Proposed Acquisition by Duke Energy – In October 2015, we entered into a Merger Agreement with Duke Energy. At the effective time of the Acquisition, subject to receipt of required shareholder and regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. For further information on the Acquisition, see "Forward Looking Statements" in Item 2 and Note 2, Note 3 and Note 13 to the condensed consolidated financial statements in this Form 10-Q. In the Merger Agreement, we agreed to covenants affecting the conduct of our business between the date of the Merger Agreement and the effective date of the Acquisition.

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

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

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

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

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

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


35


Operating Revenues

Changes in operating revenues for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.
Changes in Operating Revenues - Increase (Decrease)

In millions
Three Months
Residential and commercial customers
$
(178.7
)
Industrial customers
(4.8
)
Secondary market
(18.4
)
Margin decoupling mechanism
31.3

WNA mechanisms
10.9

IMR mechanisms
14.0

Other revenue
(0.2
)
Total
$
(145.9
)
 

Residential and commercial customers – the decrease is due to lower consumption from warmer weather and lower wholesale gas costs passed through to customers, slightly offset by customer growth.
Industrial customers – the decrease is primarily due to lower wholesale gas costs passed through to customers and lower volumes from warmer weather.
Secondary market – the decrease is due to lower margin sales prices, slightly offset by increased volumes. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements that are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.
Margin decoupling mechanism – the increase is primarily related to warmer weather in North Carolina as compared to the prior period. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to weather and conservation.
WNA mechanisms – the increase is primarily related to warmer weather in South Carolina and Tennessee as compared to the prior period. As discussed in “Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.
IMR mechanisms – the increase is due to the IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015 and December 2015.

Cost of Gas

Changes in cost of gas for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.
Changes in Cost of Gas - Increase (Decrease)

In millions
Three Months
Commodity gas costs passed through to sales customers
$
(94.2
)
Commodity gas costs in secondary market transactions
(19.3
)
Pipeline demand charges
(1.3
)
Regulatory-approved gas cost mechanisms
(47.3
)
Total
$
(162.1
)
 
Commodity gas costs passed through to sales customers – the decrease is primarily due to lower consumption from warmer weather and lower wholesale gas costs passed through to sales customers, slightly offset by customer growth.
Commodity gas costs in secondary market transactions – the decrease is primarily due to lower average wholesale gas costs, slightly offset by increased volumes.
Pipeline demand charges – the decrease is primarily due to increased capacity release revenues and asset manager payments, slightly offset by increased demand costs.

36


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

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

Margin

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

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

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


37


Changes in margin for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.
Changes in Margin - Increase (Decrease)

In millions
Three Months
Residential and commercial customers
$
13.7

Industrial customers
1.8

Secondary market activity
0.9

Net gas cost adjustments
(0.2
)
Total
$
16.2

 

Residential and commercial customers – the increase is primarily due to IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015 and December 2015, and customer growth in all three states, partially offset by decreased volumes delivered in South Carolina and Tennessee due to warmer weather.
Industrial customers – the increase is primarily due to IMR rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015 and December 2015, as well as increased margin recognized from special contracts.
Secondary market activity – the increase is primarily due to increased volumes, partially offset by lower margin sales.

Operations and Maintenance Expenses

Changes in O&M expenses for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.
Changes in Operations and Maintenance Expenses - Increase (Decrease)
 
In millions
Three Months
Payroll
$
5.3

Acquisition-related integration expenses
1.5

Other
(1.6
)
Total
$
5.2

 

Payroll – the increase is primarily due to higher equity incentive plan accruals, including $4.3 million incremental expense from the accelerated vesting and payment of incentive awards under provisions in the Merger Agreement, additional employees and merit increases.
Acquisition-related integration expenses – the increase is due to integration costs paid to outside parties in 2016.

Depreciation

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

Other Income (Expense)

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


38


Utility Interest Charges

Changes in utility interest charges for the three months ended January 31, 2016 compared with the same period in 2015 are presented below.
Changes in Utility Interest Charges - Increase (Decrease)

In millions
Three Months
Interest expense on long-term debt
$
1.4

Regulatory interest expense, net
(1.8
)
Other
(0.2
)
Total
$
(0.6
)

Interest expense on long-term debt – the increase is primarily due to higher amounts of long-term debt outstanding in the current period.
Regulatory interest expense, net – the change is primarily due to interest income on net amounts due from customers compared with interest expense in the prior year on net amounts due to customers.

Financial Condition and Liquidity

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

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

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

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

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

39


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

Short-Term Debt

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

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

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2016. Highlights for our short-term debt under our CP program as of January 31, 2016 and for the quarter ended January 31, 2016 are presented below. 
In thousands
 
End of period (January 31, 2016):
 
Amount outstanding
$
495,000

Weighted average interest rate
.57
%
 
 
During the period (November 1, 2015 – January 31, 2016):
 
Average amount outstanding
$
420,652

Minimum amount outstanding
340,000

Maximum amount outstanding
500,000

Minimum interest rate
.20
%
Maximum interest rate
.75
%
Weighted average interest rate
.44
%
 
 
Maximum amount outstanding:
 
November 2015
$
390,000

December 2015
480,000

January 2016
500,000


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

Cash Flows from Operating Activities

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

40



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

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

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

Trade accounts receivable and unbilled utility revenues increased $158.6 million from October 31, 2015 primarily due to amounts billed to customers during the winter period and the seasonal increase in unbilled volumes.
Net amounts due from customers increased $30.6 million in the current period primarily due to an increase in margin decoupling revenues, partially offset by excess deferred income taxes to be refunded to Tennessee customers.
Gas in storage decreased $7.1 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for injections and lower volumes of gas in storage.
Prepaid gas costs decreased $21.6 million in the current period primarily due to gas being made available for sale during the period. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.
Trade accounts payable increased $21.1 million in the current period primarily due to the purchase of natural gas for sale to our customers during the winter period, partially offset by the timing of payments for utility capital expenditures.

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

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


41


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

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

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

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

Cash Flows from Investing Activities

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

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

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

42


 
In millions
2016
 
2017
 
2018
Customer growth and other
$
300

 
$
315

 
$
385

System integrity
270

 
275

 
205

Total forecasted utility capital expenditures
570

 
590

 
590

Forecasted funding of construction in equity method investments
50

 
170

 
80

Total
$
620

 
$
760

 
$
670


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

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

We are invested as equity members in two interstate natural gas pipeline projects that are in the development stage. As a member of each of these limited liability companies, we are committed to fund construction in proportion to our ownership interests. For further information on these equity investments, see Note 13 to the condensed consolidated financial statements in this Form 10-Q. Details of the project costs for these investments are presented below.
 
Constitution
 
ACP
In millions
(24% ownership interest)
 
(10% ownership interest)
Our anticipated contributions for total project costs
$
205.8

 
$
450 – 500

Anticipated in-service date
second half of 2017

 
 
late 2018

Our contributions:
 
 
 
 
  For the three months ended January 31, 2016
$
4.7

 
 
$
4.4

  Over life of project to date
$
77.3

 
 
$
15.1


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

Cash Flows from Financing Activities

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

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

43


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

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

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

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

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

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

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

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

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

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

44


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

Our targeted capitalization ratio is 50 – 60% in total debt and 40 – 50% in common equity. The components of our total debt outstanding (short-term debt and long-term debt, excluding unamortized discount and debt issuance costs) to our total capitalization as of January 31, 2016 and 2015, and October 31, 2015, are summarized in the table below. 
 
January 31
 
October 31
 
January 31
In thousands
2016
 
Percentage
 
2015
 
Percentage
 
2015
 
Percentage
Short-term debt
$
495,000

 
14
%
 
$
340,000

 
10
%
 
$
480,000

 
15
%
Current portion of long-term debt
40,000

 
1
%
 
40,000

 
1
%
 

 
%
Long-term debt, principal
1,535,000

 
43
%
 
1,535,000

 
46
%
 
1,425,000

 
43
%
Total debt
2,070,000

 
58
%
 
1,915,000

 
57
%
 
1,905,000

 
58
%
Common stockholders’ equity
1,508,408

 
42
%
 
1,426,312

 
43
%
 
1,384,475

 
42
%
Total capitalization (including short-term debt)
$
3,578,408

 
100
%
 
$
3,341,312

 
100
%
 
$
3,289,475

 
100
%

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

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

As of January 31, 2016, all of our long-term debt was unsecured. Our long-term debt is rated by two rating agencies, Standard & Poor’s Ratings Services (S&P) and Moody’s Investors Service (Moody’s). Our current debt ratings are all considered investment grade and are as follows.
 
 
S&P
 
Moody's
Unsecured long-term debt
 
A
 
A2
Commercial paper
 
A1
 
P1

Subsequent to the announcement of the Acquisition, S&P affirmed our A rating for our senior unsecured long-term debt but placed it on credit watch with negative implications. Currently, Moody's has maintained its stable outlook for our long-term
debt. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, a change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

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

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


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Estimated Future Contractual Obligations

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

Off-balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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

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

As discussed in our Form 10-K for the year ended October 31, 2015 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We decided to replace the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. We made this change to improve the correlation between projected benefit cash flows and the corresponding yield curve spot rates and to provide a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.
 
Effective in our first quarter 2016, we have long-dated, fixed quantity natural gas supply contracts which are accounted for as derivatives. Our accounting of derivatives and the related fair value of the derivatives is a critical accounting estimate. We enter into both physical and financial contracts for the purchase and sale of natural gas. Fixed quantity gas supply contracts, as well as financial contracts that we purchase to hedge commodity price risks under our hedging programs established under state regulatory authority, are derivative instruments subject to fair value accounting and are recorded on the balance sheet at fair value. We record the changes in the fair value of these derivative instruments recoverable from or refundable to customers as regulatory assets or liabilities. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” as presented in Note 3 to the condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates. For the gas supply derivatives, we record the change in fair value as current and noncurrent regulatory assets or liabilities, the detail of which is presented in Note 3 to the condensed consolidated financial statements in this Form 10-Q, with corresponding current and noncurrent supply derivative liabilities recognized in the Condensed Consolidated Balance Sheets.

46



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

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

Accounting Guidance

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

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

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

Item 4. Controls and Procedures

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

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

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Part II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
c)
Issuer Purchases of Equity Securities.

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

Average Price
Paid Per Share

Total Number of Shares Purchased as Part of Publicly Announced Program

Maximum Number of Shares that May Yet be Purchased Under the Program (1)
Beginning of the period
 
 
 
 
 
 
 
2,910,074

11/1/15 – 11/30/15
 

 
$

 

 
2,910,074

12/1/15 – 12/31/15
 

 
$

 

 
2,910,074

1/1/16 – 1/31/16
 

 
$

 

 
2,910,074

Total
 

 
$

 

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

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

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


48



Item 6. Exhibits
 
10.1
Second Amended and Restated Credit Agreement, dated as of December 14, 2015, among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Bank of America, N.A, Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated December 16, 2015)
Compensatory Contracts:
10.2
Form of Share Repayment Agreement (LTIPs) between Piedmont Natural Gas Company, Inc. dated December 15, 2015 (substantially identical agreements have been executed with Thomas E. Skains, Karl W. Newlin, Franklin H. Yoho, Kevin M. O’Hara and Jane Lewis-Raymond) (incorporated by reference to Exhibit 10.2, Form 8-K dated December 16, 2015)
10.3
Form of Share Repayment Agreement (RSUs) between Piedmont Natural Gas Company, Inc. and Thomas E. Skains dated December 15, 2015 (incorporated by reference to Exhibit 10.3, Form 8-K dated December 16, 2015)
10.4
Form of Performance Unit Award Agreement
 
 
31.1
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
 
 
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema
101.CAL
XBRL Taxonomy Calculation Linkbase
101.DEF
XBRL Taxonomy Definition Linkbase
101.LAB
XBRL Taxonomy Extension Label Linkbase
101.PRE
XBRL Taxonomy Extension Presentation Linkbase

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


49


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
Piedmont Natural Gas Company, Inc.
 
 
 
 
(Registrant)
 
Date March 9, 2016
 
 
 
/s/ Karl W. Newlin
 
 
 
 
Karl W. Newlin
 
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
 
(Principal Financial Officer)
 
Date March 9, 2016
 
 
 
/s/ Jose M. Simon
 
 
 
 
Jose M. Simon
 
 
 
 
Vice President and Controller
 
 
 
 
(Principal Accounting Officer)


50


Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended January 31, 2016

Exhibits
 
Compensatory Contract:
10.4

 
Form of Performance Unit Award Agreement
 
 
 
31.1

  
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
 
 
31.2

  
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
 
 
32.1

  
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
 
 
32.2

  
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer


51