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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