UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended October 31, 2012

2015

or

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

For the transition period fromto

Commission file number1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

North Carolina

  

56-0556998

(State or other jurisdiction of incorporation or organization)  (I.R.S. Employer 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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of each class

  

Name of each exchange on which registered

Common Stock, no par value  New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yesxý No¨

Indicate by check mark if the registrant is not required to file reports pursuant to sectionSection 13 or 15 (d) of the Act. Yes¨ Noxý

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. Yesxý No¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website,Web site, if any, every Interactive Data fileFile 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). Yesxý No¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.¨ý

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 filerxý
  
    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 Act). Yes¨ Noxý

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2012.

2015.

Common Stock, no par value - $2,166,959,354

$2,923,039,979

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

Class

  

Outstanding at December 14, 2012

11, 2015
Common Stock, no par value  72,276,27280,985,282

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the 2016 Proxy Statement for the Annual Meeting of Shareholders on March 6, 2013 are incorporated by reference into Part III.



Piedmont Natural Gas Company, Inc.

2012 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS



Page
Part I.
  Item 1.Piedmont Natural Gas Company, Inc.
 

Business

2015 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
  1 
 Item 1A. 

Risk Factors

Page
Part I. 8 
 Item 1B.

Unresolved Staff Comments

  
Item 1.Business
1
Item 1A.Risk Factors
9
Item 1B.Unresolved Staff Comments
16
Item 2.Properties
17
Item 3.Legal Proceedings
17
Item 4.Mine Safety Disclosures
17
Part II. 
 Item 2.

Properties

  16
  Item 3.

Legal Proceedings

17
  Item 4.

Mine Safety Disclosures

17
Part II.
Item 5.
Market for Registrant’s Common Equity, Related
Stockholder
  Matters and Issuer Purchases of Equity Securities
18
Item 6.Selected Financial Data20
21
Item 7.
Management’s Discussion and Analysis of Financial
Condition and Results
  of Operations
21
Item 7A.Quantitative and Qualitative Disclosures about Market Risk55
47
Item 8.Financial Statements and Supplementary Data58
48
Item 9.Changes in and Disagreements With Accountants on
 Accounting and Financial Disclosure
113
Item 9A.Controls and Procedures
113
Item 9B.Other Information
116
  
129Part III. 
 Item 9A.Controls and Procedures  130
  Item 9B.Other Information133
Part III.
Item 10.Directors, Executive Officers and Corporate Governance133
116
Item 11.Executive Compensation133
116
Item 12.Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters		133
116
Item 13.Certain Relationships and Related Transactions, and Director
Independence		134
116
Item 14.Principal Accounting Fees and Services
116
  
134Part IV. 
Part IV. 
Item 15.Exhibits, Financial Statement Schedules
117
  135
 Signatures144
123




PART I


Item 1. Business


Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina.

Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.


Piedmont 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 51,600 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation.

transportation businesses.


In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service from resource centers in Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.


We have twothree reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility 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 regulated energy-related joint ventures that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in an unregulated energy-related joint venture energy-related businesses that are involved in unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation.is held by a wholly-owned subsidiary. The percentagepercentages of assets as of October 31, 20122015 and earnings before taxes by segment for the year ended October 31, 20122015 are presented below.

   Assets   

Earnings

Before Taxes

 

Regulated Utility

   97%       88%  
  

 

 

     

 

 

 

Non-utility Activities:

      

Regulated non-utility activities

   2%       5%  

Unregulated non-utility activities

   1%       7%  
  

 

 

   

 

  

 

 

 

Total non-utility activities

   3%       12%  
  

 

 

     

 

 

 

    Earnings
  Assets Before Taxes
Regulated Utility 96% 85%
Non-utility Activities:    
Regulated non-utility activities 3% 7%
Unregulated non-utility activities 1% 8%
Total non-utility activities 4% 15%

Operations of bothour segments are conducted within the United States of America. For further information on equity method investments and business segments, see Note 1213 and Note 14,15, respectively, to the consolidated financial statements.

statements in this Form 10-K.


Operating revenues shown in the Consolidated Statements of Comprehensive Income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in prudently incurred purchased gas costs from suppliers are passed through to customers through purchased gas adjustment (PGA) procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. For the year ended October 31, 2012, 48% of our operating revenues were from residential customers, 27% from commercial customers, 12% from large volume customers, including industrial, power generation and resale customers, 12% from secondary market activities and 1% from other sources. Secondary market transactions consist of off-system sales and capacity release arrangements and asset management arrangements and are part of our utilityregulatory gas supply management program with regulator-approved sharing mechanisms between our utility customers and our shareholders. OperationsEarnings or losses from equity method investments of the regulated and unregulated non-utility activities segmentsegments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive IncomeIncome. All other revenues and expenses of the regulated and unregulated non-utility activities segments are included in “Non-operating income” in “Other Income (Expense)” in “Income from equity method investments”the Consolidated Statements of Comprehensive Income.

1


Operating revenues by major customer class for the years ended October 31, 2015 and “Non-operating income.”

2014 are presented below.

  2015 2014
Residential customers 48% 46%
Commercial customers 27% 27%
Large volume customers, including industrial, power generation and resale customers 15% 14%
Secondary market activities 10% 12%
Other sources —% 1%
Total 100% 100%

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.


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, and the prices paid for, and the terms and conditions of service for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation (DOT) 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 (EPA) relating to the environment.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 whichthat are generally applicable to companies doing business in the United States of America.


We hold non-exclusive franchises for natural gas service in many of the communities we serve, with expiration dates from December 2012November 2015 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. From time to time, some of our franchise agreements expire; however, we continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. Depending on the jurisdiction, we believe that these franchises will be renewed or that service will be continued in the ordinary course of business while we negotiate renewals or continue to operate under our state-granted franchise rights without thea specific franchise agreementsagreement with each city or municipality. The likelihood of cessation of service under an expired franchise is remote, and we do not believe there will be a material adverse impact on us.


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

2


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. Weather in 2015, on average over our three-state market area, was 6% colder than normal and 3% warmer than 2014. For the year ended October 31, 2015, the margin decoupling mechanism in North Carolina decreased margin by $27 million, and the WNA mechanisms in South Carolina and Tennessee together decreased margin by $6.8 million.

With approval in North Carolina and Tennessee in December 2013, we have IMRs that separately track and recover, outside of general rate cases, certain costs associated with capital expenditures to comply with pipeline safety and integrity requirements. The first Tennessee IMR rate adjustment was recognized in earnings through customer billings beginning in January 2014, and the first North Carolina IMR rate adjustment was recognized in earnings through customer billings beginning in February 2014.

In all three states, the gas cost portion of our costs is recoverable through 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 this Form 10-K. The following table presents the breakdown of our gas utility margin for the years ended October 31, 2015, 2014 and 2013.
  2015 2014 2013
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers,      
  Tennessee and North Carolina IMRs in 2015 and 2014 only and fixed-rate contracts) 75% 72% 73%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee) 14% 16% 16%
Volumetric or periodic renegotiation (including secondary marketing activity) 11% 12% 11%
Total 100% 100% 100%

The natural gas distribution business is seasonal in nature as variations in weather conditions and our regulated utility rate designs generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. As

Our Strategies

We monitor our progress and measure our performance related to our strategic directives and business objectives over the course of each fiscal year. The metrics we use to measure our performance include, but are not limited to, earnings per share (EPS) and EPS growth, total shareholder return compared to our industry peer group, return on invested capital, return on equity, utility margin, investment grade credit ratings, customer growth, utility customer satisfaction and loyalty, operations and maintenance (O&M) expense discipline, employee health and safety, pipeline safety and sustainable business practices.

Safety is prevalenta critical component to our ongoing success as a company, and we have always placed the highest priority on the safety of our system, public safety and employee safety. We must comply with laws that regulate system integrity as well as new rulemaking proceedings under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing transmission and distribution pipeline integrity programs to inspect our system for anomalies, corrosion and leaks as well as monitoring key metrics of our system for its safe operation. We anticipate federal legislative and regulatory enactments will increase in scope and add further requirements and costs to our pipeline safety and integrity programs and our capital and O&M expenditure programs. Items that federal regulators continue to discuss include possible mandates addressing the integrity verification process of maximum allowable operating pressure of transmission pipelines. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third-party excavation damage, which is the greatest cause of damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

We believe natural gas is a safe and reliable energy source that is clean, affordable, reliable and environmentally responsible, as well as being domestically abundant. We incorporate this message into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We promote the increased awareness and use of natural gas and want our customers to choose us because of the value of natural gas and the quality of our service to them.


3


Our business model supports new clean energy technologies and energy efficiencies in the industry, we injectend use of natural gas into

storage duringgas. We seek opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2012, the amountdirect use of natural gas in storage varied from 17more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security.


We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We have converted 31% of our 1,100 vehicle fleet to CNG. As of October 31, 2015, we have approximately $19.4 million dekatherms (one dekatherm equals 1,000,000 BTUs)of utility plant in our three-state territory related to 26.2 million dekatherms,our CNG fueling stations that is included in the Consolidated Balance Sheets in “Utility plant in service.” We have been allowed by the NCUC, PSCSC and TRA to include this utility plant in service in our utility rate base and have the opportunity to earn an allowed rate of return in the jurisdictions. In an order issued in October 2015, the TRA stated that we may seek recovery of our recent investments in CNG equipment in that state in utility rate base in our next general rate proceeding.

We continued to execute our plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third-party fleets and other customers when there is sufficient demand to allow us to earn an adequate rate of return. We currently operate ten CNG fueling stations in our three-state service territory. We are also actively pursuing building customer-owned CNG fueling stations at commercial customers’ sites for use by their commercial fleets. There are currently fifteen customer-owned stations in our service territory.

Natural gas power plants continue to be a popular alternative to coal-fired electric generation plants because they emit significantly less carbon emissions than the coal power plants they replace and can cost less to operate. In recent years, we have completed pipeline expansion projects to provide long-term natural gas delivery service to new natural gas-fired power generation facilities in our market area. We currently provide service to 25 power generation customer accounts. In addition to delivering the natural gas supply to the new natural gas-fired power plants, the construction of natural gas pipelines for two of these projects increased our natural gas infrastructure in the eastern part of North Carolina with enhancement of future opportunities for economic growth and development.

Our capital program primarily supports our system infrastructure and the aggregate commodity costgrowth in our customer base. We are investing in our pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. For further information on our forecasted capital investments for fiscal 2016 – 2018, see “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and enhancing long-term shareholder value. We support our employees with improved processes and technology to better serve our customers while continuing to build a healthy, high performance culture in order to recruit, retain and motivate our workforce.

Our financial strength and flexibility is critical to our success as a company. We will continue our efforts to maintain our financial strength, including a strong balance sheet, investment-grade credit ratings and continued access to capital markets. We evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. Our capital plan includes maintaining a capitalization ratio of 50 – 60% in total debt and 40 – 50% in common equity. We will continue our efforts to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and innovative rate designs for the benefit of our customers and shareholders.

We continue to pursue strategic opportunities aligned with our core natural gas or complementary energy related businesses. It is our long-term strategic intent for our joint venture portfolio to be primarily weighted towards regulated and asset-based investments in storage variednatural gas infrastructure. We analyze and evaluate potential projects based on projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, specifically annual approved budgets, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.

Regarding our complementary energy-related businesses, we are a 24% equity member of Constitution Pipeline Company, LLC, whose purpose is to construct and operate 124 miles of interstate natural gas pipeline and related facilities

4


connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. 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 $834 million. For further information on this equity method investment, see Note 13 to the consolidated financial statements in this Form 10-K.

Also, we are a 10% equity member of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain 564 miles of natural gas pipeline with associated compression from $70.6 millionWest Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. We have committed to $125 million.

fund an amount in proportion to our ownership interest of 10% for the development and construction of the new pipeline, which is expected to cost between $4.5 billion to $5 billion. For further information on this equity method investment, see Note 13 to the consolidated financial statements in this Form 10-K.


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. For further information on the Acquisition, see Item 1A. Risk Factors, "Forward Looking Statements" in Item 7, and Note 2 and Note 16 to the consolidated financial statements in this Form 10-K.


5


Operating Statistics

The following is a five-year comparison of operating statistics for the years ended October 31, 20082011 through 2012.

   

2012

   

2011

   

2010

   

2009

   

2008

 

Operating Revenues (in thousands):

          

Sales and Transportation:

          

Residential

    $534,321      $658,892      $743,346      $787,994      $813,032  

Commercial

   301,013     379,846     428,085     462,160     503,317  

Industrial

   95,177     104,774     116,122     126,855     209,341  

Power Generation

   36,027     28,969     21,708     19,609     25,266  

For Resale

   9,512     9,692     11,061     11,746     12,326  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   976,050     1,182,173     1,320,322     1,408,364     1,563,282  

Secondary Market Sales

   140,380     244,824     224,973     221,300     515,968  

Miscellaneous

   6,350     6,908     7,000     8,452     9,858  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    $    1,122,780      $    1,433,905      $    1,552,295      $    1,638,116      $    2,089,108  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gas Volumes - Dekatherms

          

(in thousands):

          

System Throughput:

          

Residential

   43,788     57,778     58,327     55,298     51,909  

Commercial

   33,774     40,749     39,994     38,526     36,766  

Industrial

   89,234     90,842     82,805     74,363     81,780  

Power Generation

   151,675     83,522     63,024     39,639     30,875  

For Resale

   5,829     6,870     8,465     9,048     8,921  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   324,300     279,761     252,615     216,874     210,251  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Secondary Market Sales

   48,373     48,835     46,823     46,057     53,442  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Number of Customers Billed

          

(12-month average):

          

Residential

   878,851     871,401     864,205     855,670     852,586  

Commercial

   95,100     94,485     94,287     94,404     94,045  

Industrial

   2,265     2,265     2,273     2,358     2,937  

Power Generation

   22     22     20     20     20  

For Resale

   15     15     16     17     17  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   976,253     968,188     960,801     952,469     949,605  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Average Per Residential Customer:

          

Gas Used - Dekatherms

   49.82     66.30     67.49     64.63     60.88  

Revenue

    $607.98      $756.13      $860.15      $920.91      $953.61  

Revenue Per Dekatherm

    $12.20      $11.40      $12.74      $14.25      $15.66  

   2012   2011   2010   2009   2008 

Cost of Gas (in thousands):

          

Natural Gas Commodity Costs

  $379,145    $666,930    $753,529    $727,744    $1,454,073  

Capacity Demand Charges

   129,090     136,139     127,137     128,081     127,640  

Natural Gas Withdrawn From

          

(Injected Into) Storage, net

   27,580     11,362     5,293     126,480     (78,283)  

Regulatory Charges (Credits), net

   11,519     45,835     113,744     94,237     32,705  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $    547,334    $    860,266    $    999,703    $    1,076,542    $    1,536,135  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Supply Available for Distribution

          

(dekatherms in thousands):

          

Natural Gas Purchased

   132,426     155,550     157,021     149,696     159,857  

Transportation Gas

   235,474     175,005     147,038     115,519     108,332  

Natural Gas Withdrawn From

          

(Injected Into) Storage, net

   (378)     196     (1,309)     1,010     (2,980)  

Company Use

   (296)     (309)     (282)     (283)     (135)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   367,226     330,442     302,468     265,942     265,074  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2015.




2015
2014
2013
2012
2011
Operating Revenues (in thousands):







Sales and Transportation:









Residential
$656,182

$683,848
 $588,546
 $534,321
 $658,892
Commercial
370,339

397,004
 331,831
 301,013
 379,846
Industrial
106,986

115,515
 113,182
 95,177
 104,774
Power Generation
85,650

85,902
 64,109
 36,027
 28,969
For Resale
10,208

9,587
 9,549
 9,512
 9,692
Total
1,229,365

1,291,856
 1,107,217
 976,050
 1,182,173
Secondary Market Sales
134,322

169,543
 164,130
 140,380
 244,824
Miscellaneous
8,031

8,589
 6,882
 6,350
 6,908
Total
$1,371,718

$1,469,988
 $1,278,229
 $1,122,780
 $1,433,905
           
Gas Volumes - Dekatherms (in thousands)
       
System Throughput:


       
Residential
61,004

61,782
 55,283
 43,788
 57,778
Commercial
44,616

44,259
 39,602
 33,774
 40,749
Industrial
96,380

95,780
 95,019
 89,234
 90,842
Power Generation
262,161

201,707
 190,862
 151,675
 83,522
For Resale
7,362

7,174
 6,834
 5,829
 6,870
Total
471,523

410,702
 387,600
 324,300
 279,761
           
Secondary Market Sales
30,759

20,516
 41,605
 48,373
 48,835
           
Number of Customers Billed (12-month average):
       
Residential
916,719

903,067
 890,887
 878,851
 871,401
Commercial
98,544

97,288
 96,009
 95,100
 94,485
Industrial
2,283

2,279
 2,271
 2,265
 2,265
Power Generation
25

25
 24
 22
 22
For Resale
15

16
 15
 15
 15
Total
1,017,586

1,002,675
 989,206
 976,253
 968,188
           
Cost of Gas (in thousands):


       
Natural Gas Commodity Costs
$450,100

$621,604
 $526,703
 $379,145
 $666,930
Capacity Demand Charges
131,196

144,313
 151,369
 129,090
 136,139
Natural Gas Withdrawn From
 
       
(Injected Into) Storage, net
25,715

(13,578) (5,867) 27,580
 11,362
Regulatory Charges (Credits), net
37,413

27,441
 (15,466) 11,519
 45,835
Total
$644,424

$779,780
 $656,739
 $547,334
 $860,266
           
Supply Available for Distribution (dekatherms in thousands):





Natural Gas Purchased
144,862

134,986
 142,884
 132,426
 155,550
Transportation Gas
359,986

299,166
 287,980
 235,474
 175,005
Natural Gas Withdrawn From


       
(Injected Into) Storage, net
(573)
(1,232) (509) (378) 196
Company Use
(700)
(731) (369) (296) (309)
Total
503,575

432,189
 429,986
 367,226
 330,442

During the year ended October 31, 2012,2015, we delivered 324.3471.5 million dekatherms (one dekatherm equals 1,000,000 BTUs) to our utility retail customers compared to 279.8410.7 million dekatherms the year before. Of this amount, 246.7365.9 million dekatherms of gas were sold to or transported for large volume customers compared with 181.2304.7 million dekatherms in 2011.2014. Of these volumes sold to or transported for large volume customers, we transported 151.7262.2 million dekatherms this yearin 2015 to power generation facilities compared with 83.5201.7 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the

6


weather, totaled 77.6105.6 million dekatherms in 2012,2015, compared with 98.5106 million dekatherms in 2011.2014. Weather, as measured by degree days, was 19% warmer than normal in 2012 and 10%6% colder than normal in 2011.

2015 and 9% colder than normal in 2014.


We have added increasing numbers of customers in our service areas each year over our last four fiscal years. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas resulted in growth in both the residential new construction and commercial markets. Growth in residential conversion and industrial markets decreased slightly in fiscal 2015, reflecting a longer sales cycle for conversions and a decline in readily available opportunities for industrial conversions.

We forecast continuing gross customer growth in fiscal 2016 of approximately 1.6 – 2% on our base of approximately one million utility retail customers. Total net customers billed increased 2% in fiscal year 2015 compared to 2014.

Natural Gas Utility Operations

We purchase natural gas under firm contracts to meet our design-day requirements for firm sales customers. These contracts provide that we pay a reservation fee to the supplier to reserve or guarantee the availability of gas supplies for delivery. Under these provisions, absent force majeure conditions, any disruption of supply deliverability is subject to penalty and damage assessment against the supplier. We ensure the delivery of the gas supplies to our distribution system to meet the design peak day, seasonal and annual needs of our firm customers by using a variety of firm transportation and storage capacity contracts. The pipeline capacity contracts require the payment of fixed monthly demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement these firm contracts with other supply arrangements to serve our interruptible market.


As of October 31, 2012,2015, we had contracts for the following pipeline firm transportation capacity in dekatherms per day.

Williams-Transco

Williams – Transco		632,100632,200 

Kinder Morgan -Tennessee– Tennessee Pipeline

37,00074,100 

Spectra-TexasSpectra – Texas Eastern (through(partially through East Tennessee and Transco)

11,70036,700 

NiSource-ColumbiaSpectra – East Tennessee (through Transco)

44,800
Oneok – Midwestern (through East Tennessee)25,000
Columbia Pipeline Group – Columbia Gas (through Transco and Columbia Gulf)

42,800

NiSource-ColumbiaColumbia Pipeline Group – Columbia Gulf

41,00010,000 

ONEOK-Midwestern (through Tennessee, Columbia Gulf, East Tennessee and Transco)

Total		834,400    120,000 

Total

915,800 



As of October 31, 2012,2015, we had the following assets or contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets with deliverability from 5 days to one year.

Piedmont Liquefied Natural Gas (LNG)

270,000250,000 

Pine Needle LNG (through Transco)

263,400

Williams-TranscoWilliams – Transco Storage

86,100

NiSource-ColumbiaColumbia Pipeline Group – Columbia Gas Storage

96,400

Hardy Storage (through Columbia Gas and Transco)

68,800

DominionKinder Morgan – Tennessee Pipeline Storage (through Transco)

55,90013,200 

Kinder Morgan -Tennessee Pipeline Storage

Total		840,60055,900 

Total

    833,800 



As of October 31, 2012,2015, we own or have under contract 36.135.7 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capabilitycapacity is used to supplement or replace regular pipeline supplies.

We


As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2015, the amount of natural

7


gas in storage varied from 13.3 million dekatherms to 25.8 million dekatherms, and the commodity cost of this gas in storage varied from $54.4 million to $114.5 million.

Natural gas development and production in North America continues to provide abundant supply and price stability and moderation for natural gas as an energy commodity. With lower gas prices over the past eight years, we have historically sourcedbeen able to significantly lower the cost of gas to our customers with multiple filings for reductions in the wholesale natural gas component of customer rates in the three jurisdictions that we distribute primarily fromserve. Currently, natural gas has a price advantage over other fuels, and it is anticipated that the Gulf Coast production region. cost of natural gas will remain competitive due to abundant sources of shale gas reserves.

We purchase theseour natural gas supplies by contracting primarily with major and independent producers and marketers. We also purchase a diverse portfolio of transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed due to market demand fluctuations, we may release these services in the secondary market under FERC-approved capacity release provisions, with proceeds received being used to reduce the cost of natural gas we charge to customers through the sharing mechanism that is available in all three jurisdictions whereby customers are allocated 75% of the savings through the incentive plans. Peak-use requirements are met through the use of company owned storage facilities, pipeline transportation capacity, purchased storage services and other supply sources. We have been able to obtain sufficient supplies of natural gas to meet customer requirements, and with the prospect of abundant domestic shale natural gas supplies and our contracted pipeline capacity, we believe that we will be able to meet our market demands in the future.

To


When firm pipeline services or contracted gas supplies are temporarily not needed due to market demand fluctuations, we may release these services and supplies in the secondary market under FERC-approved capacity release provisions or make wholesale secondary market sales. The proceeds from those transactions are used to reduce the cost of natural gas we charge to customers through sharing mechanisms that are in place in all three jurisdictions whereby customers are allocated 75% of the savings through the incentive plans. For further information on these regulatory sharing mechanisms, see Note 3 to the consolidated financial statements in this Form 10-K.

We continue to diversify our reliance away from the Gulf Coast region, we receive firm, long-term market area storage service from Hardy Storage Company, LLC (Hardy Storage) located in West Virginia, Columbia Gas Storage located in West Virginia, Ohio and Pennsylvania, and Dominion Storage located in West Virginia, Pennsylvania and New York that may be filled with Appalachian sourced supply. We also contract for firm, long-term transportation service from Midwestern Gas Transmission Company that provides access to gas supplies from Canadian and Rocky Mountain supply basins and the Chicago hub that can supply city gate demand or be used to fill storage facilities on Tennessee Gas Pipeline, Columbia Gas, Pine Needle and Transco.

In November 2012, we executed our supply diversification strategyportfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. WeIn November 2012, we signed a long-term contract with Cabot Oil & Gas (Cabot) to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams-Transco forWilliams – Transco under its Leidy Southeast expansion project to transport thosethe Marcellus based Cabot gas supplies to our markets. ThesePartial service under these contracts began in December 2015. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that began service in September 2015. We believe these new supply arrangements are scheduled to begin in December 2015, and we believe they willcapacity arrangements provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.

We completed Also, with the new ACP project that is targeted to be in service in late 2018, we will have additional pipeline expansion projectscapacity from diversified gas supply basins under a long-term firm service agreement that we executed with ACP, subject to FERC approval of the project.


Competition

Our regulated utility competes with other energy products, such as electricity and propane, in December 2011the residential and June 2012 to provide long-termcommercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas delivery service to two power generation customersincluding price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in our market area. We have one pipeline expansion project under construction to provide natural gas delivery service to a power generation facility currently under construction in North Carolina with a targeted in service date of June 2013. In addition to delivering the natural gas supply to achieve the environmental benefits of replacing coal-fired power plants with new natural gas-fired power plants, the constructionprice of natural gas pipelines for two of these projects increasescan negatively impact our natural gas infrastructure incompetitive position by decreasing the eastern part of North Carolina and enhances future opportunities for economic growth and development. See the following discussion of our forecasted capital investment related to the construction of the natural gas pipelines and compressor stations to serve these new power generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

With some improvement in economic conditions and targeted marketing programs on theprice benefits of natural gas in our service areas, we have made gains in utility customer growth. The composition of our new customers forto the year ended October 31, 2012 is presented below.

Residential new home construction

7,939 

Residential conversion

3,789 

Commercial

1,546 

  Total new customers

13,274 

We forecast continuing grossconsumer. This can lead to slower customer growth for fiscal 2013 of approximately 1%.

Our business model supports new clean energy technologiesor customer conservation, or both, resulting in reduced gas purchases and energy efficiencies in the end use of natural gas. We are seeking opportunities for regulatory innovationcustomer billings. In turn, this can impact our capital expenditures and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting theoverall cash needs, including working capital needs. The direct use of natural gas in more homes and businesses industriesis the most efficient and vehicles as we strongly believe that the expandedcost effective use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce bothand results in overall energy consumption and greenhouse gas emissions and enhance our national energy security. We see an opportunity inlower carbon emissions. However, the clean energy technologyuse of compressed natural gas (CNG) vehicles. We are executingfor power generation also adds significant value as a plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. We currently ownresult of natural gas’ environmental attributes, competitive cost advantage and operate eight company CNG fueling stations at Company resource centers with 14%efficiency of our vehicle fleet capable of using CNG. We are also actively pursuing other commercial fleets to utilize company CNG stations and will serve commercial customers with fueling stations at their sites where there is sufficient demand. We sold 38,000 dekatherms of CNG to commercial customers for the year ended October 31, 2012, which is equivalent to approximately 579 homes, and used 4,880 dekatherms of CNG in our own fleets. Through sales of CNG to commercial customers and use by our own fleet, this CNG usage displaced more than 344,000 gallons of gasoline and diesel fuel.

To further our strategy of expanding our complementary energy-related businesses, in November 2012, we entered into an agreement to become a 24% equity member of Constitution Pipeline Company, LLC with two other members. The purpose of the joint venture is to construct and operate an interstate natural gas pipeline and related facilities connecting gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. 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 between $700 – $800 million. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

delivery.


During the year ended October 31, 2012,2015, approximately 5%3% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price and alternative fuels.relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the USU.S. dollar versus other currencies. Our marginliquidity could be impacted, either positively or negatively, as a result of changes in oil and natural gas prices and the alternate fuel decisions made by industrial customers.


Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2012,2015, no bypass occurred. The future level of bypass activity cannot be predicted.

The regulated utility also


8



Natural gas for power generation competes with other energy products, suchfuel sources for the generation of electricity, including coal, nuclear and renewable resources. Additionally, as electricity and propane, inwith industrial customers, we compete with other pipeline providers to serve the residential and small commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. The direct use of natural gas in homes and businesses is the most efficient and cost effective use of natural gas and results in overall lower carbon emissions.

power generation plants.


Other

During the year ended October 31, 2012,2015, our largest revenue generating customer contributed $59.2$86.3 million, or 5%6%, of total operating revenues. Our largest margin generating customer contributed $27.5$73.2 million, or 5%10% of total margin.

Our largest revenue and margin generating customer is the same customer.


Our costs for research and development are not material and are primarily limited to natural gas industry-sponsored research projects.


Compliance with federal, state and local environmental protection laws have had no material effect on our construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7 ofin this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.


Costs incurred for natural gas, labor, employee benefits, consulting and construction are the business charges that we incur that are most significantly impacted by inflation. Changes to the cost of gas are generally recovered through regulatory mechanisms and do not significantly impact

net income. Labor and employee benefits are components of the cost of service, and construction costs less utility deferred income taxes are the primary componentcomponents of rate base. In order to recover increased costs and earn a fair return on rate base, we file general rate cases for review and approval by regulatory authorities in North Carolina and Tennessee, when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. See the discussion above for information on IMRs to track and recover certain capital costs in North Carolina and Tennessee outside of a general rate case. In South Carolina, we operate under a rate stabilizationRSA mechanism that reduces theregulatory lag to one year. This regulatoryyear, but we reserve the right to file general rate cases when necessary. Regulatory lag can impact earnings.


As of October 31, 2012,2015, our fiscal year end, we had 1,7521,943 employees compared with 1,7821,879 as of October 31, 2011.

2014.


Our reports on Form 10-K, Form 10-Q and Form 8-K, and any amendments to these reports, are available at no cost on our website atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission (SEC).Commission.


Item 1A. Risk Factors


Market Risks

An overall economic downturn could negatively impact our earnings.

Weakening


Any weakening of economic activity in our markets could result in a loss of customers, a decline in customer additions, especially in the new home construction market, or a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. It may become more difficult for customers to pay their gas bills, leading to slow collections and higher-than-normal levels of accounts receivable. This could increase our financing requirements and non-gas cost bad debt expense. Deteriorating economic conditions could also affect pension costs by reducing the value of the investments that fund our pension plan and negatively affect actuarial assumptions, resulting in increased pension costs. The foregoing could negatively affect earnings and liquidity, reducing our ability to grow the business.


Increases in the wholesale price of natural gas could reduce our earnings and working capital.

The


A supply and demand balanceimbalance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production of U.S. shale natural gas has put downward pressure on the wholesale cost of natural gas; accordingly, restrictions or regulations on shale gas production could cause natural gas prices to increase. Additionally, the CommoditiesCommodity Futures Trading Commission (CFTC) under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. The prudently incurred cost we pay for natural gas is passed directly through to our customers. Therefore, significant increases in the price of natural gas may cause our existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders and new customers to select alternative sources of

9


energy. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, and a decline in new customers could impede growth in our future earnings. In addition, during periods when natural gas prices are high, our working capital costs could increase due to higher carrying costs of gas storage inventories, adding further upward pressure on customers’customer bills. Customers may have trouble paying those higher bills which may lead to bad debt expenses, ultimately reducing our earnings.

The availability of adequate interstate pipeline transportation capacity and natural gas supply may decrease.

We purchase all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to or reduction in that supply or interstate pipeline capacity due to events including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions, could reduce our normal interstate supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.

Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.

Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. If a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, recovery of regulatory assets, including deferred gas costs, or other tariff provisions, then our earnings could be negatively impacted.

In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Additionally, our capital investment in recent years has been and is projected to remain at higher levels, increasing the risk of cost recovery. The foregoing may negatively impact our results of operations and earnings.

Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various intervenors. Regulatory authorities also review whether our gas costs are prudent and can adjust the amount of our gas costs that we pass through to our customers. Additionally, our state regulators foster a competitive regulatory model that, for example, allows us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may directly access natural gas supply through their own connection to an interstate pipeline. If there are changes in the regulatory compact that alter our ability to compete for these customers, then we could lose customers or incur significant unrecoverable expenses or margin losses to retain them. The occurrence of any of the foregoing could negatively impact our results of operations, financial condition and cash flows.

Our debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.


Our business is subject to competition that could negatively affect our results of operations.


The natural gas business is competitive, and we face competition from other companies that supply energy, including electric companies, oil and propane dealers, renewable energy providers and coal companies in relation to sources of energy for electric power plants, as well as nuclear energy. A significant competitive factor is price.


In residential, commercial and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas or decreases in the price of other energy sources could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. In the case of industrial customers, such as manufacturing plants, adverse economic or market conditions, including higher gas costs, could cause these customers to suspend business operations or to use alternative sources of energy or bypass our systems in favor of energy sources with lower per-unit costs.


Higher gas costs or decreases in the price of other energy sources may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of the non-price attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business and adversely affecting our earnings.

Our business activities are concentrated in three states.

Approximately 97% of our assets and 88% of our earnings before taxes come from our regulated utility businesses. Further, approximately 70% of our natural gas utility customers and most of our utility transmission and distribution pipelines are located in North Carolina, with the remainder located in South Carolina and Tennessee. Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers and could adversely affect our earnings.

We are subject to new and existing laws and regulations that may require significant expenditures, significantly increase operating costs, or significant fines or penalties for noncompliance.

Our business and operations are subject to regulation by the FERC, the NCUC, the PSCSC, the TRA, the DOT, the EPA, the CFTC and other agencies, and we are subject to numerous federal and state laws and regulations. Compliance with existing or new laws and regulations may result

in increased capital, operating and other costs which may not be recoverable in rates from our customers. Furthermore, because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. All of the above could result in a material adverse effect on our business, results of operations or financial condition.

Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.

The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide. Such laws or regulations could impose costs tied to carbon emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could negatively impact the reputation of fossil fuel products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.


Weather conditions may cause our earnings to vary from year to year.


Our earnings can vary from year to year, depending in part on weather conditions. Warmer-than-normal weather can reduce our utility margins as customer consumption declines. We have in place regulatory mechanisms and rate design that normalize the margin we collect from certain customer classes during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. If our rates and tariffs are modified to eliminate weather protection provisions, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather. Additionally, our weather normalization mechanisms provide reduceddo not ensure full protection, especially for significantly warmer-than-normal winter weather. As a result of the foregoing,these events, our results of operations and earnings could vary and be negatively impacted.

The operation


Commercial Risks

We are exposed to credit risk of counterparties with whom we do business.

Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our gas distribution and transmission activities may be interrupted by accidents, work stoppage, severe weather conditions, including destructive weather patterns, such as hurricanes, tornadoes and floods, pandemicservices or acts of terrorism.

Inherentfulfill their contractual obligations. We depend on these counterparties to remit payments to fulfill their contractual obligations on a timely basis. Any delay or default in our gas distribution and transmission activities, including natural gas and LNG storage, are a variety of hazards and operational risks, such as third party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorismpayment or cyber-attacks, could also damage our pipelines and other infrastructure and disrupt our ability to

conduct our natural gas distribution and transportation business. The outbreak of a pandemic could result in a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If the foregoing events are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Our regulators may not allow us to recover part or allfailure of the increased cost relatedcounterparties to the foregoing events from our customers, which would negatively affect our earnings. The occurrence of any of these eventsmeet their contractual obligations could adversely affect our financial position, results of operations andor cash flows.


The availability of adequate interstate pipeline transportation capacity and natural gas supply may decrease.

We purchase almost all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to or reduction in that supply or interstate pipeline capacity due to events including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions or requirements, including remediation

10


related to integrity inspections, could reduce our normal interstate supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.

Our business activities are concentrated in three states.

Approximately 96% of our assets and 85% of our earnings before taxes come from our regulated utility business. Further, approximately 70% of our natural gas utility customers, including customers served by three North Carolina municipalities who are our wholesale customers, and most of our utility transmission and distribution pipelines are located in North Carolina, with the remainder located in South Carolina and Tennessee. Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers and could adversely affect our earnings.

We may not be able to complete necessary or desirable pipeline expansion or infrastructure development or maintenance projects, which may delay or prevent us from serving our customers or expanding our business.


In order to serve current or new customers or expand our service to existing customers, we need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, we may not be able to adequately serve existing customers or support customer growth, or could result in higher than anticipated cost, both of which would negatively impact our earnings. In addition, the counterparty to one of our power generation construction agreements may elect to terminate the agreement prior to the in-service date for the project, which would negatively affect future earnings and cash flows.


Financial Risks

A downgrade in our credit ratings could negatively affect our cost of and ability to access capital.


Our ability to obtain adequate and cost effective financing depends in part on our credit ratings. A negative change in our ratings outlook or any downgrade in our current investment-grade credit ratings by our rating agencies, particularly below investment grade, could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit our access to private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, the interest rate on our borrowings under our revolving credit agreement and unsecured commercial paper (CP) program, as well as on any future public or private debt issuances, would increase. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.


We may be unable to access capital or the cost of capital may significantly increase.


Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets or waning investor sentiment could adversely affect our ability to access short-term and long-term capital. Our access to funds under short-term credit facilitiesour CP program is dependent on the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding

commitments if they experience shortages of capital and liquidity.investor demand for our commercial paper. Disruptions and volatility in the global credit markets could causelimit the demand for our commercial paper or result in the need to offer higher interest rate we pay on our short-term credit facility,rates to investors, which is based on the London Interbank Offered Rate, to increase, couldwould result in higher interest rates on future financings,expense and could adversely impact the liquidity of the lenders under our short-term credit facility, potentially impairing their ability to meet their funding commitments. Disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to capital needed for our business.liquidity. Tax rates on dividends may increase, which could increase the cost of equity. The inability to access adequate capital or the increase in cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.

Changes in federal and state fiscal, tax and monetary policy could significantly increase our costs or decrease our cash flows.

Changes in federal and state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if we are not able to recover such increased costs from our customers. This series of events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash flows. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.


We do not generate sufficient cash flows to meet all our cash needs.

Historically, we


We have made, and expect to continue to make, large capital expenditures in order to finance the expansion, upgrading and maintenance of our transmission and distribution systems. We also purchase natural gas for storage. We have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We fund a portion of our cash needs for these purposes, as well as contributions to

11


our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new debt and equity securities. Our dependency on external sources of financing creates the risk that our profits could decrease as a result of higher borrowing costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us. Volatility in seasonal cash flow requirements, including requirements for our gas supply procurement and risk management programs, may require increased levels of borrowing that could result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a credit rating downgrade. Any disruptions in the capital and credit markets could require us to conserve cash until the markets stabilize or until alternative credit arrangements or other funding required for our needs can be secured. Such measures could cause deferral of major capital expenditures, changes in our gas supply procurement program, the reduction or elimination of the dividend payment or other discretionary uses of cash, and could negatively affect our future growth and earnings.


As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.


The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.

We are exposed to credit risk of counterparties with whom we do business.

Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments to fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligations could adversely affect our financial position, results of operations or cash flows.


The cost of providing pension benefits and related funding obligations may increase.


Our costs of providing a non-contributory defined benefit pension plan are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in these actuarial assumptions, future government regulation, changes in life expectancy and our required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund our pension plan, if not offset or mitigated by a decline in our liabilities, could increase the expense of our pension plan, and we could be required to fund our plan with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing cash flows and could negatively affect results of operations.


Regulatory Risks

Elevated levels of capital expenditures may weaken our financial position and inhibit customer growth.

We make significant annual capital expenditures for system integrity, infrastructure and maintenance that do not immediately produce revenue. We have the ability to recover these costs either through general rate cases or alternative rate mechanisms approved by state regulatory commissions, such as RSAs and IMRs, that periodically adjust rates to reflect incurred capital expenditures. However, before rates are adjusted, we fund construction through operating cash flows and by accessing short- and long-term capital markets and as a result, we may investexperience reduced liquidity and deteriorating credit metrics, which may weaken our financial position and could trigger a possible downgrade from the rating agencies. In addition, after these capital costs are reflected in companiesrates, to the extent that rates rise considerably, customers may choose alternative forms of energy to meet their needs. This would reduce our customer growth, which would weaken our financial position by reducing earnings and cash flows.

Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.

Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. Our earnings could be negatively impacted if a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return, or significantly lowers our allowed return or negatively alters our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, or prohibits recovery of regulatory assets, including deferred gas costs.

In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be

12


filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have risksthe authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that are inherentdo not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Additionally, our capital investment in their businesses,recent years has been and these risksis projected to remain at higher levels, increasing the risk of cost recovery. All of this may negatively affectimpact our earnings from those companies.

Weresults of operations and earnings.


Rate cases also involve a risk of rate reduction, because once rates have been filed, they are investedstill subject to challenge for their reasonableness by various intervenors. State regulators have approved various mechanisms to stabilize our gas utility margin, including margin decoupling in severalNorth Carolina, rate stabilization in South Carolina, and uncollectible gas cost recovery in all states. State regulators have approved other margin stabilizing mechanisms that, for example, allow us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may otherwise directly access natural gas related businesses assupply through their own connection to an interstate pipeline. If regulators decided to discontinue allowing us to use these tariff mechanisms, it would negatively impact our results of operations, financial condition and cash flows. In addition, regulatory authorities also review whether our gas costs are prudent and can disallow the recovery of a portion of our gas costs that we seek to recover from our customers, which would adversely impact earnings.

Our debt and equity method investor. The businessesfinancings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in which we investthe capital markets. This could negatively impact our liquidity or earnings.

We are subject to new and existing laws and regulations that may require significant expenditures, significantly increase operating costs, or market conditions,significant fines or have risks inherent in theirpenalties for noncompliance.

Our business and operations that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experiencedregulation by our regulated utility segment. We do not control the dayFERC, the NCUC, the PSCSC, the TRA, the DOT, the EPA, the CFTC and other agencies, and we are subject to day operations of our equity method investments,numerous federal and thus the management of these businesses by our partners could adversely impact their performance. Westate laws and regulations. Compliance with existing or new laws and regulations may result in increased capital, operating and other costs which may not be ablerecoverable in rates from our customers. For example, while we have implemented an IMR mechanism in North Carolina and Tennessee to fully directrecover certain capital expenditures made in compliance with federal and state safety and integrity management laws or regulations, there is a risk that the managementrelevant regulators will disallow some of the expenditures under the IMR mechanism, and policiesthat the costs expended in compliance with such laws would not be recoverable through such rate mechanisms (but rather through general rate cases with extended lag). Because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these businesses,laws and other participants in those relationshipsregulations may take action contrary to our interests, including making operational decisions that could affect our costs and liabilitiesnot be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation. As the regulatory environment for our investment. In addition, other participants may withdraw fromindustry increases in complexity, the business, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours.risk of inadvertent noncompliance could also increase. All the foregoingof these events could adversely affectresult in a material adverse effect on our

earnings from or return of our investment in these businesses. We could make future equity method investments or acquisitions of unregulated businesses that have the similar potential to adversely affect our earnings from or return of our investment in those businesses. All these adverse impacts could negatively affect our business, results of operations or financial condition.


Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.

The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide and air emissions regulations that could be expanded to address emissions of methane. Such laws or regulations could impose costs tied to carbon emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could negatively impact the reputation of fossil fuel products or services. The occurrence of these events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.

Changes in federal and/or state fiscal, tax and monetary policy could significantly increase our costs or decrease our cash flows.

Changes in federal and/or state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if

13


we are not able to recover such increased costs from our customers. These events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our earnings and cash flows. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.

Operational Risks

The operation of our gas distribution and transmission activities may be interrupted by accidents, work stoppage, severe weather conditions, including destructive weather patterns, such as hurricanes, tornadoes and floods, pandemic or acts of terrorism and sabotage.

Inherent in our gas distribution and transmission activities, including natural gas and LNG storage, are a variety of hazards and operational risks, such as third-party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorism and sabotage, could also damage our pipelines and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business. The outbreak of a pandemic could result in a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If these events are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Our regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would negatively affect our earnings. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.

We may be unable to attract and retain professional and technical employees, which could adversely impact our earnings.


Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract, train, develop and retain a skilled workforce. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. Without a properly skilled and experienced workforce, our abilitycosts, including productivity and safety costs, costs to provide quality service to our customersreplace employees, and meet our regulatory requirements will be challenged,costs as a result of errors may increase, and this could negatively impact our earnings.

Changes in accounting standards may adversely impact our financial condition and results of operations.

The SEC is considering whether issuers in the United States should be required to prepare financial statements in accordance with International Financial Reporting Standards (IFRS) instead of the current generally accepted accounting principles in the United States (GAAP). IFRS is a comprehensive set of accounting standards promulgated by the International Accounting Standards Board (IASB), which are currently in effect for most other countries in the world. Unlike U.S. GAAP, IFRS does not currently provide an industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other potential changes associated with the adoption of IFRS, may adversely impact our reported financial condition and results of operations should adoption of IFRS be required. Also, the U.S. Financial Accounting Standards Board is considering various changes to U.S. GAAP, some of which may be significant, as part of a joint effort with the IASB to converge accounting standards over the next several years. If approved, adoption of these changes may adversely impact our reported financial condition and results of operations.

Cyber-attack,


Cybersecurity attack, acts of cyber-terrorism or failure of technology systems could disrupt our business operations, shut down our facilities or result in the loss or exposure of confidential or sensitive customer, employee or Company information.


We are placing greater reliance on technological tools that support our operations and corporate functions and processes. We may own these tools or have a license to use them, or we may rely on the technological tools of third parties to whom we outsource processes. We use such tools to manage our natural gas distribution and transmission pipeline operations, maintain customer, employee, Company and vendor data, prepare our financial statements, make compliance filings and manage supply chain and other business processes. One or more of these technologies may fail due to physical disruption such as flooding, design defects or human error, or we may be unable to have these technologies supported, updated, expanded or integrated into other technologies. As technology and as our business operations change, we may replace or add systems and tools, and failure to successfully execute on these projects may result in business disruption or loss of data. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.

In recent years, cybersecurity risks have increased due in part to the increased sophistication and frequency of the attacks.


Disruption or failure of business operations and information technology systems could shut down our facilities or otherwise adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline systems, serve our customers effectively or manage our assets. An attack on or failure of information technology systems could result in the unauthorized release of customer, employee or other confidential or sensitive data. The foregoingThese events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our operations and financial results could be adversely affected.


Our insurance coverage may not be sufficient.


We currently have general liability, property and propertycyber insurance in place in amounts that we consider appropriate

14


based on our business risk and best practices in our industry and in general business. Such policies are subject to certain limits and deductibles and include business interruption coverage for limited circumstances. Insurance coverage coveringfor risks against which we and others in our industry typically insure may not be available in the future, or may be available but at materially increased costs, reduced coverage or on terms that are not commercially reasonable. Premiums and deductibles may increase substantially. The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on our financial position, results of operations and cash flows.


Strategic Risks

We may invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.

We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by our regulated utility segment and our regulated non-utilities segment. We do not control the day to day operations of our equity method investments, and thus the management of these businesses by our partners could adversely impact their performance. We may not be able to fully direct the management and policies of these businesses, and other participants in those relationships may take action contrary to our interests, including making operational decisions that could affect our costs and liabilities related to our investment. In addition, other participants may withdraw from the business, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours. The results of operations from those investments may be significantly less or realized significantly later than anticipated. All the above could adversely affect our earnings from or return on our investment in these businesses. We could make future equity method investments, acquisitions, or other business arrangements involving regulated or unregulated businesses as a minority or majority owner, with the similar potential to adversely affect our earnings from or return of our investment in those businesses.

Risks Related to the Proposed Acquisition by Duke Energy

The Acquisition is subject to receipt of consent or approval from our shareholders and various governmental entities that could delay or prevent the completion of the Acquisition or, in order to receive such consent or approval, the governmental entities may impose restrictions or conditions that could have a material adverse effect on the combined company or that could cause the companies to terminate the transaction.

Completion of the Acquisition is contingent upon, among other things, satisfaction or waiver of specified closing conditions, including (i) the approval of the Acquisition by the holders of a majority of the outstanding shares of Piedmont’s common stock, (ii) the receipt of regulatory approvals required to consummate the Acquisition, including approval from the NCUC, (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (Hart-Scott-Rodino Act), (iv) the absence of any law, statute, ordinance, code, rule, regulation, ruling, decree, judgment, injunction or order of a governmental authority that prohibits the consummation of the Acquisition, and (v) other customary closing conditions. If the Acquisition is consummated, holders of shares of Piedmont common stock will have no on-going equity in the surviving corporation, will cease to participate in Piedmont’s future earnings and growth and will not benefit from any future increases in the value of Piedmont.
We may not receive the required statutory approvals and other clearances for the Acquisition, or we may not receive them in a timely manner. If such approvals and clearances are received, they may impose terms, conditions or restrictions (i) that cause a failure of the closing conditions set forth in the Merger Agreement, which could permit us or Duke Energy to terminate the Merger Agreement or (ii) that could reasonably be expected to have a detrimental impact on the combined company following completion of the Acquisition. A substantial delay in obtaining the required authorizations, approvals or consents or the imposition of unfavorable terms, conditions or restrictions contained in such authorizations, approvals or consents could prevent the completion of the Acquisition.

Even after the expiration of the waiting period under the Hart-Scott-Rodino Act, governmental authorities could seek to block or challenge the Acquisition as they deem necessary or desirable in the public interest.


15


Failure to complete the Acquisition could adversely affect our stock price and future business operations and financial results.

Completion of the Acquisition is subject to risks, including the risks that approval of the transaction by our shareholders or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If we are unable to complete the Acquisition, holders of Piedmont common stock will not receive any payment for their shares pursuant to the Merger Agreement, our ongoing business may be adversely affected, and we would be subject to a number of risks, including the following:

we will have paid certain significant transaction costs, including legal, financial advisory and filing, printing and mailing fees, and in certain circumstances, a termination fee to Duke Energy of $125 million;
the attention of our management may have been diverted to the Acquisition rather than to our operations and the pursuit of other opportunities that could have been beneficial to us;
the potential loss of key personnel during the pendency of the Acquisition as employees may experience uncertainty about their future roles with the combined company;
we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the Acquisition is pending; and
the trading price of our common stock may decline if the market believes the Acquisition may not be completed.

A failure to complete the Acquisition may also result in negative publicity, additional litigation against Piedmont or its directors and officers, and a negative impression of Piedmont in the investment community. The occurrence of any of these events, individually or in combination, could have a material adverse effect on our results of operations or the trading price of our common stock.

We are subject to contractual restrictions in the Merger Agreement that may hinder operations pending the Acquisition.

The Merger Agreement restricts the Company, without Duke Energy’s consent, from certain specified actions until the Acquisition occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the Acquisition or termination of the Merger Agreement.

We will be subject to various uncertainties while the Acquisition is pending that may cause disruption and may make it more difficult to maintain relationships with employees, suppliers or customers.

Uncertainty about the effect of the Acquisition on employees, suppliers and customers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our abilities to attract, retain and motivate key personnel until the Acquisition is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change or terminate existing business relationships with us or not enter into new relationships or transactions.

Employee retention and recruitment may be particularly challenging prior to the completion of the Acquisition, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to continue employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our financial results could be adversely affected.

Potential future litigation against Piedmont and its directors challenging the Acquisition may prevent the Acquisition from being completed within the anticipated timeframe.

Piedmont and/or its directors may potentially be named as defendants in consolidated state class action lawsuits and potentially substantially similar federal class action lawsuits filed on behalf of public shareholders challenging the Acquisition and potentially seeking, among other things, to enjoin the defendants from consummating the Acquisition on the agreed-upon terms. If a plaintiff in a potential lawsuit or any other litigation that may be filed is successful in obtaining an injunction prohibiting the parties from completing the Acquisition on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Acquisition in the expected timeframe or altogether.

Item 1B. Unresolved Staff Comments


None.



16


Item 2. Properties


All property included in the Consolidated Balance Sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with the majority of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,8002,920 linear miles of transmission pipeline up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,00022,490 linear miles of distribution mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located near public streets and highways, or on property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on such property. All of these properties are located in North Carolina, South Carolina and Tennessee. Utility Plant includes “Construction work in progress”progress," which primarily represents distribution, transmission and general plant projects that have not been placed into service pending completion.


None of our property is encumbered, and all property is in use except for “Plant held for future use” as classified in the Consolidated Balance Sheets. The amount classified as plant held for future use relates to expenditures associated with a potential LNG peak storage facilityis comprised of land located in the eastern part ofRobeson County, North Carolina. There is no current need to proceed with theFor further information on this Robeson LNG peak

storage facility dueCounty property, see Note 1 and Note 3 to the expansion capacity, cost effectiveness, timing and design scope of another construction project that will enhance our ability to serve our North Carolina customersconsolidated financial statements in this area. The future use of this property is dependent upon annual updates to our ongoing five-year plan for forecasted growth requirements.

Form 10-K.


We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and our operating locations and resource centers located in North Carolina, South Carolina and Tennessee. Lease payments for these various offices totaled $3.7$5 million for the year ended October 31, 2012.

2015.


Property included in the Consolidated Balance Sheets in “Other Physical Property” is owned by the parent company and one of its subsidiaries. The property owned by the parent company primarily consists of natural gas water heaters leased to commercial customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.


Item 3. Legal Proceedings


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


Item 4. Mine Safety Disclosures


Not applicable.



17



PART II


Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities


Market Information


Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31, 20122015 and 2011.

2012       High   Low    2011      High   Low 

Quarter ended:

      Quarter ended:    

    January 31

   $  34.74   $  29.90       January 31  $  30.10   $  27.57 

    April 30

   34.00    29.05       April 30   32.00    27.88 

    July 31

   33.03    28.90       July 31   31.98    28.80 

    October 31

   33.72    31.03       October 31   33.60    25.86 

2014.

2015 High
 Low
 2014 High
 Low
Quarter ended:     Quarter ended:    
January 31 $41.09

$36.62
 January 31 $34.18
 $31.94
April 30 40.61

34.95
 April 30 36.55
 32.12
July 31 38.44

35.09
 July 31 37.86
 34.30
October 31 59.14

36.11
 October 31 38.36
 33.38

Holders


As of December 14, 2012,11, 2015, our common stock was owned by 13,39212,816 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in street name or in the name of an investment company.


Dividends


The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 20122015 and 2011.2014. We expect that comparable cash dividends will continue to be paid in the future.

Dividends PaidDividends Paid
2012

Per Share

2011

Per Share

Quarter ended:

Quarter ended:

January 31

29¢

January 31

28¢

April 30

30¢

April 30

29¢

July 31

30¢

July 31

29¢

October 31

30¢

October 31

29¢

  Dividends Paid   Dividends Paid
2015 Per Share 2014 Per Share
Quarter ended:    Quarter ended:   
January 31 32
¢ January 31 31
¢
April 30 33
¢ April 30 32
¢
July 31 33
¢ July 31 32
¢
October 31 33
¢ October 31 32
¢

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2012, net earnings available2015, our ability to pay dividends was not restricted. Per a provision in the Agreement and Plan of Merger (Merger Agreement) of the proposed acquisition (the Acquisition) by Duke Energy Corporation (Duke Energy) as discussed in Note 2 to the consolidated financial statements in this Form 10-K, our cash dividend cannot exceed the current annual per share dividend rate by more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practice. Also, provision is made for restricted payments were greater than retained earnings; therefore,a stub period dividend payment to holders of record of our retained earnings were not restricted.

shares of common stock immediately prior to consummation of the Acquisition.


Share Repurchases


The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2012.

2015.

18


Period
Total Number
of Shares
Purchased
Average Price
Paid Per Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Program
Maximum Number
of Shares that May
Yet be Purchased
Under the Program (1)
Beginning of the period2,910,074
8/1/15 – 8/31/15———2,910,074
9/1/15 – 9/30/15———2,910,074
10/1/15 – 10/31/15———2,910,074
        
Total Number of Maximum Number
— Total Number——  Shares Purchasedof Shares that May

of Shares

Average Price

Paid Per Share

as Part of PubliclyYet be Purchased

Period

Purchased

Announced Program

Under the Program (1)

Beginning of the period

2,910,074

8/1/12 - 8/31/12

-$-    -2,910,074

9/1/12 - 9/30/12

-$-    -2,910,074

10/1/12 - 10/31/12

-$-    -2,910,074

Total

-$-    -

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


Discussion of our compensation plans, under which shares of our common stock are authorized for issuance, is included in the portion of our proxy statement captioned “Executive Compensation” to be filed no later than January 31, 2013,February 28, 2016, in connection with our 2016 Annual Meeting, to be held on March 6, 2013, and is incorporated herein by reference.


Comparisons of Cumulative Total Shareholder Returns


The following performance graph compares our cumulative total shareholder return from October 31, 20072010 through October 31, 20122015 (a five-year period) with the average performance of our industry peer group and the Standard & Poor’s 500 Stock Index a broad market index (the S&P 500 Index)., a broad market index. Our LDClocal distribution company (LDC) Peer Group index is comprised of peer group companies that are domiciled in the United States, publicly traded havein the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our cumulativerelative total shareholder return asreturns, which we use for market benchmarking for our executive compensation plans when the end of the three-year performance period of a share-based plan award aligns with the current year of our report.

NICOR, Inc. and AGL Resources Inc. were included in our peer group for our fiscal year 2011. In 2012, NICOR, Inc. was merged into AGL Resources Inc.

plans.


The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 20072010 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.

Comparisons of Five-Year Cumulative Total Returns

Value of $100 Invested as of October 31, 2007

LDC Peer Group—The following companies are included: AGL Resources Inc., Atmos Energy Corporation, New Jersey Resources Corporation, NiSource Inc., Northwest Natural Gas Company, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc.

   

2007

   

2008

   

2009

   

2010

   

2011

   

2012

 

Piedmont

  $        100   $        134   $        99   $        130   $        150   $        152 

LDC Peer Group

   100    100    97    123    142    149 

S&P 500 Index

   100    64    70    82    88    102 



19


LDC Peer Group—The following companies are included: AGL Resources, Inc., Atmos Energy Corporation, CenterPoint Energy, New Jersey Resources Corporation, NiSource Inc., Northwest Natural Gas Company, Questar Corporation, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc. 

  2010 2011 2012 2013 2014 2015
Piedmont $100
 $115
 $117
 $130
 $150
 $234
LDC Peer Group 100
 118
 125
 149
 175
 193
S&P 500 Index 100
 108
 125
 158
 186
 195



20


Item 6. Selected Financial Data


The following table provides selected financial data for the years ended October 31, 20082011 through 2012.

In thousands except per share amounts

  

2012

   

2011

   

2010

   

2009

   

2008

 

Operating Revenues

  $1,122,780   $1,433,905   $1,552,295   $1,638,116   $2,089,108 

Margin (operating revenues less cost of gas)

  $575,446   $573,639   $552,592   $561,574   $552,973 

Net Income

  $119,847   $113,568   $141,954   $122,824   $110,007 

Earnings per Share of Common Stock:

          

Basic

  $1.67   $1.58   $1.96   $1.68   $1.50 

Diluted

  $1.66   $1.57   $1.96   $1.67   $1.49 

Cash Dividends per Share of Common Stock

  $1.19   $1.15   $1.11   $1.07   $1.03 

Total Assets *

  $  3,769,939   $  3,242,541   $  3,053,275   $  3,118,819   $  3,138,401 

Long-Term Debt (less current maturities)

  $975,000   $675,000   $671,922   $732,512   $794,261 
* Total assets for 2008 have been adjusted to reflect the gross presentation rather than a net presentation in accordance with the adoption of new accounting guidance related to offsetting of amounts related to certain contracts with the same counterparty.   

2015.

In thousands, except per share amounts
2015
2014
2013
2012
2011
Operating Revenues
$1,371,718

$1,469,988

$1,278,229

$1,122,780
 $1,433,905
Margin (operating revenues less cost of gas)
$727,294

$690,208

$621,490

$575,446
 $573,639
Net Income
$137,011

$143,801

$134,417

$119,847
 $113,568
Earnings per Share of Common Stock:






   
Basic
$1.74

$1.85

$1.80

$1.67
 $1.58
Diluted
$1.73

$1.84

$1.78

$1.66
 $1.57
Cash Dividends per Share of Common Stock
$1.31
 $1.27
 $1.23
 $1.19
 $1.15
Total Assets (1)

$5,110,750

$4,774,307

$4,360,277
 $3,764,144
 $3,238,780
Long-Term Debt (less current maturities) (1)

$1,523,677

$1,414,484

$1,166,525
 $969,205
 $671,239
(1) Total assets and long-term debt for the years 2011 through 2014 have been adjusted to reflect the netting of debt issuance costs with its debt carrying value in accordance with the 2015 adoption of new accounting guidance related to this balance sheet presentation.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations


Forward-Looking Statements


This report, as well asincluding the documents incorporated by reference and other documents that we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Item 1A. Risk Factors:

Factors, including those related to the Acquisition by Duke Energy that is more fully discussed in Note 2 to the consolidated financial statements in this Form 10-K:

economic

Economic conditions in our markets

markets.

wholesaleWholesale price of natural gas

gas.

availabilityAvailability of adequate interstate pipeline transportation capacity and natural gas supply

supply.

regulatoryRegulatory 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

basis.

competitionCompetition from other companies that supply energy

energy.

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

concentrated.

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

us.

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

opportunities.

weather conditions

Weather conditions.

operationalOperational interruptions to our gas distribution and transmission activities

activities.

abilityInability to complete necessary or desirable pipeline expansion or infrastructure development projects

projects.

Elevated levels of capital expenditures.

Changes to our credit ratings

ratings.

availabilityAvailability and cost of capital

capital.

federalFederal and state fiscal, tax and monetary policy

policies.

abilityAbility to generate sufficient cash flows to meet all our cash needs

needs.

abilityAbility to satisfy all of our outstanding debt obligations

obligations.

abilityAbility of counterparties to meet their obligations to us

us.

costsCosts of providing pension benefits

benefits.

earningsEarnings from the joint venture businesses in which we invest

invest.

abilityAbility to attract and retain professional and technical employees

employees.

changes in accounting standards

risk of cyber-attack, acts of cyber-terrorism,Cybersecurity breaches or failure of technology systems

systems.

ability

21


Ability to obtain and maintain sufficient insurance

insurance.

changeChange in number of outstanding shares

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 of shareholders to approve the Acquisition or a failure to obtain the required regulatory approvals;
delays caused by the required regulatory approvals, which may delay the Acquisition or cause the companies to abandon the transaction;
uncertainties and disruptions caused by the Acquisition that make it more difficult to maintain our business and operational relationships as well as maintain our relationships with employees, suppliers or customers, and the risk that unexpected costs will be incurred during this process;
the diversion of management time on Acquisition-related issues, and;
pending or 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 atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.


Overview


Piedmont Natural Gas Company, Inc. (Piedmont), 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 51,600 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

transportation businesses.


We have twooperate with three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.

Regulation

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina 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.

We are also subject to various federal regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular Factors critical to the natural gas industry, such as regulationssuccess of the Federal Energy Regulatory Commission that affect the purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation (DOT) 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. 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 delivered to our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag 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.

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. Alternative rate structures and cost recovery mechanisms are rate designs and mechanisms that allow utilities to encourage energy efficiency and conservation by separating or decoupling the link between energy consumption and margin revenues, thereby aligning the interests of 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 rate stabilization adjustment mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the rate stabilization adjustment tariff mechanism, we restate our rates in South Carolina based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism in South Carolina that partially offsets the impact of colder- or warmer-than-normal winter weather on bills rendered during the months of November through March to residential and commercial customers. In March 2012, we expanded our WNA mechanism in Tennessee to include bills rendered during the months of October through April to residential and commercial customers. Our WNA formulas calculate the actual weather variance

from normal, using 30 years of history and increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns significantly vary from consumption patterns used to establish the WNA factors.

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. For the year ended October 31, 2012, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 72% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 17% of our utility margins, including the rate stabilization adjustment mechanism in South Carolina and WNA mechanisms in South Carolina and Tennessee; and volumetric or periodic renegotiation of 11% of our utility margins, including our secondary marketing programs. For further information, see Note 2 to the consolidated financial statements.

Strategic Focus

Our strategic directives focus on our customers, our communities, our employees and our shareholders and reflect what we believe is the inherent advantages of natural gas compared to other types of energy. They 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 and service provider of choice

Achieve excellence in customer service every time

Preserve financial strength and flexibility

Execute sustainable business practices

Enhance our healthy, high performance culture

We believe natural gas is a safe and reliable energy source that is clean, efficient and abundant. We incorporate this belief into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We promote the increased awareness and use of natural gas and want our customers to choose us because of the value of natural gas and the quality of our service to them. With the environmental and cost benefits of using natural gas compared to coal in the generation of electricity, we have encouraged the development of gas-fired power generation facilities in our market area. We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and enhancing long-term shareholder value. We support our employees with improved processes and technology to better serve our customers while continuing to build a healthy, high performance culture in order to recruit, retain and motivate our workforce.

Our business model supports new clean energy technologies and energy efficiencies in the end use of natural gas. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security.

We have always placed a high priority on the safety of our system, the public and our employees, as safety is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing transmission and distribution pipeline integrity programs to inspect our system for corrosion and leaks as well as monitoring key metrics of our system for its safe operation. We anticipate federal legislative and regulatory enactments that will increase in scope and add further requirements and costs to our pipeline safety and integrity programs and our capital expenditure programs. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, which is the greatest cause of any pipeline damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength which includes a strong balance sheet, investment-grade credit ratings and continued access to capital markets. We evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue our efforts to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return for the benefit of our customers and shareholders.

We invest in joint ventures to complement or supplement income from our regulated utility operations if an opportunity aligns with our overall business strategies and allows us to leverage our core competencies. We analyze and evaluate potential projects withsegment include operating a major factor being projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.

Executive Summary

We monitor our progress and measure our performance related to our strategic directives and our business objectives over the course of our fiscal year. The metrics we use to measure our performance include, but are not limited to, earnings per share (EPS) and EPS growth, total shareholder return compared to our industry peer group, return on invested capital, return on equity, utility margin, investment grade credit ratings, customer growth, utility customer satisfaction and loyalty, operations and maintenance expense discipline, pipeline safety, carbon emissions and our corporate culture related to employee job satisfaction, health and safety.

Focus Areas and Achievements

Managing Gas Supplies and Prices. Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have sufficient and reliable supplies of competitively-priced natural gas to meet the needs of our utility customers. Natural gas development and

production in North America continues to provide supply stability and price moderation for natural gas as an energy commodity. In the past two years, the lower price of natural gas has allowed us to significantly lower the cost of gas to our customers. Currently, natural gas has a price advantage over many other fuels, and it is anticipated that the cost of natural gas will remain competitive due to abundant sources of shale gas reserves. In November 2012, in order to provide diversification, reliability and gas cost benefits to our customers, we signed long-term contracts to source more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These new supply arrangements are scheduled to begin in December 2015.

Customer Growth. With some improvement in economic conditions and targeted marketing programs on the benefits of natural gas, we have gains in utility customer growth in our service areas. Lower wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Customer gains in our residential market increased 29% in 2012 compared to 2011 from growth in new construction and conversion markets. Commercial customer additions increased 10% in 2012 compared to 2011, reflecting improvements in both commercial new construction activity and commercial conversion opportunities. We forecast continuing gross customer growth for fiscal 2013 of approximately 1%. Overall, total customers billed increased 1% in 2012 compared to 2011.

We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We are executing a plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. We currently own and operate eight company CNG fueling stations at Company resource centers with 14% of our vehicle fleet capable of using CNG. We are also actively pursuing other commercial fleets to utilize company CNG stations and will serve commercial customers with fueling stations at their sites where there is sufficient demand. We sold 38,000 dekatherms of CNG to commercial customers for the year ended October 31, 2012, which is equivalent to approximately 579 homes, and used 4,880 dekatherms of CNG in our own fleets. Through sales of CNG to our commercial customers and use by our own fleet, this CNG usage displaced more than 344,000 gallons of gasoline and diesel fuel.

Capital Expenditures. We continue to make progress with capital projects that we expect will provide benefits to our customers through safe and reliable natural gas service, while providingdistribution 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 shareholdersequity 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 reasonable returnwholly-owned subsidiary. For further information on invested capital. We completed pipeline expansion projectsequity method investments and business segments, see Note 13 and Note 15, respectively, to the consolidated financial statements in December 2011this Form 10-K.



22


Executive Summary

A summary of our annual results is as follows:
Comprehensive Income Statements Components
         
        Percent Change
        2015 vs. 2014 vs.
In thousands, except per share amounts 2015 2014 2013 2014 2013
Operating Revenues $1,371,718
 $1,469,988
 $1,278,229
 (6.7)% 15.0%
Cost of Gas 644,424
 779,780
 656,739
 (17.4)% 18.7%
Margin 727,294
 690,208
 621,490
 5.4 % 11.1%
Operations and Maintenance 294,517
 270,877
 253,120
 8.7 % 7.0%
Depreciation 128,704
 118,996
 112,207
 8.2 % 6.1%
General Taxes 42,110
 37,294
 34,635
 12.9 % 7.7%
Utility Income Taxes 76,934
 83,176
 77,334
 (7.5)% 7.6%
Total Operating Expenses 542,265
 510,343
 477,296
 6.3 % 6.9%
Operating Income 185,029
 179,865
 144,194
 2.9 % 24.7%
Other Income (Expense), net of tax 20,613
 18,622
 15,161
 10.7 % 22.8%
Utility Interest Charges 68,631
 54,686
 24,938
 25.5 % 119.3%
Net Income $137,011
 $143,801
 $134,417
 (4.7)% 7.0%
           
Average Shares of Common Stock:          
Basic 78,942

77,883
 74,884
 1.4 % 4.0%
Diluted 79,231

78,193
 75,333
 1.3 % 3.8%
           
Earnings per Share of Common Stock:          
Basic $1.74

$1.85
 $1.80
 (5.9)% 2.8%
Diluted $1.73

$1.84
 $1.78
 (6.0)% 3.4%
Margin by Customer Class
       
In thousands 2015 2014 2013
Sales and Transportation:            
Residential $376,568
 52% $348,782
 51% $331,920
 54%
Commercial 181,555
 25% 169,442
 25% 155,065
 25%
Industrial 49,877
 7% 50,889
 7% 52,268
 8%
Power Generation 77,244
 10% 77,573
 11% 56,312
 9%
For Resale 12,549
 2% 8,819
 1% 7,477
 1%
Total 697,793
 96% 655,505
 95% 603,042
 97%
Secondary Market Sales 21,122
 3% 25,414
 4% 8,979
 1%
Miscellaneous 8,379
 1% 9,289
 1% 9,469
 2%
Total $727,294
 100% $690,208
 100% $621,490
 100%


23


Gas Deliveries, Customers, Weather Statistics and Number of Employees
           
        Percent Change
        2015 vs. 2014 vs.
  2015 2014 2013 2014 2013
Deliveries in Dekatherms (in thousands):          
Residential 61,004
 61,782
 55,283
 (1.3)% 11.8 %
Commercial 44,616
 44,259
 39,602
 0.8 % 11.8 %
Industrial 96,380
 95,780
 95,019
 0.6 % 0.8 %
Power Generation 262,161
 201,707
 190,862
 30.0 % 5.7 %
For Resale 7,362
 7,174
 6,834
 2.6 % 5.0 %
Throughput 471,523

410,702
 387,600
 14.8 % 6.0 %
Secondary Market Volumes 30,759
 20,516
 41,605
 49.9 % (50.7)%
           
Customers Billed (at period end) 1,011,959

992,551
 979,909
 2.0 % 1.3 %
Gross Residential, Commercial and Industrial Customer Additions 17,017
 16,251
 14,293
 4.7 % 13.7 %
Degree Days          
Actual 3,449

3,543
 3,336
 (2.7)% 6.2 %
Normal 3,257

3,265
 3,276
 (0.2)% (0.3)%
Percent colder than normal 5.9%
8.5% 1.8% n/a
 n/a
Number of Employees (at period end) 1,943
 1,879
 1,795
 3.4 % 4.7 %

Financial Performance – Fiscal 2015 Compared with Fiscal 2014

Our 2015 net income decreased 5%. Margin increased 5% due to rate adjustments to customers through integrity management riders (IMRs) and June 2012 to provide long-term natural gas delivery service to two power generation customers in our market area. We have one pipeline expansion project under construction to provide natural gas delivery service to a power generation facility currently under constructionnew rates effective January 1, 2014 in North Carolina withunder a targetedrate case settlement, and overall customer growth, partially offset by lower margin sales from secondary market transactions. Operations and maintenance (O&M) expenses and depreciation expense increased 9% and 8%, respectively. The increase in service dateO&M expenses was related to increases in contract labor, payroll, employee benefits and regulatory expenses, including direct and indirect Acquisition-related expenses of June 2013. See$15.8 million, partially offset by a decrease in bad debt expense. Depreciation was higher due to increases in plant in service. General taxes increased 13% primarily due to increased state property and franchise taxes. Other Income (Expense), net of tax, increased 11% primarily due to an increase in income from equity method investments and a write-off in the discussionprior year of a cost-basis investment. Utility interest charges increased 26% as a result of increases in long-term debt outstanding and a decrease in capitalized interest recorded as income.

Business Summary – Fiscal 2015

Our fiscal 2015 performance reflects execution of our forecasted capital investment related to the construction of natural gas pipelines and compressor stations to serve new power generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We are increasing our utility capital expenditures for pipeline integrity,long-term business strategy that focuses on safety and compliance programs as well as systemgrowth in our markets, favorable changes in state regulation with new rates and technology infrastructure. To ensure safe pipeline operations, we are focusing on new technology throughIMRs, and secondary market activity. As discussed above, financial performance was solid for the development of a new workyear with increased earnings, excluding Acquisition-related expenses, and asset management system. These capital expenditures will require rate cases or other regulatory mechanisms to obtain a return of and on those capital costs. See further discussion in the section below on “Business Process and Technology Improvements.”

Regulatory Activity. We continue our regulatory strategy to implement rate structures that better align and balance the interests of shareholders and customers. In January 2012, the TRA approved an annual general rate increase of $11.9 million, effective March 2012, for Tennessee customers based on an approved rate of return of equity of 10.2%. This represented a 6.3% increase in annual revenue. In thatour dividend rate case, we shifted more of our cost recovery to the fixed portion of our customers’ bills to mitigate margin recovery fluctuations from volumetric usage. Our annual margin recovery from fixed monthly charges to Tennessee customers increased from 29% to 37% with a resulting decrease in annual margin recovery from volumetric charges from 71% to 63%. The TRA also approved an expansion of the WNA period by two months to October through April with updated WNA factors and the recovery of various deferred regulatory assets.

Even though we have WNA mechanisms in South Carolina and Tennessee, we are not fully insulated from the effects of weather that is significantly warmer than normal, such as that experienced during the 2011-2012 winter heating season. Weather in 2012 was 19% warmer than normal and 27% warmer than 2011.

For the year ended October 31, 2012, the margin decoupling mechanism in North Carolina increased margin by $46.8 million, and the WNA mechanisms in South Carolina and Tennessee increased margin by $13.3 million, which included the additional months of April and October 2012 in Tennessee.

Business Process and Technology Improvements. To support our strategic objectives of excellence in customer service, as discussed above in the “Strategic Focus,” we have reorganized our field customer service, sales and marketing, field operations and maintenance and construction departments into functional organizations to provide a more focused and better managed approach to customer service with an end goal of increasing customer loyalty and satisfaction while improving operational efficiencies. We have also implemented centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.

We are in the process of a multi-year program designed to bring additional technology and automationper share to our field operations by providing systems and information to enable operations employees to more effectively and efficiently manage our pipeline assets, ensure operating efficiencies and facilitate compliance with pipeline safety and integrity regulations. This enhanced and new systems and process program, which includes multiple projects, will be integrated with our current and future financial and other business systems.

investors.


Cost Containment Measures. We continue to focus on improving operating efficiency and productivity and cost containment discipline where possible in payroll, corporate overhead charges and various discretionary spending categories. We have benefited from cost containment measures during the current and prior fiscal years, and we will continue to manage our business as efficiently as possible consistent with providing safe, reliable and cost effective services to our customers.

Financial Strength and Flexibility.Flexibility – In order to profitablyprudently fund our Company’s investment in growth and our ongoing capital needs, we have executed our financing programs to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings.ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. In March 2012,January 2015, we initiatedestablished an at-the-market (ATM) equity sales program, including a forward sales component, under our effective shelf registration statement. The timing and volume of sales under this program cannot be predicted with certainty and may be affected by factors outside our control, but will not exceed an aggregate of $170 million from the period beginning January 2015 through the end of fiscal 2016. We continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs. We accomplished the following in fiscal year 2015:


In September 2015, we issued $150 million of ten-year, unsecured senior notes, receiving net proceeds of $148.9 million.

24


In October 2015, we issued 1.5 million shares under our ATM equity sales program under the forward sales agreements (FSAs), receiving proceeds of $54.1 million.

For further information on these transactions, see Note 5 and Note 7 to the consolidated financial statements in this Form 10-K and the following discussion of "Cash Flows from Financing Activities."

Managing Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have adequate and reliable supplies of competitively priced natural gas to meet the needs of our utility customers. In order to provide additional diversification, reliability and gas cost benefits to our customers, we have long-term supply and capacity contracts to buy and transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These new long-term sources of supply became available in late 2015 with the partial completion of the Williams – Transco Leidy Southeast expansion project and its Virginia Southside expansion project. In October 2014, we signed a long-term pipeline capacity precedent agreement under the Atlantic Coast Pipeline, LLC (ACP) project to source additional gas supplies from diverse gas supply basins in central West Virginia that are anticipated to be available for the winter 2018 – 2019 season.

Customer Growth – We have added increasing numbers of customers in our service areas each year over our last three fiscal years. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas resulted in growth in both the residential new construction and commercial markets. Growth in residential conversion and industrial markets decreased slightly, reflecting a longer sales cycle for conversions and a decline in readily available opportunities for industrial conversions. Overall, total residential and commercial customers increased in 2015 compared to 2014 and 2013, as presented below.
        Percent Change
        2015 vs. 2014 vs.
  2015 2014 2013 2014 2013
Residential new home construction 12,436
 11,659
 10,299
 6.7 % 13.2 %
Residential conversion 2,789
 2,814
 2,463
 (0.9)% 14.3 %
Commercial 1,780
 1,763
 1,512
 1.0 % 16.6 %
Industrial 12
 15
 19
 (20.0)% (21.1)%
  Total new customers 17,017
 16,251
 14,293
 4.7 % 13.7 %

Overall, total net customers billed increased 2% as compared to 2014.

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

With significant capital costs incurred under our ongoing system integrity programs, we have IMR regulatory mechanisms in North Carolina and Tennessee to separately track and recover certain costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity programs, as well as additional state safety and integrity requirements in Tennessee. The IMR orders by jurisdiction and the amount reflected in "Operating Revenues" in the Consolidated Statements of Comprehensive Income for 2015 is backstoppedsummarized below:

25


In millionsNorth Carolina Tennessee
Incremental annual margin revenue - 2014 IMR filing$1.0
(1) 
$13.1
Incremental annual margin revenue - 2015 IMR filing24.4
(1) 
6.5
Total cumulative incremental annual margin revenue in 2015 (2)
$25.4
(1) 
$19.6
    
Amounts recorded as revenues during fiscal year 2015$17.1
 $18.2
(1) Amounts are adjusted to reflect the 2015 IMR settlement agreement approved by the NCUC in November. For further information on the IMR settlement agreement, see Note 3 to the consolidated financial statements in this Form 10-K.
(2) IMR recovery period in both jurisdictions does not align with our fiscal year. For further information on those periods, see Note 3 to the consolidated financial statements in this Form 10-K.

We completed pipeline expansion projects in recent years that provide natural gas delivery service to new power generation facilities in our market area. We currently provide service to 25 power generation customer accounts. See the discussion of our forecasted capital investments in “Cash Flows from Investing Activities” in this Form 10-K.

Sustainable Business Practices – In February 2015, the winter weather throughout our service area was the coldest in 37 years. During this month, we experienced a record customer volume sendout for our 65-year history, with February 19, 2015 as a new, single-day volume sendout record of 2.6 million dekatherms. Our ability to provide safe and reliable natural gas service under these operating conditions was due to our ongoing investments in our pipeline delivery system through our system expansion and pipeline integrity management programs. Our review and implementation of our gas supply acquisition strategy ensures that we have adequate and reliable supplies to meet the peak day needs of our utility customers. We evaluate ongoing cold weather conditions and corresponding customer consumption patterns, as well as historical winter weather over the past 40 years, in developing our peak day requirements.

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

Proposed Acquisition by our syndicated revolving credit facility for a combined borrowing capacity of $650 million. Also in March 2012,Duke Energy – On October 24, 2015, we entered into an agreementa Merger Agreement with Duke Energy and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provides for the Acquisition by merging the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy. At the effective time of the Acquisition, subject to issue $300 millionreceipt of senior unsecured long-term debtrequired shareholder and regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. For further information on the Acquisition, see Item 1A. Risk Factors, "Forward Looking Statements" in Item 7, and Note 2 and Note 16 to the consolidated financial statements in this Form 10-K. In the Merger Agreement, we agreed to covenants affecting the conduct of our business between the date of the Merger Agreement and the effective date of the Acquisition.

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

On December 14, 2015, we filed a private placement with a blended interest rate of 3.54%. We issued $100 million on July 16, 2012 and $200 million on October 15, 2012 with the proceeds used to repay short-term debt incurred in part for funding of capital expenditures. Both issuances will mature on July 16, 2027. In addition to these debt issuances during this fiscal year, we have an open shelf registration fileddefinitive proxy statement with the SEC to notify our shareholders of a special meeting to be held on January 22, 2016 to vote on the Acquisition of Piedmont by Duke Energy. We and Duke Energy have filed notification and report forms under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In December 2015, the Federal Trade Commission granted antitrust approval of the Acquisition.


26


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 June 2011 thatSouthStar. GNGC’s election to purchase our entire 15% interest in SouthStar is available for future issuancessubject to and effective with the consummation of debt or equity.

On October 1, 2012,the Acquisition.


Strategy and Focus Areas

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 renegotiatedbelieve are the inherent advantages of natural gas compared to other types of energy. Our seven foundational strategic priorities are as follows:
Promote the benefits of natural gas,
Expand our core natural gas and extendedcomplementary energy-related businesses to enhance shareholder value,
Be the maturityenergy service provider of choice,
Achieve excellence in customer service every time,
Preserve financial strength and flexibility,
Execute sustainable business practices, and
Enhance our healthy, high performance culture.

With a continued focus on these priorities, we believe we will enhance long-term shareholder value. For a full discussion of our syndicated revolving credit facility to further take advantage of favorable borrowing termsstrategy and reductionsfocus areas, see Item 1. Business in our borrowing costs. This amended revolving credit facility extended our term to October 1, 2017 and continues to include the CP program in our borrowing capacity of $650 million with an option to request an increase of our capacity to $850 million. We anticipate annual savings of approximately $800,000 from lower unused fees and amortization of debt issuance costs over the life of the new agreement.

this Form 10-K.


Additional information on operating results for the years ended October 31, 2012, 20112015, 2014 and 20102013 follows.


Results of Operations

Comprehensive Income Statement Components  
               Percent Change 
               2012 vs.  2011 vs. 
In thousands except per share amounts  

2012

   

2011

   

2010

   2011  2010 

Operating Revenues

    $  1,122,780      $  1,433,905      $  1,552,295     (21.7)%   (7.6)% 

Cost of Gas

   547,334     860,266     999,703     (36.4)%   (13.9)% 
  

 

 

   

 

 

   

 

 

    

  Margin

   575,446     573,639     552,592     0.3%   3.8% 
  

 

 

   

 

 

   

 

 

    

Operations and Maintenance

   242,599     225,351     219,829     7.7%   2.5% 

Depreciation

   103,192     102,829     98,494     0.4%   4.4% 

General Taxes

   34,831     38,380     33,909     (9.2)%   13.2% 

Utility Income Taxes

   69,101     64,068     62,082     7.9%   3.2% 
  

 

 

   

 

 

   

 

 

    

  Total Operating Expenses

   449,723     430,628     414,314     4.4%   3.9% 
  

 

 

   

 

 

   

 

 

    

Operating Income

   125,723     143,011     138,278     (12.1)%   3.4% 

Other Income (Expense), net of tax

   14,221     14,549     47,387     (2.3)%   (69.3)% 

Utility Interest Charges

   20,097     43,992     43,711     (54.3)%   0.6% 
  

 

 

   

 

 

   

 

 

    

Net Income

    $119,847      $113,568      $141,954     5.5%   (20.0)% 
  

 

 

   

 

 

   

 

 

    

Average Shares of Common Stock:

         

  Basic

   71,977     72,056     72,275     (0.1)%   (0.3)% 

  Diluted

   72,278     72,266     72,525     -%   (0.4)% 

Earnings per Share of Common Stock:

         

  Basic

    $1.67      $1.58      $1.96     5.7%   (19.4)% 

  Diluted

    $1.66      $1.57      $1.96     5.7%   (19.9)% 

Margin by Customer Class  

In thousands

  

2012

  

2011

  

2010

 

Sales and Transportation:

          

Residential

    $321,056     56%  $319,675     56%  $316,368     57% 

Commercial

   150,306     26%   150,681     26%   148,884     27% 

Industrial

   46,993     8%   47,176     8%   44,078     8% 

Power Generation

   32,289     6%   23,970     4%   17,384     3% 

For Resale

   7,465     1%   8,550     2%   10,446     2% 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

   

 

 

 

Total

   558,109     97%   550,052     96%   537,160     97% 

Secondary Market Sales

   9,681     2%   14,016     2%   10,702     2% 

Miscellaneous

   7,656     1%   9,571     2%   4,730     1% 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

   

 

 

 

Total

    $      575,446       100%    $      573,639      100%    $      552,592       100% 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

   

 

 

 

Gas Deliveries, Customers, Weather Statistics and Number of Employees

            Percent Change
            2012 vs.  2011 vs.
   

2012

  

2011

  

2010

  

2011

  

2010

Deliveries in Dekatherms (in thousands):

               

Sales Volumes

    82,087     104,740     105,583     (21.6)%     (0.8)% 

Transportation Volumes

    242,213     175,021     147,032     38.4 %     19.0 % 
                               

Throughput

    324,300     279,761     252,615     15.9 %     10.8 % 
                               

Secondary Market Volumes

    48,373     48,835     46,823     (0.9)%     4.3 % 
                               

Customers Billed (at period end)

    969,239     958,307     946,785     1.1 %     1.2 % 

Gross Residential and Commercial Customer Additions

    13,274     10,522     10,975     26.2 %     (4.1)% 

Degree Days

               

Actual

    2,668     3,662     3,535     (27.1)%     3.6 % 

Normal

    3,310     3,318     3,321     (0.2)%     (0.1)% 

Percent (warmer) colder than normal

    (19.4)%     10.4 %     6.4 %     n/a     n/a 
                               

Number of Employees (at period end)

    1,752     1,782     1,788     (1.7)%     (0.3)% 
                               

Net Income

2012 compared to 2011:

Net income increased $6.3 million in 2012 compared with 2011 primarily due to the following changes, which increased net income:

$23.9 million decrease in utility interest charges.
$3.5 million decrease in general taxes.
$1.8 million increase in margin (operating revenues less cost of gas).

These changes were partially offset by the following changes, which decreased net income:

$17.2 million increase in operations and maintenance expenses.
$5.9 million increase in income taxes.

2011 compared to 2010:

Net income decreased $28.4 million in 2011 compared with 2010 primarily due to the following changes, which decreased net income:

$49.7 million decrease due to a gain on the sale of an interest in an equity method investment in the prior year.
$5.5 million increase in operations and maintenance expenses.
$4.8 million decrease in income from equity method investments.
$4.5 million increase in general taxes.
$4.3 million increase in depreciation.
$.6 million increase in non-operating expense.
$.5 million increase in charitable contributions.

These changes were partially offset by the following changes, which increased net income:

$21 million increase in margin.
$19.6 million decrease in income taxes.
$1.1 million increase in non-operating income.

Operating Revenues


Changes in operating revenues for 20122015 and 20112014 compared with the same prior periods are presented below.

Changes in Operating Revenues - Increase (Decrease)
2012 vs.

In millions

2011

Residential and commercial customers

$        (275.4)

Industrial customers

(9.8)

Power generation customers

7.1

Secondary market

(104.4)

Margin decoupling mechanism

53.7

WNA mechanisms

18.2

Other

(.5)

Total

$(311.1)

2012

Changes in Operating Revenue - Increase (Decrease)
   2015 vs. 2014 vs.
In millions 2014 2013
Residential and commercial customers $(85.2) $201.5
Industrial customers (9.6) 1.4
Power generation customers (0.3) 21.8
Secondary market (35.2) 5.4
Margin decoupling mechanism 6.4
 (39.4)
WNA mechanisms 1.6
 (11.4)
IMR mechanisms 24.6
 10.7
Other (0.6) 1.8
Total $(98.3) $191.8

2015 compared to 2011:

2014:
Residential and commercial customers – the decrease is primarily due to lower consumption from warmer weather and lower wholesale gas costs passed through in rates.to customers and lower consumption from warmer weather, slightly offset by customer growth.

Industrial customers – the decrease is primarily due to lower consumption and lower wholesale gas costs passed through to sales customers.customers and decreased transportation revenues, slightly offset by increased revenue on special contracts.

Power generation customers – the increasedecrease is primarily due to increased transportation services.certain annual contract rate adjustments.

Secondary market – the decrease is due to lower secondary market margins in the wholesale market.margin sales prices. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements andthat are part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.


27


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

WNAWeather normalization adjustment (WNA) mechanisms – the increase is due to warmer weather in South Carolina and Tennessee.

2011Tennessee, as compared to 2010:

Operating revenuesthe prior period. As discussed in 2011 decreased $118.4 million“Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.

IMR mechanisms – the increase is due to incremental IMR rate adjustments in North Carolina and Tennessee. The North Carolina and Tennessee IMR mechanisms were effective February 1, 2014 and January 1, 2014, respectively.

2014 compared with 2010to 2013:
Residential and commercial customers – the increase is primarily due to the following decreases:

$150.8 million of lowerhigher consumption from colder weather, higher wholesale gas costs passed through to sales customers.customers and customer growth.
$1.1 millionIndustrial customers – the increase is primarily due to higher consumption from decreased revenues under the margin decoupling mechanism.

These decreases were partiallycolder weather and higher wholesale gas costs passed through to customers, slightly offset by decreased transportation revenues.

Power generation customers – the following increases:

$19.8 million from higher revenues in secondary market transactionsincrease is primarily due to increased activitytransportation services.
Secondary market – the increase is due to higher margin sales related to sustained colder-than-normal weather and gas costs.increased wholesale market volatility.
$5.8 million from an increaseMargin decoupling mechanism – the decrease is primarily related to colder weather in volumes delivered to transportation customers.North Carolina.
$3.9 million from increased revenues under the WNA mechanisms – the decrease is due to colder weather in South Carolina and Tennessee.

IMR mechanisms – the increase is due to the IMR rate adjustments in Tennessee effective January 1, 2014 and North Carolina effective February 1, 2014.

Cost of Gas


Changes in cost of gas for 20122015 and 20112014 compared with the same prior periods are presented below.

Changes in Cost of Gas - Increase (Decrease)  
    2012 vs.   2011 vs. 

In millions

  2011   2010 

Commodity gas costs passed through to sales customers

  $        (194.3)    $(80.5)  

Commodity gas costs in secondary market transactions

   (100.1)     16.5  

Pipeline demand charges

   (7.0)     9.0  

Regulatory approved gas cost mechanisms

   (11.5)     (83.2)  

Other

   -      (1.2)  
  

 

 

   

 

 

 

Total

  $(312.9)    $        (139.4)  
  

 

 

   

 

 

 

2012

Changes in Cost of Gas - Increase (Decrease)
  2015 vs. 2014 vs.
In millions 2014 2013
Commodity gas costs passed through to sales customers $(125.8) $137.5
Commodity gas costs in secondary market transactions (31.0) (11.0)
Pipeline demand charges (13.1) (7.1)
Regulatory approved gas cost mechanisms 34.5
 3.6
Total $(135.4) $123.0

2015 compared to 2011:

2014:
Commodity gas costs passed through to sales customers – the decrease is primarily due to lower volumes sold due to warmer weather and lower wholesale gas costs passed through to sales customers.customers, slightly offset by customer growth.

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

Pipeline demand charges – the decrease is primarily due to changingincreased capacity release revenues and decreased demand costs, slightly offset by decreased asset manager agreement terms.payments.

Regulatory approved gas cost mechanisms – decreasethe increase is primarily due to the effects of variousan increase in commodity cost and demand true-ups, partially offset by other regulatory true-up mechanisms.

2011


2014 compared to 2010:

2013:
Commodity gas costs passed through to sales customers – the decreaseincrease is primarily due to lowerhigher volumes sold due to colder weather and higher wholesale gas costs passed through to sales customers.

Commodity gas costs in secondary market transactions – the increasedecrease is primarily due to increaseddecreased activity, andpartially offset by higher average wholesale gas costs.

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

28


Regulatory approved gas cost mechanisms – the increase is primarily due to timing of asset manager agreement terms.

Regulatory approved gasdemand cost mechanisms – the decrease is primarily due to commodity gas cost true ups.true-ups, slightly offset by other regulatory mechanisms.


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

this Form 10-K.


Margin


Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory passthroughpass through of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 36%35% of revenues for the year ended October 31, 2012,2015 and our41% for the years ended October 31, 2014 and 2013. Our pipeline transportation and storage costs accounted for 11%.

10% for the years ended October 31, 2015 and 2014 and 12% for the year ended October 31, 2013.


In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers under terms and conditions of service that are competitive with alternative energy sources and allow such service to be provided without general subsidies from Piedmont’s other system customers.


Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These include WNAregulatory mechanisms in Tennessee and South Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, the gas supply Incentive Plan in Tennessee, the margin decoupling mechanism in North Carolina, negotiated loss treatment in North Carolina and South Carolina and the recovery of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

by jurisdiction are presented below.

Regulatory MechanismNorth CarolinaSouth CarolinaTennessee
WNA mechanism*XX
Margin decoupling mechanism *X
Natural gas rate stabilization mechanismX
Secondary market programs **XXX
Incentive plan for gas supply **X
IMR mechanismXX
Negotiated margin loss treatmentXX
Uncollectible gas cost recoveryXXX
  * Residential and commercial customers only.
** In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million.

Changes in margin for 20122015 and 20112014 compared with the same prior periods are presented below.

Changes in Margin - Increase (Decrease)  
   2012 vs.   2011 vs. 

In millions

  2011   2010 

Residential and commercial customers

  $1.0    $5.1  

Industrial customers

   (1.3)     1.2  

Power generation customers

   8.3     6.6  

Secondary market activity

   (4.3)     3.3  

Net gas cost adjustments

           (1.9)     4.8  
  

 

 

   

 

 

 

  Total

  $1.8    $        21.0  
  

 

 

   

 

 

 

2012

Changes in Margin - Increase (Decrease)
 
2015 vs.
2014 vs.
In millions
2014
2013
Residential and commercial customers
$39.9

$31.2
Industrial customers
2.7

—
Power generation customers (0.3) 21.3
Secondary market activity (4.3) 16.4
Net gas cost adjustments (0.9) (0.2)
Total $37.1
 $68.7

29



2015 compared to 2011:

2014:
Residential and commercial customers – the increase is primarily due to incremental IMR rate adjustments discussed above, as well as the general rate increase in North Carolina effective January 1, 2014, and customer growth in all three states, partially offset by decreased volumes delivered in South Carolina and Tennessee due to warmer weather.
Industrial customers – the increase is due to incremental IMR rate adjustments discussed above, increased margin on special contracts and higher consumption in the industrial market.
Power generation customers – the decrease is primarily due to certain annual contract rate adjustments.
Secondary market activity – the decrease is primarily due to lower margin sales.

2014 compared to 2013:
Residential and commercial customers – the increase is primarily due to the general rate increase in TennesseeNorth Carolina effective MarchJanuary 1, 2012 and2014, the IMR rate adjustments discussed above, customer growth in all three states offset by lower consumptionand increased volumes delivered in Tennessee and South Carolina where the WNA mechanisms did not perfectly adjust for significantly warmer-than-normal weather.

Industrial customers – the decrease is primarilyand Tennessee due to lower consumption in the industrial market from warmercolder weather.

Power generation customers – the increase is due to increased transportation services.

Secondary market activity – the decrease is due to less wholesale natural gas price volatility.

2011 compared to 2010:

Residential and commercial customers – the increase is primarily due to growth in those markets.increased transportation services.

Industrial customersSecondary market activity – the increase is primarily due to increases in volumes and services to industrial customers.

Power generation customers – the increase is due to increases in volumes and services to power generation customers.

Secondary market activity – the increase is duehigher margin sales related to increased activitywholesale market volatility and margins.sustained colder-than-normal weather.


Operations and Maintenance Expenses


Changes in operations and maintenanceO&M expenses for 20122015 and 20112014 compared with the same prior periods are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)

In millions

        2012 vs.      
2011		         2011 vs.      
2010		 

Employee benefits

  $7.1     $.8   

Payroll

   4.0      1.1   

Contract labor

   3.7      (.4)   

Regulatory

   1.3      (.9)   

Transportation

   .8      2.5   

Materials

   -       1.5   

Other

   .3      .9   
  

 

 

   

 

 

 

  Total

  $17.2     $5.5   
  

 

 

   

 

 

 

2012

Changes in Operations and Maintenance Expenses - Increase (Decrease)
  2015 vs. 2014 vs.
In millions 2014 2013
Contract labor $13.4
 $1.9
Payroll 7.9
 9.6
Employee benefits 2.5
 (0.3)
Regulatory 1.0
 4.2
Bad debt (1.8) 2.1
Other 0.6
 0.3
Total $23.6
 $17.8

2015 compared to 2011:

2014:
Employee benefits – the increase is primarily due to increases in medical coverage premiums and defined benefit pension costs and the absence of pension plan funding and a regulatory pension deferral in the current year.

Payroll – the increase is due to increases in incentive plan accruals.

Contract labor – the increase is primarily due to $8.6 million of expenses related to the Acquisition, increased process improvement projects and pipeline integrity maintenance and safety programs.

Payroll – the increase is primarily due to additional employees, higher incentive plan accruals of $7.2 million from a higher stock price at October 31 related to the announcement of the Acquisition and employee overtime.
Employee Benefits – the increase is primarily due to a lower regulatory pension deferral in Tennessee in the current period related to lower funding of the defined benefit plan in 2015 versus 2014.
Regulatory – the increase is primarily due increased amortization of regulatory assets with approved amortization amounts established in the North Carolina general rate proceeding, effective January 1, 2014.
Bad debt – the decrease is primarily due lower projected charge-offs than the prior period.

2014 compared to 2013:
Contract labor – the increase is primarily due to increased call volume and collection efforts for customer receivables resulting from the colder winter, increased process improvement projects and pipeline integrity maintenance and safety programs.
Payroll – the increase is primarily due to additional employees, employee overtime because of colder-than-normal winter weather and incentive plan accruals.

30


Regulatory – the increase is primarily due to increased amortization of regulatory assets that began with approved amortization amounts established in the TennesseeNorth Carolina general rate increase.

2011 compared to 2010:

Payroll –proceeding, effective January 1, 2014, and an increase in the increase is primarily due to merit increases, partially offset by a decrease in long-term incentive plan accruals.

Transportation – the increase is primarilyNorth Carolina regulatory fee due to increased fuel costs and new vehicles placed into service in 2011.revenues.

Materials – the increase is primarily due to the implementation of an integrated supply chain process in 2011.

Regulatory – the decrease is primarily due to the cessation of the amortization of certain regulatory assets in South Carolina.

OtherBad debt – the increase is primarily due to a recovery disallowancehigher level of some prior years’ franchise fees in one of our jurisdictionsnet charge-offs from customer receivables due to the colder weather experienced this past winter and increased accruals to reflect higher bank fees from increased activity and unused amounts of the revolving syndicated credit facility, partially offset by decreases in insurance, utility and advertising expenses.aging receivables.


Depreciation


Depreciation expense increased from $98.5$112.2 million to $103.2$128.7 million over the three-year period 20102013 to 20122015 primarily due to increases in plant in service, particularly with the addition ofrelated to major pipeline and compression facilities usedadditions to provide service toserve new power generation customers.

customers and transmission integrity investments.


General Taxes


Changes in general taxes for 20122015 and 20112014 compared with the same prior periods are presented below.

Changes in General Taxes Expense - Increase (Decrease)

In millions

        2012 vs.      
2011		         2011 vs.      
2010		 

Sales tax accrual

    $(2.5)       $  2.5   

Gross receipts tax

   (.8)      (.1)   

Property taxes

   .4      1.8   

Other

   (.6)      .3   
  

 

 

   

 

 

 

Total

    $  (3.5)       $4.5   
  

 

 

   

 

 

 

2012

Changes in General Taxes - Increase (Decrease)
  2015 vs. 2014 vs.
In millions 2014 2013
Property taxes $3.1
 $1.5
Franchise taxes 1.3
 0.9
Other 0.4
 0.3
  Total $4.8
 $2.7

2015 compared to 2011:

with 2014:
Sales tax accrual – the decrease is primarily due to the accrual of a liability of $2.7 million in 2011 for sales
Property taxes on certain customer accounts.

Gross receipts tax – the decrease is due to lower accruals in the current period for Tennessee gross receipts tax as a result of lower revenues.

2011 compared to 2010:

Sales tax accrual – the increase is primarily due to increases in property.
Franchise taxes – the accrual of a liability of $2.7 millionincrease is primarily due to changes in 2011 for sales taxes on certain customer accounts.North Carolina tax laws and increases in property.

2014 compared with 2013:

Property taxes – the increase is relatedprimarily due to a larger property base and property value reassessments by taxing authorities.increases in property.

Franchise taxes – the increase is primarily due to increases in property.

Other Income (Expense)


Other Income (Expense) is comprised of income from equity method investments, gain on sale of interest in equity method investment, non-operating income, charitable contributions, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, home service warranty programs, subsidiary operations, interest income and other miscellaneous income.

2012 compared with 2011:

The primary change to Non-operating expense is comprised of charitable contributions and miscellaneous expenses.



31


Changes in Other Income (Expense) in 2012 compared with 2011 was income from equity method investments, primarily from SouthStar Energy Services LLC (SouthStar)for 2015 and Cardinal Pipeline Company, L.L.C. (Cardinal). All other changes for the year ended October 31, 2012 compared with 2011 were insignificant.

Income from equity method investments from SouthStar decreased $1.4 million in 2012 primarily due to lower customer usage related to warmer-than-normal weather, net of weather derivatives, partially offset by lower transportation and gas costs and higher commercial asset optimization.

The decrease from SouthStar was partially offset by a $1 million increase in earnings from Cardinal primarily due to higher capitalized interest from the allowance for funds used during construction (AFUDC) and increased revenues as a result of the expansion project to serve Progress Energy Carolinas’ (PEC) Wayne County generation project, partially offset by higher depreciation and operating expenses.

2011 compared with 2010:

The primary changes to Other Income (Expense) in 2011 compared with 2010 were in income from equity method investments, the gain on the sale of half of our ownership interest in SouthStar in 2010 and non-operating income discussed below. All other changes were insignificant.

In January 2010, we sold half of our 30% membership interest in SouthStar to the other member of the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax gain on the sale was $49.7 million. The after-tax gain was $30.3 million, or $.42 per diluted earnings per share, for 2010.

Income from equity method investments decreased $4.8 million in 2011 compared with 2010 primarily due to a decrease of $4.5 million in earnings from SouthStar due to a full year of recording earnings at the lower 15% ownership interest and unfavorable changes in SouthStar’s average customer usage due to warmer weather and retail pricing plan mix, partially offset by decreases in operating expenses.

Non-operating income increased $1.1 million in 2011 compared with 2010 primarily due to increased revenues under our non-regulated home service warranty program, interest earned on installment loans made to our natural gas customers under our third party financing program and a state tax refund on behalf of a joint venture.

Utility Interest Charges

Changes in utility interest charges for 2012 and 20112014 compared with the same prior periods are presented below.

Changes in Utility Interest Charges - Increase (Decrease)

In millions

        2012 vs.      
2011		         2011 vs.      
2010		 

Borrowed AFUDC

  $(16.6)    $1.4  

Interest expense on long-term debt

   (4.6)     (6.6)  

Regulatory interest expense, net

   (3.8)     3.7  

Interest expense on short-term debt

   .8     1.1  

Other

   .3     .7  
  

 

 

   

 

 

 

  Total

  $(23.9)    $.3  
  

 

 

   

 

 

 

2012

Changes in Other Income (Expense) - Increase (Decrease) to Income
  2015 vs. 2014 vs.
In millions 2014 2013
Income from equity method investments:    
  Constitution $3.4
 $1.7
  SouthStar (1.0) 5.0
  Other (0.7) —
    Total 1.7
 6.7
Non-operating income 1.3
 (1.0)
Non-operating expense 0.6
 0.8
Income Taxes (1.6) (3.0)
  Total $2.0
 $3.5

2015 compared to 2011:

with 2014:
Borrowed AFUDC
Income from equity method investments from Constitution – the decreaseincrease is primarily due to an increase inhigher capitalized interest primarily as a result ofassociated with increased project construction expenditures.

Interest expensecapital expenditures on long-term debtthe project.
Income from equity method investments from SouthStar – the decrease is primarily due to a lower value of hedged derivatives and less usage in Georgia and Illinois due to warmer weather, partially offset by favorable margins in Georgia, Illinois and Ohio.
Non-operating income – the replacementincrease is primarily due to the $2 million write-off in 2014 of an investment that was accounted for on the cost basis as discussed below.

2014 compared with 2013:

Income from equity method investments from Constitution – the increase is primarily due to higher rate debtcapitalized interest associated with lower rate debt.increased capital expenditures on the project.

Regulatory interest expense, netIncome from equity method investments from SouthStar – the increase is primarily due to the expansion of the business into Illinois markets beginning in September 2013, and favorable weather and customer usage in Georgia, partially offset by higher general and administrative expenses. For further information on the contribution of the Illinois business to SouthStar and our cash contribution in our equity method investment, see Note 13 to the consolidated financial statements in this Form 10-K.
Non-operating income – the decrease is primarily due to a $2 million write-off of an increaseinvestment that we accounted for on the cost basis. This investment was presented in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets.

Utility Interest Charges

Changes in utility interest charged on amounts due from customers, which is recorded as interest income.charges for 2015 and 2014 compared with the same prior periods are presented below.

Changes in Utility Interest Charges - Increase (Decrease)
  2015 vs. 2014 vs.
In millions 2014 2013
Interest expense on long-term debt $9.1
 $7.4
Borrowed AFUDC 5.3
 14.5
Regulatory interest expense, net (0.5) 8.1
Other —
 (0.3)
Total $13.9
 $29.7


32


2015 compared to 2014:

Interest expense on short-termlong-term debt – the increase is primarily due to higher balancesamounts of debt outstanding duringin the current periodperiod.
Borrowed allowance for funds used for utility capital expenditures and other corporate purposes at interest rates that are 28 basis points lower than the prior year period.

2011 compared to 2010:

Borrowed AFUDCduring construction (AFUDC) – the increase in interest expense is due to a decrease in capitalized interest primarily due to the closingon a lower base of approximately half of our construction expenditures to utility plant in service in the first halfcurrent period resulting from the timing of the current year asprojects being placed into service.

2014 compared with the prior year.to 2013:

Interest expense on long-term debt – the decrease is primarily due to lower amounts of debt outstanding.

Regulatory interest expense, net – the increase in net interest expense is primarily due to a decrease in interest charged on amounts due from customers, which earned a carrying charge, as those balances were lower in the current period.

Interest expense on short-term debt – the increase is primarily due to averagehigher amounts of debt outstanding in the current period.
Borrowed AFUDC – the increase is due to a decrease in capitalized interest rates duringon a lower base of construction expenditures in the current period that were 44 basis points higher thanresulting from the timing of projects being placed into service.
Regulatory interest expense, net – the increase is primarily due to the recording of interest expense on amounts due to customers compared with the recording of interest income in the prior year periodon amounts due to higher spreads under the new revolving syndicated credit facility that was put into place in January 2011.from customers.


Financial Condition and Liquidity


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


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

For information on the issuance of long-term debt and equity securities, see Note 5 and Note 7, respectively, to the consolidated financial statements in this Form 10-K.

To meet our capital and liquidity requirements outside of the long-term capital market,markets, we rely on certain resources, including cash flows from operating activities, cash generated from our investments in joint ventures and short-term debt. Operating activities primarily providesprovide the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs.

Short-term debt is vital to meet our working capital needs, such as our seasonal requirements for gas supply, pipeline capacity, payment of dividends, general corporate liquidity, a portion of our capital expenditures and approved investments. We rely on short-term debt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support ourinvestments in customer growth, pipeline integrity programs, system infrastructure and the growth incontributions to our customer base.

joint ventures.


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


We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, constructioncapital expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions common share repurchases and other cash needs. Our ability to satisfy all of these requirements is dependent

upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by reduced tax payments due to the extensiongeneration of federal net operating loss (NOL) carryforwards resulting from bonus depreciation, legislation.as well as the ability to recover and earn on investments


33


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

Activities” in this Form 10-K.


Short-Term Debt. In October 2012, we amended and restated the agreement underlying our $650 We have an $850 million three-year revolving syndicated credit facility. The amended and restated agreement provides for a five-year revolving syndicated credit facility that expires in October 2017 and has an option to request an expansion of up to $850 million.2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $650 million.amount. The five-year revolving syndicated credit facility continuescontains normal and customary financial covenants.

On December 14, 2015, we entered into an agreement with the lenders under our existing $850 million five-year revolving syndicated credit facility to haveamend and extend the same financial covenants. We anticipate annual savingsfacility. The amended facility has substantially similar terms to our existing facility and has an option to request an expansion of approximately $800,000 from lower unused fees andfinancing commitments by an additional $200 million. The amended facility extended amortizationthe maturity of debt issuance costs underour facility to December 14, 2020. The amended facility expressly permits the amended and restated revolvingAcquisition by Duke Energy. The CP program will continue to be backstopped by the new credit facility.

In March 2012, we established a $650


We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650$850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.


We did not have any borrowings under the revolving syndicated credit facility for the year ended October 31, 2015. Highlights for our short-term debt under our CP program as of October 31, 20122015 and 20112014 and for the quarter and year ended October 31, 20122015 and 20112014 are presented below.

In thousands

  Credit
         Facility        		        Commercial      
Paper		  Total
    Borrowings     		 

2012

    

End of period (October 31, 2012):

    

Amount outstanding

      $-       $365,000      $365,000 

Weighted average interest rate

   -%   .42%   .42% 

During the period (August 1, 2012 - October 31, 2012):

    

Average amount outstanding

      $-       $444,300      $444,300 

Minimum amount outstanding

      $-       $335,000      $335,000 

Maximum amount outstanding

      $-       $535,000      $535,000 

Minimum interest rate

   -%   .30%   .30% 

Maximum interest rate

   -%   .45%   .45% 

Weighted average interest rate

   -%   .39%   .39% 

Maximum amount outstanding during the month:

    

August 2012

      $-       $450,000      $450,000 

September 2012

   -    500,000   500,000 

October 2012

   -    535,000   535,000 

During the year ended October 31, 2012:

    

Average amount outstanding

      $144,700      $404,700      $416,300 

Minimum amount outstanding(1)

      $-       $-       $328,500 

Maximum amount outstanding(1)

      $475,500      $    535,000      $535,000 

Minimum interest rate(2)

   1.15%   .22%   .22% 

Maximum interest rate

   1.20%   .45%   1.20% 

Weighted average interest rate

   1.17%   .38%   .66% 

2011

    

End of period (October 31, 2011):

    

Amount outstanding

      $331,000      $-       $    331,000 

Weighted average interest rate

   1.15%   -%   1.15% 

During the period (August 1, 2011 - October 31, 2011):

  

  

Average amount outstanding

      $236,000      $-       $236,000 

Weighted average interest rate

   1.14%   -%   1.14% 

Maximum amount outstanding during the month:

    

August 2011

      $269,500      $-       $269,500 

September 2011

   288,500   -    288,500 

October 2011

   342,500   -    342,500 

During the year ended October 31, 2011:

    

Average amount outstanding

      $    203,500      $-       $203,500 

Weighted average interest rate

   .94%   -%   .94% 

Maximum amount outstanding

      $426,000      $-       $426,000 

(1) During March 2012, we were borrowing under both the credit facility and CP program for a portion of the month.

  

(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program.

  

In thousands 2015
End of period (October 31, 2015):  
Amount outstanding $340,000
Weighted average interest rate .22%
   
During the period (August 1, 2015 – October 31, 2015):  
Average amount outstanding $372,600
Minimum amount outstanding 290,000
Maximum amount outstanding 445,000
Minimum interest rate .16%
Maximum interest rate .25%
Weighted average interest rate .22%
   
Maximum amount outstanding during the month:  
August 2015 $430,000
September 2015 445,000
October 2015 380,000
   
During the year ended October 31, 2015:  
Average amount outstanding $361,100
Minimum amount outstanding 230,000
Maximum amount outstanding 580,000
Minimum interest rate .15%
Maximum interest rate .30%
Weighted average interest rate .21%


34


In thousands
2014
End of period (October 31, 2014):

Amount outstanding
$355,000
Weighted average interest rate
.17%
   
During the period (August 1, 2014 – October 31, 2014):

Average amount outstanding
$420,900
Minimum amount outstanding
275,000
Maximum amount outstanding
535,000
Minimum interest rate
.10%
Maximum interest rate
.25%
Weighted average interest rate
.17%



Maximum amount outstanding during the month:

August 2014
$525,000
September 2014
535,000
October 2014
355,000
   
During the year ended October 31, 2014:

Average amount outstanding
$441,500
Minimum amount outstanding
275,000
Maximum amount outstanding
625,000
Minimum interest rate
.10%
Maximum interest rate
.43%
Weighted average interest rate
.19%

As of October 31, 2012,2015, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $3.6$1.6 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31, 2012,2015, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $281.4$508.4 million.


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


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


Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers but may lead to conservation by customers in order to reduce their heating bills. Regulatory margin stabilizing and cost recovery mechanisms, such as decoupled tariffs and those that allow us to recover the gas cost

35


portion of bad debt expense, mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.

Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, are expected to mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. With the unusually warmer-than-normal winter of 2011-2012 together with lower natural gas prices this fiscal year, we have experienced lower levels of bad debt expense.


Net cash provided by operating activities was $304.5$371.6 million in 2012, $311.22015, $430.6 million in 20112014 and $360.5$313.2 million in 2010.2013. Net cash provided by operating activities reflects a $6.3$6.8 million increasedecrease in net income for 2012in 2015 compared with 20112014 primarily due to lowerhigher operating costs, costs resulting from the Acquisition and utility interest expensecharges, partially offset by higher operating costs in 2012.increased margin. The effect of changes in working capital on net cash provided by operating activities is described below:

Trade accounts receivable and unbilled utility revenues decreased $4.8$10.2 million in the current period primarily due to athe decrease in unbilled volumes and amounts billed to customers reflecting lower gas costs. Volumes sold to weather-sensitive residential and commercial customers decreased 21.4 million dekatherms as compared with the same prior period primarily due to 27.1%2.7% warmer weather during the current period. Total throughput increased 44.5 million dekatherms as compared with the same prior period, largely from 68.2 million dekatherms, or 81.6%, increased deliveries to power generation customers, partially offset by decreased sales to residential, commercial and industrial customers.
Net amounts due fromto customers increased $45.6decreased $16.8 million in the current period primarily due to the accrual of amounts due froma $45.5 million one-time bill credit to North Carolina customers under the North Carolinaand lower hedging costs, partially offset by deferred gas cost collections and refunds through rates, margin decoupling and South Carolina WNA tariff mechanisms.WNA.
Gas in storage decreased $18.5 million in the current period due to a decrease in the weighted average cost of gas and decreased volumes in storage.
Prepaid gas costs decreased $9$15.8 million in the current period primarily due to a decrease in the weighted average cost of gas andpurchased for injections, offset slightly by increased volumes of gas being made availablein storage.
Prepaid gas costs decreased $10.2 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for sale during the period.injections. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

Trade accounts payable increased$14.6 million in the current period primarily due to the timing of utility capital expenditures, partially offset by lower prices for natural gas purchases.

Primarily due to bonus depreciation, we generated federal NOLs in our tax years 2012, 2013 and 2014. We filed claims to carryback a portion of the NOLs to prior federal income tax returns. We recorded approximately $27 million in "Income taxes receivable" in "Current Assets" in the Consolidated Balance Sheets for refundable income taxes from the carryback of theses NOLs in 2014. We are currently under audit by the Internal Revenue Service for our 2012 tax year. Due to the timing of the audit, we reclassified $26 million of current refundable income taxes to “Income taxes receivable” in “Noncurrent Assets” in the Consolidated Balance Sheets from the carryback of these NOLs in 2015.

The Tax Increase Prevention Act of 2014 (the Act), enacted December 19, 2014, retroactively extended the 50% bonus depreciation that expired December 2013 for a year to December 2014. Under the Act, we were entitled to additional tax depreciation deductions for 2014. These additional deductions resulted in generating a federal NOL in 2014. We utilized tax NOL carryforwards to offset our taxable income in 2015. We anticipate that we will generate future taxable income sufficient to utilize tax carryforwards prior to the expiration of the carryforward period. For further information on tax carryforwards as of October 31, 2015, see Note 12 to the consolidated financial statements in this Form 10-K.

The Protecting Americans from Tax Hikes Act of 2015, enacted in December 2015, retroactively extends bonus depreciation that expired in December 2014. Under this legislation, qualified property placed in service during 2015 is eligible for 50% bonus depreciation. This retroactive extension of bonus depreciation will increase our federal NOLs as of October 31, 2015 by approximately $135 million.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA mechanismcustomers in Tennessee, effectiveSouth Carolina and in March 2012, was extended to the months of October through April for residential and commercial billings.customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee which includes the additional months of April and October 2012 in Tennessee, generated chargescredits to customers of $13.3$6.8 million and $8.4 million in 20122015 and credits2014, respectively, and charges of $4.9 million and $8.8$3 million in 2011 and 2010, respectively.2013. In Tennessee, adjustments are made directly to individual customer monthly bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Current“Regulatory Assets” or “Amounts due to customers” in “Current Liabilities”“Regulatory Liabilities,” as presented in Note 3 to the Consolidated Balance Sheetsconsolidated financial statements in this Form 10-K, for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin decoupling mechanism reduced margin by $27 million and $33.4 million in 2015 and 2014, respectively, and increased margin by $46.8$6 million in 2012 and reduced margin by $7 million and $5.9 million in 2011 and 2010, respectively.2013. Our gas costs are recoverable through PGApurchased gas adjustment (PGA) procedures and are not affected by the WNA or the margin decoupling mechanisms.

The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the Act), enacted in December 2010, extended the 50% bonus depreciation that expired December 2009 and temporarily increased bonus depreciation for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010-2014. Based on current capital projections and timelines, we are anticipating that bonus depreciation will reduce cash needed to pay federal income taxes during fiscal years 2010-2014 by $130-170 million as compared with cash tax needs prior to the Act. While reducing cash tax payments, bonus depreciation will increase deferred tax liabilities by a similar amount. Rate base generally consists of net utility plant in service less utility deferred income tax liabilities. Rate base upon which authorized revenue requirements are determined is expected to increase for the remainder of 2012, but less than if bonus depreciation had not been in effect.



36


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

The regulated utility competes with


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


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


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


Cash Flows from Investing Activities. Net cash used in investing activities was $549.3$478.4 million in 2012, $252.62015, $504.4 million in 20112014 and $128.6$663.5 million in 2010.2013. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures were $529.6$443.7 million in 20122015 as compared to $243.6$460.4 million in 2011,2014 primarily due to expending $284.3 millionlower spending on transmission integrity projects and $103.6 million, respectively, for the constructioncompletion of power generation service delivery projects.early phases of the work and asset management system. Gross utility capital expenditures were $199.1$460.4 million in 2010 with $52.32014 compared to $600 million of investments in plant2013 primarily due to servelower power generation customers.service delivery project expenditures and lower maintenance expenditures.


We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. We are increasingOur program supports our spendingsystem infrastructure, the growth in our customer base and large amounts for pipeline integrity, safety and compliance programs, andincluding systems and technology infrastructure to enhance our pipeline system and integrity. Our program primarily supports our system infrastructureintegrity through a comprehensive work and the growth in our customer base.asset management system. Significant utility construction expenditures are expected to meet long-termfor growth including growth in the power generation market,and system integrity and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed. To ensure safe pipeline operations, we are also focusing on new technology through the development

Detail of a new work and asset management system.

We anticipate makingour forecasted 2016 – 2018 utility capital expenditures, including AFUDC, in the range of $525 – $575 million inand our fiscal year 2013, including $75 - $85 million for the completion of the Sutton power generation delivery project and higher utility capital expenditures relatedcommitments to pipeline integrity, safety and compliance programs and systems and technology infrastructure. Our estimates of utility capital expenditures shown below for 2013 - 2015 include utility transmission pipeline integrity projects.fund equity method investments is presented below. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 45-50%50 – 60% in long-termtotal debt and 50-55%40 – 50% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to accelerated depreciation as well as bonus depreciation benefits. Additional detail for the anticipated capital expenditures follows.

In millions

  

2013

   

2014

   

2015

 

Utility

  $          450 - 490    $          275 - 325    $          275 - 325  

Sutton power generation project

   75 - 85     -     -  
  

 

 

   

 

 

   

 

 

 

Total forecasted capital expenditures

  $525 - 575    $275 - 325    $275 - 325  
  

 

 

   

 

 

   

 

 

 

In October 2009,depreciation.

In millions 2016 2017 2018
Customer growth and other $290
 $310
 $385
System integrity 270
 255
 210
Total forecasted utility capital expenditures 560
 $565
 595
Forecasted funding of construction in equity method investments 116
 104
 69
Total $676
 $669
 $664

During fiscal 2013, we reached an agreement with PEC, now a subsidiary of Duke Energy Corporation (DEC), to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. This required us to construct 38 miles of transmission pipeline along with additional compression facilities to provide service in June 2012. Our investment in the pipeline and compression facilities is supported by a long-term service agreement. We also executed an agreement with Cardinal to expand our firm capacity requirement on Cardinal to serve the PEC Wayne County site. This required Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million related to this system expansion from January 2011 through June 2012; our current fiscal year contributions related to this expansion were $3.6 million. Cardinal’s expansion service for the project was also placed into service in June 2012. In June 2012, due to Cardinal obtaining permanent financing on the expansion, we received $5.4 million as a partial return of our capital investment. For further information regarding this agreement, see Note 12 to the consolidated financial statements.

In April 2010, we reached another agreement with PEC to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement calls for us to construct approximately 130 miles of transmission pipeline along withand compression facilities to provide natural gas delivery service to the plant by June 2013, and oura Duke Energy Progress, Inc., (now a subsidiary of Duke Energy) power generation facility at their Sutton


37


site near Wilmington, North Carolina. Our investment in the pipeline and compression facilities iswas supported by a long-term service agreement.

Theagreement with fixed monthly payments.


Our Sutton project facilities will also createcreated cost effective expansion capacity that we will also use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. We anticipate thatIn 2015, a portionspecial contracts credit, representing the depreciation of investments under our power generation contracts, reduced the costIMR revenue requirement under the IMR mechanism.

In June 2014, we executed an agreement to construct approximately 1.5 miles of this project will be included in our North Carolina utility rate base because the facilities will enhance our abilitynatural gas transmission pipeline and associated compression to serve other North Carolina customers.

During fiscal 2011, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a PECDuke Energy’s W.S. Lee power generation facility locatednear Anderson, South Carolina. Our total investment is estimated to be $38 million, with expenditures occurring primarily in Richmond County, North Carolina. Duringour fiscal 2011, we also placed into serviceyear 2016, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas pipeline facilitiesservice agreement with fixed monthly charges and has a target in-service date of May 2017.


Also, in May 2015, we executed an agreement to construct a delivery station and associated compression to provide natural gas deliveryadditional service to a DECDuke Energy’s power generation facility locatedat their Sutton site as discussed above. Our total investment is estimated to be $13 million with expenditures occurring primarily in Rowan County, North Carolina. In December 2011, we placed into serviceour fiscal years 2016 and 2017, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas pipeline facilities to provide natural gas delivery service toagreement with fixed monthly charges and has a DEC power generation facility locatedtarget in-service date of June 2017.

We are invested as equity members in Rockingham County, North Carolina.

In January 2010, we sold half of our 30% membership interest in SouthStar to Georgia Natural Gas Company (GNGC) and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC. For further information regarding the sale, see Note 12 to the consolidated financial statements.

In November 2012, we entered into an agreement to become a 24% equity member of Constitution Pipeline Company, LLC, a Delaware limited liability company. The purpose of the joint venture is to construct and operate a 121 miletwo interstate natural gas pipeline and related facilities connecting gathering systemsprojects that are in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. The target in-service date is March 2015. We haveprocess of development. As a member of these limited liability companies, we are committed to fund an amountconstruction in proportion to our ownership interest for the development and construction of the new pipeline, which is estimated at $700 – 800 million. In November 2012, we made an initial contribution of $4.8 million, and we expect our total contributions will be an estimated $180 million through 2015 with approximately 90% of funding to occur during our fiscal 2014 and 2015 years.interests. For further information regarding this agreement,these investments, see Note 1213 to the consolidated financial statements.

statements in this Form 10-K.

 Constitution ACP
In millions(24% ownership interest) (10% ownership interest)
Our anticipated contributions for total projects costs$200.2
 $ 450 - 500
Anticipated in-service datefourth quarter of 2016
 late 2018
Our contributions:   
  For the year ended October 31, 201519.1
 10.6
  Over life of project to date72.7
 10.6

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

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $240$110.9 million in 2012, ($57.5)2015, $75.4 million in 20112014 and ($233.9)$356.3 million in 2010.2013. Funds are primarily provided from long-term debt securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP), and our employee stock purchase plan (ESPP) and bonus depreciation.. We may sell common stock and issue long-term debt when market and other conditions favor such long-term financing to maintain our target capital structure of 50-55%40 – 50% equity to total long-term capital. Funds are primarily used to finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program andwhen required to maintain target capital structure, pay quarterly dividends on our common stock.stock and for other general corporate purposes.


Outstanding debt under our syndicated revolving credit facility and CP program increaseddecreased from $331$355 million as of October 31, 20112014 to $365$340 million as of October 31, 20122015 primarily due to higher capital expenditures. Overnet proceeds received from the three-year period from 2010 to 2012,issuance of long-term debt and our short-term debt has included two revolving syndicated credit facilities. Our previouscommon stock. As discussed above in “Short-Term Debt” in “Financial Condition and Liquidity,” we amended and extended our existing $850 million five-year revolving syndicated credit facility, was replaced with our three-year revolving syndicated credit facility, which in October 2012 was amended and restated as a five-year revolving syndicated credit facility. Our unsecured CP program, which is backstoppedincluding an option to request an expansion of financing commitments by our credit facility, was established in March 2012.an additional $200 million. For further information on short-term debt, see Note 6 to the previous discussion of “Short-Term Debt”consolidated financial statements in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We have an open10-K.


In June 2014, we filed a combined debt and equity shelf registration filedstatement with the SEC in July 2011 that is available for future use.became effective on June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration up to $1 billion during its three-

38


year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate

purposes, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries and for repurchases of shares of our common stock. purposes. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment gradeinvestment-grade securities. We anticipate issuing $250 million


Under this shelf registration statement, we established an ATM equity sales program, including a forward sales 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, in long-term debttheir capacity as agents and/or principals (Agents). Under the terms of the Sales Agreements, we may issue and approximately 4 millionsell, 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 beginning January 2015 and ending October 31, 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.

Our ability to sell our common stock up to the specified $170 million limit will depend on a variety of circumstances, including equity market conditions, trading volume in our common stock and other factors outside our control. We cannot predict the timing of any such sales or the aggregate amount of shares that may be sold under the ATM program. In addition, the ATM program allows us, at our option, to sell shares pursuant to FSAs with affiliates of our sales agents (forward counterparties) under the related ATM program sales agreements. Shares sold pursuant to FSAs settle on dates specified by us, which may be substantially after the sales occur but not later than October 31, 2016, subject to certain exceptions. As of October 31, 2015, all FSAs have been settled in shares, and we intend to settle any future FSAs in shares. Under the terms of the Merger Agreement, we would need to obtain Duke Energy's prior consent to cash or net settle a FSA.

The table below presents equity transactions under the open registration statements over the three-year period ended October 31, 2015.
    Per share
Equity Issuance Transaction Number of Shares Settled 
Net Proceeds Before Issuance Costs (1)  (In thousands)
 Public Offering Price Net Settlement Price  Underwriting Discount
Underwriting agreement, January 2013:           
Issued 3,000,000
 February 2013 $92,640
 $32.00
 $30.88
  $1.12
FSAs physically settled in shares 1,600,000
 December 2013 47,302
   30.88
   
  4,600,000
   $139,942
       
              
ATM program, physically settled in shares:         
FSA - executed March 2015 612,000
 October 2015 $21,729
   35.50
(2) 
  
FSA - executed June 2015 795,529
 October 2015 28,230
   35.49
(2) 
  
FSA - executed September 2015 114,500
 October 2015 4,125
   36.03
(2) 
  
  Total ATM program 1,522,029



$54,084
       
(1) Issuance costs incurred as follows: February 2013 shares - $370, December 2013 shares - $12, and October 2015 shares - $377.
(2) Net of 1.5% commission plus other adjustments.

We used the net proceeds from the equity transactions presented above to finance capital expenditures, repay outstanding notes under the unsecured CP program and for general corporate purposes. As of October 31, 2015, we have approximately $114.1 million remaining under the ATM program. For further information on our common stock and for more details on these equity issuance transactions, see Note 7 to the consolidated financial statements in this Form 10-K.

As of October 31, 2015, we have $544.1 million remaining under the shelf registration statement for debt and equity issuances as approved by the NCUC. We plan to issue equity capital in our fiscal 2013.

year 2016, at such amounts to support our capital investment program and maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. In addition to issuing common stock under our DRIP and ESPP as described above, we expect to continue to issue common stock under our ATM program as described above through the end of fiscal 2016.



39


We continually monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt. In March 2012, we entered into an agreementThe table below presents the activity of our long-term debt during the three-year period ended October 31, 2015. For further information on our long-term debt instruments, see Note 5 to issue $300 million of notesthe consolidated financial statements in a private placement with a blended interest rate of 3.54%. In July 2012, we issued $100 million with an interest rate of 3.47%. In October 2012, we issued $200 million with an interest rate of 3.57%. Both issuances will mature in July 2027. These proceeds were used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.

this Form 10-K.

In millions Issued (Redeemed) Date Issued/Redeemed Cash Impact
Senior Notes:       
  4.65%, due August 1, 2043 (1)
 $300
 August 2013 $299.9
(3) 
  4.10%, due September 18, 2034 (2)
 250
 September 2014 249.6
(3) 
  3.60%, due August 15, 2025(2)
 150
 September 2015 149.9
(3) 
Medium-Term Notes:       
  5.00%, due December 19, 2013 (100) December 2013 (100.0) 
        
(1) The net proceeds were used to finance capital expenditures, to repay the balance of $100 million of our 5% Medium-Term Notes listed below, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes.
(2) The net proceeds were used to finance capital expenditures, to repay outstanding short-term unsecured notes under our CP program and for general corporate purposes.
(3) Net of debt discount.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program and our accelerated share repurchase program as described in Note 67 to the consolidated financial statements. During 2012, we repurchased and retired .8 million shares for $26.5 millionstatements in this Form 10-K. We did not repurchase any or our common stock under our Common Stock Open Market Purchase Program leaving a balance of 2,910,074 shares available for repurchase underduring the program. During 2011 and 2010,three-year period ended October 31, 2015, nor do we repurchased .8 million shares and 1.8 million shares for $23 million and $47.3 million, respectively. We do not anticipate repurchasing our common stock in our fiscal year 2013.

2016. During 2012,the effectiveness of the Merger Agreement, we are prohibited from repurchasing our common stock.


During 2015, we issued $22.1$27 million of common stock through DRIP and ESPP. During 20112014 and 2010,2013, we issued $20.2$25.6 million and $19.1$24.6 million, respectively, through these plans.


We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share in 2012, 2011 and 2010.over the past three fiscal years. Dividends of $85.7$103.4 million, $82.9$99.2 million and $80.3$92.1 million for 2012, 2011in 2015, 2014 and 2010,2013, respectively, were paid on common stock. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2012,2015, our retained earnings wereability to pay dividends was not restricted.restricted by these note agreements. On December 13, 2012,11, 2015, the Board of Directors declared a quarterly dividend on common stock of $.30$.33 per share, payable December 31, 2012January 15, 2016 to shareholders of record at the close of business on December 24, 2012.2015. For further information on our long-term debt, see Note 45 to the consolidated financial statements.

statements in this Form 10-K.


Our long-term targeted capitalization ratio is 45-50%50 – 60% in long-termtotal debt and 50-55%40 – 50% in common equity. As of October 31, 2012, our capitalization, including current maturities of long-term debt, if any, consisted of 49% in long-term debt and 51% in common equity.

The components of our total debt outstanding (short-term and long-term)long-term, excluding unamortized discount and debt issuance costs) to our total capitalization as of October 31, 20122015 and 20112014 are summarized in the table below.

   October 31   October 31 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

In thousands

  2012   Percentage   2011   Percentage 

Short-term debt

    $365,000    16 %      $331,000    16 %  

Long-term debt

   975,000    41 %     675,000    34 %  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total debt

   1,340,000    57 %     1,006,000    50 %  

Common stockholders’ equity

   1,027,004    43 %     996,923    50 %  

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total capitalization (including short-term debt)

    $  2,367,004    100 %      $  2,002,923    100 %  

 

  

 

 

   

 

 

   

 

 

   

 

 

 

  October 31 October 31
In thousands 2015 Percentage 2014 Percentage
Short-term debt $340,000
 10% $355,000
 12%
Current portion of long-term debt 40,000
 1% —
 —%
Long-term debt, principal 1,535,000
 46% 1,425,000
 46%
Total debt 1,915,000
 57% 1,780,000
 58%
Common stockholders’ equity 1,426,312
 43% 1,308,602
 42%
Total capitalization (including short-term debt) $3,341,312
 100% $3,088,602
 100%

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



40


The lenders under our revolving syndicated credit facility and our unsecured CP program are major financial institutions, all of which have investment grade credit ratings as of October 31, 2015. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

As of October 31, 2012,2015, all of our long-term debt was unsecured. Our long-term debt is rated “A” by two rating agencies, Standard & Poor’s Ratings Services (S&P) and “A3” by Moody’s Investors Service (Moody’s). Our current debt ratings are all considered investment grade and are as follows.
S&PMoody's
Unsecured long-term debtAA2
Commercial paperA1P1

Subsequent to the announcement of the Acquisition, S&P affirmed our A rating for our senior unsecured long-term debt but placed it on credit watch with negative implications. Currently, with respect toMoody's has maintained its stable outlook for our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our CP program at “A1” and “P2”, respectively.debt. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, ora change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by ourthe rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.


We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2012,2015, there has been no event of default giving rise to acceleration of our debt.


The default provisions of some or all of our senior debt include:

Failure to make principal or interest payments,
Bankruptcy, liquidation or insolvency,
Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
Specified events under the Employee Retirement Income Security Act of 1974,
Change in control, and
Failure to observe or perform covenants, including:

Interest coverage of at least 1.75 times. Interest coverage was 4.723.96 times as of October 31, 2012;2015;
Funded debt cannot exceed 70% of total capitalization. Funded debt was 57% of total capitalization as of October 31, 2012;2015;
Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2012;2015;
Restrictions on permitted liens;

Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.


The Acquisition would constitute a change in control under the note agreements under which our 2.02% Senior Notes due 2016, 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued.  While the Acquisition would not constitute an event of default, upon the closing of the Acquisition, we would be required to offer to prepay these notes to the noteholders at 100% of the principal amounts plus accrued interest.

Contractual Obligations and Commitments


We have incurred various contractual obligations and commitments in the normal course of business. In November 2012, we contractually committed to provide funding of an estimated $180 million for our 24% equity membership of Constitution Pipeline Company, LLC. For further information about this contractual obligation, which is not reflected in the table below as of October 31, 2012, see the previous discussion in “Cash Flows from Investing Activities” in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. As of October 31, 2012,2015, our estimated recorded and unrecorded contractual obligations are as follows.

   Payments Due by Period 
   Less than   1-3   3-5   More than     

In thousands

  

1 year

   

Years

   

Years

   

5 Years

   

Total

 

Recorded contractual obligations:

          

Long-term debt (1)

    $-       $140,000      $35,000      $800,000      $975,000  

Short-term debt (2)

   365,000     -      -      -      365,000  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recorded contractual obligations

   365,000     140,000     35,000     800,000     1,340,000  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
Unrecorded contractual obligations and commitments: (3)          

Pipeline and storage capacity (4)

   152,163     349,224     119,902     227,477     848,766  

Gas supply (5)

   6,149     -      -      -      6,149  

Interest on long-term debt (6)

   47,831     140,052     86,431     355,200     629,514  

Telecommunications and information technology (7)

   9,459     12,244     -      -      21,703  

Qualified and nonqualified pension plan funding (8)

   21,198     34,640     11,885     -      67,723  

Postretirement benefits plan funding (8)

   1,500     4,000     1,300     -      6,800  

Operating leases (9)

   4,265     12,109     7,393     28,241     52,008  

Other purchase obligations (10)

   28,798     -      -      -      28,798  

Letters of credit (11)

   3,649     -      -      -      3,649  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total unrecorded contractual obligations and commitments

   275,012     552,269     226,911     610,918     1,665,110  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total contractual obligations and commitments

    $      640,012      $      692,269      $      261,911      $  1,410,918      $  3,005,110  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

We have conditional asset retirement obligations for underground mains and services of $19.7 million that are not included in the table because we cannot reasonably estimate payments by periods.

41


  Payments Due by Period
  Less than 1-3 3-5 More than  
In thousands 1 year Years Years 5 Years Total
Recorded contractual obligations:          
           
Long-term debt (1)
 $40,000
 $35,000
 $160,000
 $1,340,000
 $1,575,000
Short-term debt (2)
 340,000
 —
 —
 —
 340,000
Total recorded contractual obligations 380,000
 35,000
 160,000
 1,340,000
 1,915,000
           
Unrecorded contractual obligations and          
 commitments: (3)
          
           
Pipeline and storage capacity (4)
 178,594
 439,793
 228,134
 402,599
 1,249,120
Gas supply reservation fees (5)
 4,577
 165
 —
 —
 4,742
Gas supply purchase commitments (6)
 65,286
 228,922
 139,328
 638,129
 1,071,665
Interest on long-term debt (7)
 75,323
 216,936
 142,705
 692,155
 1,127,119
Capital contributions to joint ventures (8)
 115,835
 234,269
 1,172
 —
 351,276
Telecommunications and information          
  technology (9)
 6,164
 2,918
 —
 —
 9,082
Qualified and nonqualified pension plan          
  funding (10)
 12,170
 37,946
 13,141
 —
 63,257
Postretirement benefits plan funding (10)
 1,300
 3,600
 1,200
 —
 6,100
Operating leases (11)
 5,052
 13,748
 9,060
 19,830
 47,690
Other purchase obligations (12)
 45,577
 —
 —
 —
 45,577
Surety bonds (11)
 5,465
 1,170
 —
 —
 6,635
Letters of credit (2)
 1,641
 —
 —
 —
 1,641
Total unrecorded contractual obligations          
  and commitments 516,984
 1,179,467
 534,740
 1,752,713
 3,983,904
Total contractual obligations and          
  commitments $896,984
 $1,214,467
 $694,740
 $3,092,713
 $5,898,904
(1)
(1)
See Note 45 to the consolidated financial statements.statements in this Form 10-K.
(2)
See Note 56 to the consolidated financial statements.statements in this Form 10-K.
(3)
In accordance with generally acceptable accounting principles in the United States (GAAP), these items are not reflected in the Consolidated Balance Sheets.
(4)
Recoverable through PGA procedures.
(5)
Reservation fees are fixed payments and are recoverable through PGA procedures.
(6)
Base load gas supply commitments at market index pricing. For purposes of this table, payments above are calculated at the December 2015 price levels.
(7)
Includes accrued interest of $29.5 million as of October 31, 2015.
(8)
See Note 413 to the consolidated financial statements.statements in this Form 10-K.
(7)
(9)
Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, and cell phone and pager usage fees.
(8)
(10)
Estimated funding beyond five years is not available. See Note 10 to the consolidated financial statements in this Form 10-K.
(11)
See Note 9 to the consolidated financial statements.
(9)See Note 8 to the consolidated financial statements.statements in this Form 10-K. Operating lease payments do not include paymentspayment for common area maintenance, utilities or tax payments.
(10)
(12)
Consists primarily of pipeline products, vehicles, contractors and merchandise.
(11)See Note 5 to the consolidated financial statements.


Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than


From time to time, we enter into letters of credit, surety bonds and operating leases.leases, as well as credit support arrangements on behalf of a wholly-owned subsidiary that holds one of our equity-method investments. None of these existing arrangements are material to our results of operations, cash flows or financial position. The letters of credit are discussed in

42


Note 6 to the consolidated financial statements in this Form 10-K. The surety bonds and operating leases are discussed in Note 5 and Note 8, respectively,9 to the consolidated financial statements in this Form 10-K. The credit support arrangement and indemnification agreement are reflecteddiscussed in Note 13 to the table above.

consolidated financial statements in this Form 10-K.


Critical Accounting Estimates


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


Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates. Management has discussed these critical accounting estimates presented below with the Audit Committee of the Board of Directors.


Revenue Recognition. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. In South Carolina and Tennessee, we have WNA mechanisms that are designed to protect a portion of our residential and commercial customer revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA mechanisms also serve to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin earned monthly under the margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanisms. Without the WNA and margin decoupling mechanisms, our operating revenues and margin would have been higher by $33.8 million and $41.8 million in 20122015 and 2014, respectively, and lower by $9 million 2013.

In 2014, the IMR was implemented in North Carolina and Tennessee to separately track and recover costs associated with capital expenditures in order to comply with pipeline safety and integrity requirements on an annual basis outside general rate cases. Under the North Carolina IMR tariff as initially approved, we file annually each November to capture such costs closed to plant through October with revised rates effective the following February. Under the Tennessee IMR, we file to adjust rates to be effective each January 1 based on capital expenditures incurred through the previous October. Without the IMR in North Carolina, our operating revenues and margin would have been lower by $60.1$17.1 million for the period November 1, 2014 through October 31, 2015 and higher by $11.9$.6 million for the period February 1, 2014 through October 31, 2014, respectively. Without the IMR in Tennessee, our operating revenues and $14.7margin would have been lower by $18.2 million for the period November 1, 2014 through October 31, 2015 and by $10.1 million for the period January 1, 2014 through October 31, 2014, respectively.

The North Carolina IMR was revised in 2011November 2015. As revised, filings are to be made semi-annually each October 31 and 2010,April 30 for certain costs closed to plant through September and March, respectively, with revised rates to be effective the following December 1 and June 1, respectively.


Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Meters are read throughout the month based on an approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to

estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.


Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to the accounting regulations required by rate-regulated operations and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting

43


policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to those portions ceasing to meet such criteria and include them in theas an adjustment to net income statementor accumulated other comprehensive income for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded.


Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation.legislation that would affect the regulatory environment. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.


Regulatory assets as of October 31, 20122015 and 20112014 totaled $293.1$207.7 million and $200.1$202.1 million, respectively. Regulatory liabilities as of October 31, 20122015 and 20112014 totaled $489.7$603.7 million and $467$604.8 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 13 to the consolidated financial statements.

statements in this Form 10-K.


Pension and Postretirement Benefits. We have a traditional defined benefit pension plan (qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible employees. For further information and our reported costs of providing these benefits, see Note 910 to the consolidated financial statements. statements in this Form 10-K. We recognize the funded status of our benefit plans as an asset or liability with any changes in the funded status recorded as a regulatory asset or liability as allowed by our state regulatory commissions.

The costs of providing these benefits are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.


Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In September 2015, we announced the replacement of the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA), effective January 1, 2016. Under the HRA, the retiree will receive a fixed subsidy that is assumed to not increase; therefore, our 2015 accumulated postretirement benefit obligation is not impacted by projected health care cost trend rates. For further information on this change in coverage, see Note 10 to the consolidated financial statements in this Form 10-K.

In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may

differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods, and we cannot predict with certainty what these factors will be in the future.


The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’snon-callable bonds rated AA or better-rated non-callable bonds. Based on this approach,better by either Moody’s or S&P that have a yield higher than the regression mean yield curve. The weighted average discount raterates used in the measurement of theour plans' benefit obligation for the qualified pension plan changed from 4.67% in 2011 to 3.51% in 2012. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 4.10% in 2011 to 2.95% in 2012. Similarly, the weighted average discount rate for postretirement benefits changed from 4.36% in 2011 to 3.34% in 2012.obligations are presented below. The lowerhigher discount rates discussed abovein 2015 reflect the lowerhigher yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, the initial health care cost trend rate was assumed to be 7.70% in 2012 declining gradually to 5% by 2027.

decreased.

  2015 2014
Qualified pension plan 4.34% 4.13%
Nonqualified pension plans 3.85% 3.69%
Postretirement benefits 4.38% 4.03%


44


In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 50%55% equity securities and 50%45% fixed income securities. To the extent that the actual rate of return on assets realized during the fiscal year is greater or less than the assumed rate, that year’s qualified pension plan and postretirement benefits plan costs are not affected; instead, this gain or loss reduces or increases the future costs of the plans over the average remaining service period for active employees. The expected long-term rate of return on plan assets was 8% in 2010, 20112013, decreasing to 7.75% in 2014, and 2012.further decreasing to 7.5% in 2015. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.87%3.76% in 2010,2013, decreasing to 3.78%3.72% in 20112014, and further decreasing to 3.76%3.68% in 20122015 due to changes in the demographics of the participants.


Our market-related value of plan assets represents the fair market value of the plan’s assets as adjusted by the portion of the prior five years’ asset gains and losses that has not yet been recognized. The use of this calculation delays the impact of current market fluctuations on benefit costs for the fiscal year.


During 2012,2015, we recorded costs of $5.5$7.1 million related to our qualified pension plan and postretirement benefits plan. We estimate 20132016 expenses for these two plans to be in the range of $11$3.5 to $12$4 million representing an increasea decrease of $5.5$3.1 to $6.5$3.6 million over 2012.from 2015. These estimates reflect the higher discount rates and assumeda 7.25% expected long-term rate of return on the plan assets discussed above for each plan.

assets.


The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculation are constant.

   Change in  Impact on 2012   Impact on Projected 

Actuarial Assumption

  Assumption  Benefit Cost   Benefit Obligation 
      

Increase (Decrease)

In thousands

 

Discount rate

   (.25)%  $551         $7,999       

Rate of return on plan assets

   (.25)%   634          N/A        

Rate of increase in compensation

   .25 %   658          4,629       

  Change in  Impact on 2015  Impact on Projected
Actuarial Assumption Assumption  Benefit Cost  Benefit Obligation
     
Increase (Decrease)
In thousands
Discount rate (0.25)% $674 $7,472
Rate of return on plan assets (0.25)%  787  N/A      
Rate of increase in compensation 0.25%  791  3,740

The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.

      Impact on 2012   Impact on Accumulated 
   Change in  Postretirement   Postretirement Benefit 
Actuarial Assumption  Assumption  Benefit Cost   Obligation 
      Increase (Decrease) 
      

In thousands

 

Discount rate

   (.25)%  $11         $924       

Rate of return on plan assets

   (.25)%   53          N/A        

Health care cost trend rate

   .25 %   8          167       

     Impact on 2015  Impact on Accumulated
  Change in  Postretirement  Postretirement Benefit
Actuarial Assumption Assumption  Benefit Cost  Obligation
     Increase (Decrease)
     In thousands
Discount rate (0.25)% $122 $1,128
Rate of return on plan assets (0.25)%  67  N/A      
Health care cost trend rate 0.25%  34  N/A      

We utilize accounting methods consistently applied that are allowed under GAAP which reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.


Beginning in 2016, we will change the method we use to estimate the service and interest cost components of net periodic benefit costs for our plans from using a developed zero-coupon spot rate yield curve as discussed above. We have elected to use a full yield curve approach in the estimation of these components of benefit costs by applying the specific spot rates along the yield curve used in the determination of the benefit obligations to the relevant projected cash flows. We will make 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 will not affect the measurement of our total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We will account for this change as a change in estimate and, accordingly, will account for it prospectively beginning in 2016.

The expected impact in 2016 of the change in accounting estimate discussed above is presented below and is reflected in the 2016 estimated expense discussed above.

45


  Qualified Nonqualified Other
  Pension Pension Benefits
Discount rates used to measure benefit costs in 2016:      
Service cost 4.46% N/A       4.67%
Interest cost 3.25% 2.98% 3.51%
Discount rate that would have been used to measure service and interest costs under prior actuarial methodology 4.34% 3.85% 4.38%
       
Reduction in components of expected 2016 benefit costs using specific spot rates: Impact in thousands
Service cost $153
 N/A       $11
Interest cost 3,280
 $45
 320

The health care cost trend rate used in the prior actuarial calculations is not applicable under the 2016 methodology to measure either the benefit cost or the obligation for postretirement benefits. This is due to the new plan design where Piedmont's HRA contribution will be fixed as discussed above.

Gas Supply and Regulatory Proceedings


The source of our gas supply that we distribute to our customers comes primarilyis contracted from the Gulf Coast production region where it is purchased mostly froma diverse portfolio of major and independent producers and marketers. As part of our long-term plan to diversify our reliance away from the Gulf Coast region, we contracted for firm, long-term market areamarketers and interstate and intrastate pipeline and storage service in West Virginia from Hardy Storage Company, LLC, a venture in which we have a 50% equity interest, which is more fully discussed in Note 12 to the consolidated financial statements. We also contracted for firm, long-term transportation contract service that provides access to Canadian and Rocky Mountain gas supplies and the Chicago hub, primarily to serve our Tennessee markets.

operators. In Novemberlate 2012, we executedentered into long-term contracts that would provide diversification in our supply diversification strategyportfolio to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed aThe long-term contract with Cabot Oil & Gas (Cabot) to purchase firm, price-competitive Marcellus gas supplies. We also signed asupplies and the long-term firm capacity contract with Williams-Transco forWilliams – Transco under its Leidy Southeast expansion project to transport thosethe Cabot gas supplies to our markets. These new supply arrangements are scheduled to beginmarkets began partial service in December 2015, and2015. Our long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion allowing us to further diversify our supply portfolio with Marcellus based natural gas began service in September 2015. Also, in October 2014, we contracted for long-term pipeline capacity from diverse gas supply basins in central West Virginia under the ACP project that is proposed to be effective for the winter 2018 – 2019 season. We believe theythat these new natural gas supplies will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.


Natural gas demand is continuing to grow in our service area particularly to provide natural gas delivery service to power generation facilities as discussed in the preceding section of “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.10-K. For further information on our equity venture with Cardinal that expandedventures, particularly ACP's future service to our firm capacity requirement in order to serve a power generation facility in Wayne County, North Carolina,expanding markets, see Note 1213 to the consolidated financial statements.

Secondarystatements in this Form 10-K.


As approved by our state regulatory commissions, secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales normally contribute smaller per-unit margins to earnings; however, the program allowsprograms allow us to act as a wholesale marketer of natural gas and transportation capacity when market conditions permit in orderand when the supply and capacity are not required to generate operating margin from sources not restricted by the capacity ofserve our retail distribution system. For further information on secondary market transactions, see Note 23 to the consolidated financial statements.

statements in this Form 10-K.


We continue to work with our regulatory commissions to earn a fair rate of return on invested capital for our shareholders and provide safe, reliable natural gas distribution service to our customers. For further information about regulatory proceedings and other regulatory information, see Note 23 to the consolidated financial statements.

statements in this Form 10-K.


Equity Method Investments


For information about our equity method investments, see Note 1213 to the consolidated financial statements.

statements in this Form 10-K.


Environmental Matters


We have developed an environmental self-assessment plan to examine our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGPManufactured Gas Plant Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 89 to the consolidated financial statements.

statements in this Form 10-K.



46


Accounting Guidance


For further information regarding recently issuedon accounting guidance, see Note 1 to the consolidated financial statements.

International Financial Reporting Standards (IFRS)

In early 2010, the SEC expressed its commitment to the development of a single set of high quality globally accepted accounting standards and directed its staff to execute a work plan addressing specific areas of concern regarding the potential incorporation of IFRS for the U.S. The work plan and progress made by the Financial Accounting Standards Board and the International Accounting Standards Board (IASB) to achieve convergence on some key accounting standards would be foundational to the SEC’s decision on whether, when and how the U.S. might adopt IFRS. The SEC has stated that the fundamental question is whether transitioning to IFRS isstatements in the best interests of the U.S. securities markets generally and U.S. investors specifically.

In July 2012, the SEC Staff released its final report on the work plan that includes its summary findings by the SEC Staff on the following:

Development of IFRS,this Form 10-K.
Interpretive process,
Use of national standard setters by the IASB,
Global application and enforcement,
Governance of the IASB,
Status of funding, and
Investor understanding.

The final report does not contain a recommendation for SEC action. A Staff recommendation will be made at some later unspecified date.

In late 2010 and early 2011, we completed a preliminary assessment of IFRS to understand the key accounting and reporting differences compared to U.S. GAAP and to assess potential organizational, process and system impacts that would be required. The accounting differences between U.S. GAAP and IFRS are complex and significant in many areas, and conversion to IFRS would have broad impacts on us. In addition to financial statement and disclosure changes, converting to IFRS would involve changes to processes and controls, regulatory and management reporting, financial reporting systems and other areas of the company. As a part of the IFRS assessment project, a preliminary conversion roadmap was created for reporting in accordance with IFRS. This IFRS conversion roadmap and our strategy for addressing a potential mandate of IFRS will be re-assessed when the SEC makes its final determination on the use of IFRS.

Item 7A. Quantitative and Qualitative DisclosuresaboutDisclosures about Market Risk


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


In fiscal 2014, the Board of Directors delegated oversight of our ERM program to the Finance and Enterprise Risk (FER) Committee. All other committees of our Board of Directors have enhanced monitoring of those risks relating to areas over which they have oversight responsibility. The Board of Directors approved risk tolerances for several major areas of risk exposure, namely strategic, commercial, market, financial, operational, regulatory and reputational risks, and receives quarterly reports from the FER Committee and annual reports from management.

We hold all financial instruments discussed below for purposes other than trading.


Credit Risk


We enter into contracts with third parties to buy and sell natural gas. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. Incontract, or in situations where counterparties do not have investment gradeinvestment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the 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.


We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party.


We have mitigated our exposure to the risk of non-payment of utility bills by our customers. In North Carolina and South Carolina,all three states, gas costs related to uncollectible accounts are recovered through PGA procedures. Effective in March 2012, we recover gas costs related to uncollectible accounts through PGA procedures in Tennessee similar to North Carolina and South Carolina. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas or colder-than-normal weather can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.


Interest Rate Risk


We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2012,2015, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.


We have short-term borrowing arrangements to provide working capital and general corporate liquidity. The level of borrowings under such arrangements varies from period to period depending upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs, our investments in capital projects, the level and expense of our storage inventory and the collection of receivables. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.


As of October 31, 2012,2015, we had $365$340 million of short-term debt outstanding as commercial paper at an interest rate of .42%.22%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $4.2$3.6 million during 2012.

2015.



47


As of October 31, 2012,2015, information about our long-term debt is presented below.

                        Fair Value as 
   Expected Maturity Date     of October 31, 
In millions    2013      2014      2015      2016      2017      Thereafter      Total      2012   

Fixed Rate Long-term Debt

  $        -   $        100  $        -   $40  $35  $        800.0  $        975.0  $        1,163.2 

Average Interest Rate

   -%   5 %   -%           2.92%           8.51%   5.21%   5.22%  

                Fair Value as
  Expected Maturity Date   of October 31,
In millions 2016 2017 2018 2019 2020   Thereafter     Total   2015
Fixed Rate Long-term Debt $40
 $35
 $—
 $—
 $—
 $1,500
 $1,575
 $1,720.6
Average Interest Rate 2.92% 8.51% —% —% —% 4.75% 4.79%  

Commodity Price Risk


We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. As such,However, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers” in “Current“Regulatory Assets” or any over-recoveries are included in “Amounts due to customers” in “Current“Regulatory Liabilities” as presented in Note 3 to the Consolidated Balance Sheetsconsolidated financial statements in this Form 10-K, for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.


We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments and have used over-the-counter instruments of various durations to hedge price volatility on a portion of our natural gas requirements, subject to regulatory review and approval.


We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since mostsubstantially all of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier default would have a material effect on our financial position, results of operations or cash flows.


Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Costs have never been disallowed on the basis of prudence in any jurisdiction.


Weather Risk


We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. This risk is mitigated by a WNA mechanism designed to offset the impact of colder-than-normal or warmer-than-normal weather in our residential and commercial markets during the months of November through March in our residential and commercial markets. Effective in March 2012, the additional months of AprilSouth Carolina and October are includedthrough April in Tennessee. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the Tennessee WNA mechanism.factors. In North Carolina, we manage our weather risk through a year round margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold. We are exposed to weather risks in our industrial markets to the extent our margin is collected through volumetric rates in all of our jurisdictions.


Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.


Item 8. Financial Statements and Supplementary Data


Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV of this Form 10-K.





48


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina


We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 20122015 and 2011,2014, and the related consolidated statements of comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2012.2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe financial statements based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 20122015 and 2011,2014, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2012,2015, in conformity with accounting principles generally accepted in the United States of America.


We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of October 31, 2012,2015, based on the criteria established inInternal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 21, 201223, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.


/s/ Deloitte & Touche LLP


Charlotte, North Carolina

December 21, 2012

23, 2015


49




Consolidated Balance Sheets

October 31, 20122015 and 2011

2014


ASSETS

In thousands  2012   2011 

Utility Plant:

    

  Utility plant in service

  $3,746,178    $3,377,310  

    Less accumulated depreciation

   1,036,814     974,631  
  

 

 

   

 

 

 

      Utility plant in service, net

   2,709,364     2,402,679  

  Construction work in progress

   388,979     217,832  

  Plant held for future use

   6,743     6,751  
  

 

 

   

 

 

 

      Total utility plant, net

       3,105,086         2,627,262  
  

 

 

   

 

 

 
Other Physical Property, at cost (net of accumulated
  depreciation of $843 in 2012 and $806 in 2011)		   415     452  
  

 

 

   

 

 

 

Current Assets:

    
  Cash and cash equivalents   1,959     6,777  

  Trade accounts receivable (less allowance for doubtful

    accounts of $1,579 in 2012 and $1,347 in 2011)

   56,700     57,035  
  Income taxes receivable   31,606     15,966  
  Other receivables   2,104     2,547  
  Unbilled utility revenues   24,012     28,715  
  Inventories:    
    Gas in storage   72,661     91,124  
    Materials, supplies and merchandise   934     1,368  
  Gas purchase derivative assets, at fair value   3,153     2,772  
  Amounts due from customers   81,626     38,649  
  Prepayments   30,600     39,128  
  Deferred income taxes   -      1,793  
  Other current assets   287     147  
  

 

 

   

 

 

 

    Total current assets

   305,642     286,021  
  

 

 

   

 

 

 

Noncurrent Assets:

    

  Equity method investments in non-utility activities

   87,867     85,121  

  Goodwill

   48,852     48,852  

  Marketable securities, at fair value

   2,131     1,439  

  Overfunded postretirement asset

   -      22,879  

  Regulatory asset for postretirement benefits

   123,290     81,073  

  Unamortized debt expense

   13,583     11,315  

  Regulatory cost of removal asset

   21,129     19,336  

  Other noncurrent assets

   61,944     58,791  
  

 

 

   

 

 

 

      Total noncurrent assets

   358,796     328,806  
  

 

 

   

 

 

 

      Total

  $3,769,939    $3,242,541  
  

 

 

   

 

 

 

See notes to consolidated financial statements.

In thousands 2015 2014
Utility Plant:    
Utility plant in service $5,426,584
 $5,011,497
Less accumulated depreciation 1,251,940
 1,166,922
Utility plant in service, net 4,174,644
 3,844,575
Construction work in progress 170,250
 141,693
Plant held for future use 3,155
 3,155
Total utility plant, net 4,348,049
 3,989,423
Other Physical Property, at cost (net of accumulated depreciation of $926 in 2015 and $904 in 2014) 332
 355
Current Assets:    
Cash and cash equivalents 13,744
 9,643
Trade accounts receivable (1) (less allowance for doubtful accounts of $1,648 in 2015 and $2,152 in 2014)
 59,248
 65,260
Income taxes receivable 11,447
 36,100
Other receivables 10,667
 3,361
Unbilled utility revenues 17,422
 21,093
Inventories:    
Gas in storage 68,240
 84,081
Materials, supplies and merchandise 1,251
 1,652
Gas purchase derivative assets, at fair value 1,343
 4,898
Regulatory assets 10,936
 27,837
Prepayments 28,903
 39,030
Deferred income taxes 32,392
 53,418
Other current assets 344
 326
Total current assets 255,937
 346,699
Noncurrent Assets:    
Equity method investments in non-utility activities 206,956
 170,171
Goodwill 48,852
 48,852
Regulatory assets 196,726
 174,281
Income taxes receivable 26,023
 —
Marketable securities, at fair value 4,666
 3,727
Overfunded postretirement asset 17,770
 33,757
Other noncurrent assets 5,439
 7,042
Total noncurrent assets 506,432
 437,830
Total $5,110,750
 $4,774,307
     
(1) See Note 13 for amounts attributable to affiliates.
    
     
See notes to consolidated financial statements.    



50


Consolidated Balance Sheets

October 31, 20122015 and 2011

2014


CAPITALIZATION AND LIABILITIES

In thousands  2012   2011 

Capitalization:

    
  Stockholders’ equity:    
    Cumulative preferred stock - no par value - 175 shares authorized  $-     $-   
    Common stock - no par value - shares authorized: 200,000;
      shares outstanding: 72,250 in 2012 and 72,318 in 2011		   442,461     446,791  
    Retained earnings   584,848     550,584  
    Accumulated other comprehensive loss   (305)     (452)  
  

 

 

   

 

 

 
      Total stockholders’ equity   1,027,004     996,923  
  Long-term debt   975,000     675,000  
  

��

 

   

 

 

 
      Total capitalization   2,002,004     1,671,923  
  

 

 

   

 

 

 
Current Liabilities:    
  Short-term debt   365,000     331,000  
  Trade accounts payable   94,269     85,721  
  Other accounts payable   47,699     43,959  
  Accrued interest   21,450     20,038  
  Customers’ deposits   21,739     25,462  
  Current deferred taxes   13,542     -   
  General taxes accrued   21,504     21,262  
  Amounts due to customers   28     2,617  
  Other current liabilities   7,320     4,073  
  

 

 

   

 

 

 
      Total current liabilities   592,551     534,132  
  

 

 

   

 

 

 
Noncurrent Liabilities:    
  Deferred income taxes   597,211     512,961  
  Unamortized federal investment tax credits   1,669     2,004  
  Accumulated provision for postretirement benefits   37,299     14,671  
  Cost of removal obligations   492,963     466,000  
  Other noncurrent liabilities   46,242     40,850  
  

 

 

   

 

 

 
      Total noncurrent liabilities   1,175,384     1,036,486  
  

 

 

   

 

 

 
Commitments and Contingencies (Note 8)    
    
  

 

 

   

 

 

 
      Total  $    3,769,939    $    3,242,541  
  

 

 

   

 

 

 

See notes to consolidated financial statements.

Page Intentionally Blank

In thousands 2015 2014
Capitalization:    
Stockholders’ equity:    
Cumulative preferred stock - no par value - 175 shares authorized $—
 $—
Common stock – no par value – shares authorized: 200,000; shares outstanding: 80,883 in 2015 and 78,531 in 2014 721,419
 636,835
Retained earnings 705,748
 672,004
Accumulated other comprehensive loss (855) (237)
Total stockholders’ equity 1,426,312
 1,308,602
Long-term debt, net 1,523,677
 1,414,484
Total capitalization 2,949,989
 2,723,086
Current Liabilities:    
Current maturities of long-term debt 40,000
 —
Short-term debt 340,000
 355,000
Trade accounts payable (1)
 99,895
 85,299
Other accounts payable 52,149
 54,349
Accrued interest 29,488
 27,982
Customers’ deposits 20,896
 19,994
General taxes accrued 27,940
 23,828
Regulatory liabilities 13,367
 46,231
Other current liabilities 11,861
 9,303
Total current liabilities 635,596
 621,986
Noncurrent Liabilities:    
Deferred income taxes 861,615
 809,467
Unamortized federal investment tax credits 1,027
 1,193
Accumulated provision for postretirement benefits 14,975
 15,471
Regulatory liabilities 590,301
 558,598
Conditional cost of removal obligations 19,712
 14,647
Other noncurrent liabilities 37,535
 29,859
Total noncurrent liabilities 1,525,165
 1,429,235
Commitments and Contingencies (Note 9) 
 
Total $5,110,750
 $4,774,307
     
(1) See Note 13 for amounts attributable to affiliates.
    
     
See notes to consolidated financial statements.    

51


Consolidated Statements of Comprehensive Income

For the Years Ended October 31, 2012, 20112015, 2014 and 2010

    2012   2011   2010 
In thousands except per share amounts            
Operating Revenues  $    1,122,780    $    1,433,905    $    1,552,295  
Cost of Gas   547,334     860,266     999,703  
  

 

 

   

 

 

   

 

 

 
Margin   575,446     573,639     552,592  
  

 

 

   

 

 

   

 

 

 
Operating Expenses:      
  Operations and maintenance   242,599     225,351     219,829  
  Depreciation   103,192     102,829     98,494  
  General taxes   34,831     38,380     33,909  
  Utility income taxes   69,101     64,068     62,082  
  

 

 

   

 

 

   

 

 

 
    Total operating expenses   449,723     430,628     414,314  
  

 

 

   

 

 

   

 

 

 
Operating Income   125,723     143,011     138,278  
  

 

 

   

 

 

   

 

 

 
Other Income (Expense):      
  Income from equity method investments   23,904     24,027     28,854  
  Gain on sale of interest in equity method investment   -      -      49,674  
  Non-operating income   1,288     1,762     659  
  Charitable contributions   (1,068)     (1,818)     (1,363)  
  Non-operating expense   (787)     (1,204)     (643)  
  Income taxes   (9,116)     (8,218)     (29,794)  
  

 

 

   

 

 

   

 

 

 
    Total other income (expense)   14,221     14,549     47,387  
  

 

 

   

 

 

   

 

 

 
Utility Interest Charges:      
  Interest on long-term debt   41,412     46,070     52,666  
  Allowance for borrowed funds used during construction   (25,211)     (8,619)     (9,981)  
  Other   3,896     6,541     1,026  
  

 

 

   

 

 

   

 

 

 
    Total utility interest charges   20,097     43,992     43,711  
  

 

 

   

 

 

   

 

 

 
Net Income   119,847     113,568     141,954  
  

 

 

   

 

 

   

 

 

 
Other Comprehensive Income, net of tax:      
  Unrealized loss from hedging activities of equity method
    investments, net of tax of ($530), ($371) and ($52) for the years
    ended October 31, 2012, 2011 and 2010, respectively.		   (826)     (576)     (88)  

  Reclassification adjustment of realized gain from hedging activities

    of equity method investments included in net income, net of tax of
    $621, $420 and $1,291 for the years ended October 31, 2012, 2011
    and 2010, respectively.

   973     654     2,005  
  

 

 

   

 

 

   

 

 

 
    Total other comprehensive income   147     78     1,917  
  

 

 

   

 

 

   

 

 

 
Comprehensive Income  $119,994    $113,646    $143,871  
  

 

 

   

 

 

   

 

 

 
Average Shares of Common Stock:      
  Basic   71,977     72,056     72,275  
  Diluted   72,278     72,266     72,525  
Earnings Per Share of Common Stock:      
  Basic  $1.67    $1.58    $1.96  
  Diluted  $1.66    $1.57    $1.96  

See notes to consolidated financial statements.

2013

In thousands, except per share amounts 2015 2014 2013
Operating Revenues (1)
 $1,371,718
 $1,469,988
 $1,278,229
Cost of Gas (1)
 644,424
 779,780
 656,739
Margin 727,294
 690,208
 621,490
Operating Expenses:      
Operations and maintenance 294,517
 270,877
 253,120
Depreciation 128,704
 118,996
 112,207
General taxes 42,110
 37,294
 34,635
Utility income taxes 76,934
 83,176
 77,334
Total operating expenses 542,265
 510,343
 477,296
Operating Income 185,029
 179,865
 144,194
Other Income (Expense):      
Income from equity method investments 34,461
 32,753
 26,056
Non-operating income 3,164
 1,842
 2,839
Non-operating expense (3,724) (4,331) (5,122)
Income taxes (13,288) (11,642) (8,612)
Total other income (expense) 20,613
 18,622
 15,161
Utility Interest Charges:      
Interest on long-term debt 70,619
 61,562
 54,158
Allowance for borrowed funds used during construction (11,106) (16,427) (30,975)
Other 9,118
 9,551
 1,755
Total utility interest charges 68,631
 54,686
 24,938
Net Income 137,011
 143,801
 134,417
Other Comprehensive Income (Loss), net of tax:      
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($1,028), $225 and ($69) for the years ended October 31, 2015, 2014 and 2013, respectively (1,601) 355
 (109)
Reclassification adjustment of realized (gain) loss from hedging activities of equity method investments included in net income, net of tax of $652, ($177) and $85 for the years ended October 31, 2015, 2014 and 2013, respectively 1,018
 (284) 130
Net current period benefit activities of equity method investments, net of tax of ($23) and ($16) for the years ended October 31, 2015 and 2014, respectively (35) (24)  
Total other comprehensive income (loss) (618) 47

21
Comprehensive Income $136,393
 $143,848

$134,438
       
Average Shares of Common Stock:      
Basic 78,942
 77,883
 74,884
Diluted 79,231
 78,193
 75,333
       
Earnings Per Share of Common Stock:      
Basic $1.74
 $1.85
 $1.80
Diluted $1.73
 $1.84
 $1.78
       
(1) See Note 13 for amounts attributable to affiliates.
      
       
See notes to consolidated financial statements.


52



Consolidated Statements of Cash Flows

For the Years Ended October 31, 2012, 20112015, 2014 and 2010

In thousands  2012   2011   2010 
Cash Flows from Operating Activities:      
  Net income  $      119,847    $      113,568    $      141,954  
  Adjustments to reconcile net income to net
    cash provided by operating activities:		      
      Depreciation and amortization   109,230     107,046     102,776  

  Amortization of investment tax credits

   (335)     (141)     (277)  

  Allowance for doubtful accounts

   232     418     (61)  

  Gain on sale of interest in equity method investment, net of tax

   -      -      (30,286)  

  Net gain on sale of property

   -      -      (89)  

  Income from equity method investments

   (23,904)     (24,027)     (28,854)  

  Distributions of earnings from equity method investments

   19,590     22,685     28,834  

  Deferred income taxes, net

   99,494     76,962     21,831  

  Changes in assets and liabilities:

      

    Gas purchase derivatives, at fair value

   (381)     47     (30,863)  

    Receivables

   5,403     (3,019)     23,493  

    Inventories

   18,897     13,789     2,565  

    Amounts due from/to customers

   (45,566)     26,304     133,794  

    Settlement of legal asset retirement obligations

   (2,038)     (1,493)     (1,141)  

    Overfunded postretirement asset

   22,879     (5,537)     (17,342)  

    Regulatory asset for postretirement benefits

   (42,217)     (16,298)     12,130  

    Other assets

   (10,388)     972     18,184  

    Accounts payable

   4,283     (4,085)     (3,007)  

    Provision for postretirement benefits

   22,628     (134)     (16,836)  

    Other liabilities

   6,861     4,188     3,706  
  

 

 

   

 

 

   

 

 

 
Net cash provided by operating activities   304,515     311,245     360,511  
  

 

 

   

 

 

   

 

 

 
Cash Flows from Investing Activities:      
  Utility capital expenditures   (529,576)     (243,641)     (199,059)  
  Allowance for funds used during construction   (25,211)     (8,619)     (9,981)  
  Contributions to equity method investments   (3,566)     (6,222)     -   
  Distributions of capital from equity method investments   5,372     3,029     18,260  
  Proceeds from sale of interest in equity method investment   -      -      57,500  
  Proceeds from sale of property   1,250     1,074     1,653  
  Investments in marketable securities   (606)     (486)     (498)  
  Other   3,044     2,292     3,554  
  

 

 

   

 

 

   

 

 

 
Net cash used in investing activities   (549,293)     (252,573)     (128,571)  
  

 

 

   

 

 

   

 

 

 

2013

In thousands 2015 2014 2013
Cash Flows from Operating Activities:      
Net income $137,011
 $143,801
 $134,417
  Adjustments to reconcile net income to net cash provided by      
   operating activities:      
Depreciation and amortization 140,217
 129,343
 120,797
Provision for doubtful accounts 5,095
 6,959
 5,314
Impairment loss on investment —
 2,000
 —
Net gain on sale of property —
 (817) (349)
Income from equity method investments (34,461) (32,753) (26,056)
Distributions of earnings from equity method investments 24,875
 24,843
 22,139
Deferred income taxes, net 73,407
 87,136
 57,637
Changes in assets and liabilities:      
Gas purchase derivatives, at fair value 3,555
 (3,064) 1,319
Receivables, net (2,637) 9,785
 (28,616)
Inventories 16,242
 (10,079) (2,059)
Settlement of legal asset retirement obligations (5,563) (3,575) (2,389)
Regulatory assets (14,917) 20,297
 43,338
Other assets 16,220
 (2,829) 4,629
Accounts payable (7,626) 18
 2,381
Contributions to benefit plans (12,728) (22,516) (22,415)
Accrued/deferred postretirement benefit costs 28,219
 20,446
 (31,100)
Regulatory liabilities (16,065) 49,468
 23,429
Other liabilities 20,791
 12,149
 10,831
Net cash provided by operating activities 371,635
 430,612
 313,247
       
Cash Flows from Investing Activities:      
Utility capital expenditures (443,654) (460,444) (599,999)
Allowance for borrowed funds used during construction (11,106) (16,427) (30,975)
Contributions to equity method investments (29,723) (37,642) (41,348)
Distributions of capital from equity method investments 1,505
 3,929
 4,700
Proceeds from sale of property 717
 1,883
 1,951
Investments in marketable securities (866) (454) (414)
Other 4,707
 4,708
 2,609
Net cash used in investing activities (478,420) (504,447) (663,476)

53


Consolidated Statements of Cash Flows

For the Years Ended October 31, 2012, 20112015, 2014 and 2010

In thousands  2012   2011   2010 
Cash Flows from Financing Activities:      
  Borrowings under credit facility   350,000             1,723,000             1,058,000  
  Repayments under credit facility   (681,000)     (1,634,000)     (1,122,000)  
  Net borrowings - commercial paper   365,000     -      -   
  Proceeds from issuance of long-term debt   300,000     200,000     -   
  Retirement of long-term debt   -      (256,922)     (60,590)  
  Expenses related to issuance of debt   (3,908)     (3,902)     (46)  

  Issuance of common stock through dividend reinvestment and employee stock plans

   22,123     20,233     19,099  
  Repurchases of common stock   (26,528)     (23,004)     (47,295)  
  Dividends paid   (85,693)     (82,913)     (80,255)  
  Other   (34)     (6)     (792)  
  

 

 

   

 

 

   

 

 

 
Net cash provided by (used in) financing activities   239,960     (57,514)     (233,879)  
  

 

 

   

 

 

   

 

 

 
Net (Decrease) Increase in Cash and Cash Equivalents   (4,818)     1,158     (1,939)  
Cash and Cash Equivalents at Beginning of Year   6,777     5,619     7,558  
  

 

 

   

 

 

   

 

 

 
Cash and Cash Equivalents at End of Year      $1,959        $6,777        $5,619  
  

 

 

   

 

 

   

 

 

 
Cash Paid During the Year for:      
  Interest      $        44,571        $50,136        $56,554  
  

 

 

   

 

 

   

 

 

 
  Income Taxes:      

  Income taxes paid

      $4,770        $5,649        $32,305  

  Income taxes refunded

   8,437     16,958     1,845  
  

 

 

   

 

 

   

 

 

 

  Income taxes, net

      $(3,667)        $(11,309)        $30,460  
  

 

 

   

 

 

   

 

 

 
Noncash Investing and Financing Activities:      
  Accrued construction expenditures      $43,643        $18,055        $3,225  
  Guaranty   -      -      1,234  

See notes to consolidated financial statements.

2013

In thousands 2015 2014 2013
Cash Flows from Financing Activities:      
Borrowings under credit facility $—
 $—
 $10,000
Repayments under credit facility —
 —
 (10,000)
Net (repayments) borrowings - commercial paper (15,000) (45,000) 35,000
Proceeds from issuance of long-term debt, net of discount 149,902
 249,565
 299,856
Repayment of long-term debt —
 (100,000) —
Expenses related to issuance of debt (1,330) (2,871) (3,250)
Proceeds from issuance of common stock, net of expenses 53,707
 47,290
 92,271
Issuance of common stock through dividend reinvestment and
  employee stock plans
 26,992
 25,556
 24,610
Dividends paid (103,390) (99,151) (92,146)
Other 5
 26
 (8)
Net cash provided by financing activities 110,886
 75,415
 356,333
Net Increase in Cash and Cash Equivalents 4,101
 1,580
 6,104
Cash and Cash Equivalents at Beginning of Year 9,643
 8,063
 1,959
Cash and Cash Equivalents at End of Year $13,744
 $9,643
 $8,063
       
Cash Paid During the Year for:      
Interest $71,519
 $64,276
 $50,275
       
Income Taxes:      
Income taxes paid $3,680
 $10,840
 $5,760
Income taxes refunded 530
 30
 169
Income taxes, net $3,150
 $10,810
 $5,591
       
Noncash Investing and Financing Activities:      
Accrued construction expenditures $58,868
 $38,869
 $39,389
       
See notes to consolidated financial statements.


54



Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2012, 20112015, 2014 and 2010

In thousands except per share amounts  

Common

Stock

   

Retained

Earnings

   

Accumulated

Other

Comprehensive

Income (Loss)

   Total 

Balance, October 31, 2009

    $    471,569      $    458,826      $    (2,447)      $    927,948  
        

 

 

 

Comprehensive Income:

        

  Net income

     141,954       141,954  

  Other comprehensive income

       1,917     1,917  
        

 

 

 

Total comprehensive income

         143,871  

Common Stock Issued

   21,366         21,366  

Common Stock Repurchased

   (47,276)         (47,276)  

Rescission Offer

   (19)         (19)  

Costs of Rescission Offer

     (792)       (792)  

Tax Benefit from Dividends Paid on ESOP Shares

     98       98  

Dividends Declared ($1.11 per share)

     (80,255)       (80,255)  
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance, October 31, 2010

   445,640     519,831     (530)     964,941  
        

 

 

 

Comprehensive Income:

        

  Net income

     113,568       113,568  

  Other comprehensive income

       78     78  
        

 

 

 

Total comprehensive income

         113,646  

Common Stock Issued

   24,155         24,155  

Common Stock Repurchased

   (23,004)         (23,004)  

Costs of Rescission Offer

     (6)       (6)  

Tax Benefit from Dividends Paid on ESOP Shares

     104       104  

Dividends Declared ($1.15 per share)

     (82,913)       (82,913)  
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance, October 31, 2011

   446,791     550,584     (452)     996,923  
        

 

 

 

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2012, 2011 and 2010

In thousands except per share amounts  

Common

Stock

   

Retained

Earnings

   

Accumulated

Other

Comprehensive

Income (Loss)

   Total 

Comprehensive Income:

        

  Net income

     119,847       119,847  

  Other comprehensive income

       147     147  
        

 

 

 

Total comprehensive income

         119,994  

Common Stock Issued

   22,198         22,198  

Common Stock Repurchased

   (26,528)         (26,528)  

Tax Benefit from Dividends Paid on ESOP Shares

     110       110  

Dividends Declared ($1.19 per share)

     (85,693)       (85,693)  
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance, October 31, 2012

    $  442,461      $  584,848      $(305)      $  1,027,004  
  

 

 

   

 

 

   

 

 

   

 

 

 

2013

In thousands, except per share amounts 
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
Balance, October 31, 2012 $442,461
 $584,848
 $(305) $1,027,004
         
Comprehensive Income:        
Net income   134,417
   134,417
Other comprehensive income     21
 21
Total comprehensive income       134,438
Common Stock Issued 119,552
     119,552
Expenses from Issuance of Common Stock (369)     (369)
Tax Benefit from Dividends Paid on ESOP Shares   117
   117
Dividends Declared ($1.23 per share)   (92,146)   (92,146)
Balance, October 31, 2013 561,644
 627,236
 (284) 1,188,596
         
Comprehensive Income:        
Net income   143,801
   143,801
Other comprehensive income     47
 47
Total comprehensive income       143,848
Common Stock Issued 75,203
     75,203
Expenses from Issuance of Common Stock (12)     (12)
Tax Benefit from Dividends Paid on ESOP Shares   118
   118
Dividends Declared ($1.27 per share)   (99,151)   (99,151)
Balance, October 31, 2014 636,835
 672,004
 (237) 1,308,602
         
Comprehensive Income:        
Net income   137,011
   137,011
Other comprehensive loss     (618) (618)
Total comprehensive income       136,393
Common Stock Issued 84,966
     84,966
Expenses from Issuance of Common Stock (382)     (382)
Tax Benefit from Dividends Paid on ESOP Shares   123
   123
Dividends Declared ($1.31 per share)   (103,390)   (103,390)
Balance, October 31, 2015 $721,419
 $705,748
 $(855) $1,426,312
         
See notes to consolidated financial statements.

The components of accumulated other comprehensive income (loss) (OCI)(OCIL) as of October 31, 20122015 and 20112014 are as follows.

In thousands

  2012   2011 

Hedging activities of equity method investments

  $      (305)    $            (452)  

See notes to consolidated financial statements.

In thousands 2015 2014
Hedging activities of equity method investments $(796) $(213)
Benefit activities of equity method investments (59) (24)

55


Notes to Consolidated Financial Statements


1. Summary of Significant Accounting Policies


Nature of Operations and Basis of Consolidation


Piedmont Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 23 to the consolidated financial statements.


The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). The consolidated financial statements reflect the accounts of Piedmont and its wholly ownedwholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For further information on equity method investments, see Note 12 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Inter-companyFor further information on equity method investments and related party transactions, have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on salessee Note 13 to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

the consolidated financial statements.


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. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 1516 to the consolidated financial statements.


On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy). For further information, see Note 2 to the consolidated financial statements.

Use of Estimates

The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC).


In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and liabilities, disclosureexpenses 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 contingentjudgment 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 consolidated financial statements and the reported amounts of revenues and expenses during the periods reported.reporting period. Actual results could differ significantly from these estimates and assumptions.

assumptions, which are evaluated on a continual basis.


Segment Reporting


Our segments are based on the components of the Company for which we produce separate financial information internally that are evaluatedis used regularly by the chief operating decision maker (CODM) in deciding how to allocate resources and in assessing performance. Our chief operating decision makerCODM is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision makingdecision-making activities. We evaluate the performance of the regulated utility segment based on margin, operations and

56


maintenance (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from our cash flows in the ventures.


We have twothree reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home warranty programs,service agreements, with activities conducted by the utility. 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. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly ownedwholly-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 Consolidated Statements of
Comprehensive Income. Earnings or losses from equity method investments of the regulated and unregulated non-utility activities segments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. All other revenues and expenses of the regulated and unregulated non-utility activities segments are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. See Note 1415 to the consolidated financial statements for further discussion of segments.


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.income or accumulated other comprehensive income (OCI). 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.

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2012 and 2011 are as follows.

In thousands

  

2012

   

2011

 

Regulatory Assets:

    

Unamortized debt expense

      $13,583        $11,315  

Amounts due from customers

   81,626     38,649  

Environmental costs *

   10,202     9,644  

Deferred operations and maintenance expenses *

   7,050     7,676  

Deferred pipeline integrity expenses *

   13,691     7,927  

Deferred pension and other retirement benefits costs *

   20,139     22,119  

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

   123,290     81,073  

Regulatory cost of removal asset

   21,129     19,336  

Other *

   2,394     2,396  
  

 

 

   

 

 

 

Total

      $293,104        $200,135  
  

 

 

   

 

 

 

Regulatory Liabilities:

    

Regulatory cost of removal obligations

      $464,334        $438,605  

Amounts due to customers

   28     2,617  

Deferred income taxes*

   25,330     25,731  
  

 

 

   

 

 

 

Total

      $      489,692        $      466,953  
  

 

 

   

 

 

 

* Regulatory assets are included in “Other noncurrent assets” in “Noncurrent Assets” and regulatory liabilities are included in “Other noncurrent liabilities” in “Noncurrent Liabilities” in the Consolidated Balance Sheets.

As of October 31, 2012, we had regulatory assets totaling $.4 million on which we do not earn a return during the recovery period. The original amortization period for these assets is 15 years and, accordingly, $.4 million will be fully amortized by 2018. We have $2.2 million related to unrealized mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing amounts due to/from customer accounts when realized and $123.3 million of regulatory postretirement assets, $21.1 million of asset retirement obligations (AROs) and $8.4 million of estimated environmental costs on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.


Utility Plant and Depreciation


Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, and pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the costcosts of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.



57


The classification of total utility plant, net, for the years ended October 31, 20122015 and 20112014 is presented below.

In thousands

  

2012

   

2011

 

Intangible plant

  $3,374    $3,377  

Other storage plant

   118,277     56,064  

Transmission plant

   866,000     652,069  

Distribution plant

   2,422,988     2,347,287  

General plant

   329,867     312,482  

Asset retirement cost

   10,819     11,156  

Contributions in aid of construction

   (5,147)     (5,125)  
  

 

 

   

 

 

 

Total utility plant in service

   3,746,178     3,377,310  

Less accumulated depreciation

   (1,036,814)     (974,631)  
  

 

 

   

 

 

 

Total utility plant in service, net

   2,709,364     2,402,679  
  

 

 

   

 

 

 

Construction work in progress

   388,979     217,832  

Plant held for future use

   6,743     6,751  
  

 

 

   

 

 

 

Total utility plant, net

  $      3,105,086    $      2,627,262  
  

 

 

   

 

 

 

In thousands 2015 2014
Intangible plant $3,374
 $3,374
Other storage plant 180,960
 180,058
Transmission plant 2,024,264
 1,787,990
Distribution plant 2,766,871
 2,623,560
General plant 452,301
 421,763
Asset retirement cost 4,159
 11
Contributions in aid of construction (5,345) (5,259)
Total utility plant in service 5,426,584
 5,011,497
Less accumulated depreciation (1,251,940) (1,166,922)
Total utility plant in service, net 4,174,644
 3,844,575
Construction work in progress 170,250
 141,693
Plant held for future use 3,155
 3,155
Total utility plant, net $4,348,049
 $3,989,423

Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.


AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the Consolidated Statements of Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For the three years ended October 31, 2012, 20112015, 2014 and 2010,2013, all of our AFUDC was attributable to borrowed funds.


AFUDC for the years ended October 31, 2012, 20112015, 2014 and 20102013 is presented below.

In thousands

  

2012

   

2011

   

2010

 

AFUDC

  $25,211    $8,619    $9,981  

In thousands
2015
2014
2013
AFUDC
$11,106

$16,427

$30,975

In accordance with utility accounting practice, we have classified expendituresreal estate and development costs associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina that has been delayed as “Plant held for future use” in the Consolidated Balance Sheets. There is no current needSheets, due to proceedconstruction being suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the LNG peak storage facility dueNorth Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the expansion capacity, cost effectiveness, timingamortization and design scopecollection of another construction project$1.2 million of non-real estate costs that will enhanceis recorded as a regulatory asset with amortization over 38 months beginning January 1, 2014 through February 2017. Under the settlement of our abilityJune 2014 rate stabilization adjustment (RSA) filing with the Public Service Commission of South Carolina (PSCSC) that was approved in October 2014, we agreed to serve our North Carolina customersthe amortization and collection of $.5 million of non-real estate costs that was recorded as a regulatory asset with amortization over the 12 months beginning November 1, 2014. We recorded cumulative amortization of $1.8 million of non-real estate costs in this area. The future usefiscal year 2013 that is included in the Consolidated Statements of this property is dependent upon annual updates to our ongoing five-year plan for forecasted growth requirements, and the

pursuit of such project will be determined as growth requirements dictate. Such costs, approximately half being land purchase and preparation, will be moved to any such future project.Comprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on a regulatory filing related tothe 2013 general rate proceeding settlement of these costs for North Carolina or the 2014 RSA filing for South Carolina, see Note 23 to the consolidated financial statements.


We compute depreciation expense using the straight-line method over periods ranging from 45 to 8880 years. The composite weighted-average depreciation rates were 2.94%2.48% for 2012, 3.19%2015, 2.54% for 20112014 and 3.20%2.77% for 2010.

2013.


Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed

58


with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina, and March 1, 2012 for Tennessee. We anticipateTennessee and January 1, 2014 for North Carolina.

As authorized by our regulatory commissions, the new rates will become effective in North Carolina in connection with our next general rate case filing.

The estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we accruecollect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate.

Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in Note 3 to the consolidated financial statements. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.


Cash and Cash Equivalents


We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31, 20122015 and 2011.

2014.


Trade Accounts Receivable and Allowance for Doubtful Accounts


Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the North Carolina Utilities Commission (NCUC),NCUC, the Public Service Commission of South Carolina (PSCSC)PSCSC and the TRA,Tennessee Regulatory Authority (TRA), we are authorized to recover allactual uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets.

We are exposed to credit risk when we enter into contracts with third parties to sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our internal credit policies require counterparties to have an investment-grade or functionally equivalent credit rating at the time of the contract. Where the counterparty does not have an investment-grade credit rating, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. We continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas.


We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 20122015 and 2011,2014, our trade accounts receivable consisted of the following.

In thousands

  

2012

   

2011

 

Gas receivables

      $55,956        $55,928  

Non-regulated merchandise and service work receivables

   2,323     2,454  

Allowance for doubtful accounts

   (1,579)     (1,347)  
  

 

 

   

 

 

 

Trade accounts receivable

      $      56,700        $      57,035  
  

 

 

   

 

 

 

In thousands 2015 2014
Gas receivables $57,759
 $64,400
Non-regulated merchandise and service work receivables 3,137
 3,012
Allowance for doubtful accounts (1,648) (2,152)
Trade accounts receivable $59,248
 $65,260

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2012, 20112015, 2014 and 20102013 is presented below.

In thousands

  

2012

   

2011

   

2010

 

Balance at beginning of year

  $1,347    $929    $990  

Additions charged to uncollectibles expense

   4,584     4,842     4,886  

Accounts written off, net of recoveries

   (4,352)     (4,424)     (4,947)  
  

 

 

   

 

 

   

 

 

 

Balance at end of year

  $        1,579    $        1,347    $        929  
  

 

 

   

 

 

   

 

 

 

In thousands 2015 2014 2013
Balance at beginning of year $2,152
 $1,604
 $1,579
Additions charged to uncollectibles expense 5,095
 6,959
 5,314
Accounts written off, net of recoveries (5,599) (6,411) (5,289)
Balance at end of year $1,648
 $2,152
 $1,604

For information on credit risk, see "Credit and Counterparty Risk" in Note 8 of the consolidated financial statements.

Inventories


We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in

59


storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.


We utilizeenter into service contracts, or asset management agreementsarrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we may assign the gas supply and/or storage inventory and release the transportation capacity and storage capacity to the asset manager for certain natural gas storagethe term of the agreement. The inventory is assigned at no cost, and transportation assets. the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in the inventories section as “Gas in storage.” From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,” and the inventory that is available for our use remains in “Gas in storage.”

At October 31, 20122015 and 2011,2014, such counterparties held natural gas storage assets includedas recorded in “Prepayments” in “Current Assets” in the Consolidated Balance Sheets,“Prepayments,” with a value of $26.7$24.8 million and $35.8$35 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive capacity and storage asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The asset management agreementsAMAs expire at various times through March 31, 2014.2017. For further information on the revenue sharing of secondary market transactions, see Note 23 to the consolidated financial statements.


Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.


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 Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of cash and cash equivalents, 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 financialnonfinancial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the Consolidated Balance Sheets in accordance with derivative accounting standards and marketable securities that are classified as trading securities and are held in rabbi trusts established forinclude our deferred compensation plans. Our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.


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


Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.


Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We

60


obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place.marketplace. Our Level 2 items include

non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities fund of funds, a common trust fund,funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.


Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a diversified private equity fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.


In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.


Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as a Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer.


For the fair value measurements of our derivatives and marketable securities, see Note 78 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 910 to the consolidated financial statements.


Goodwill, Equity Method Investments and Long-Lived Assets


Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. WeWhen we test goodwill, usingwe use a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 1415 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.


Our annual goodwill impairment assessment was performed as of October 31, 2012,2015 was performed using a qualitative approach. As part of our qualitative assessment, we considered macroeconomic conditions such as general deterioration in economic condition, limitations on accessing capital and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any changes in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors, such as increases in utility construction expenditures, labor or other costs, that would have a negative effect on earnings. We determined that there was no impairment tothe relevance of any entity-specific events or events affecting our regulated utility segment which would have a negative effect on the carrying value of the reporting unit.

Based on our goodwill.qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test as of October 31, 2015. The annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment has beenwas recognized during the years ended October 31, 2012, 20112015, 2014 and 2010.

2013. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.


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We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. In April 2014, we recorded a $2 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Non-operating expense" in the Consolidated Statements of Comprehensive Income. There were no events or circumstances during the years ended October 31, 2012, 20112015 and 20102013 that resulted in any impairment charges. For further information on equity method investments, see Note 1213 to the consolidated financial statements.


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 910 to the consolidated financial statements.


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


The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 20122015 and 20112014 is as follows.

In thousands

  2012   2011 
    

Cost

   

Fair Value

   

Cost

   

Fair Value

 

Current trading securities:

        

Money markets

  $-     $-     $-     $-   

Mutual funds

   134     157     47     52  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current trading securities

   134     157     47     52  
  

 

 

   

 

 

   

 

 

   

 

 

 

Noncurrent trading securities:

        

Money markets

   243     243     217     217  

Mutual funds

   1,668     1,888     1,107     1,222  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total noncurrent trading securities

   1,911     2,131     1,324     1,439  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total trading securities

  $      2,045    $      2,288    $      1,371    $      1,491  
  

 

 

   

 

 

   

 

 

   

 

 

 

Unamortized Debt Expense

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt which has lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is five years.

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

  2015 2014
In thousands Cost Fair Value Cost Fair Value
Current trading securities:        
Money markets $51
 $51
 $22
 $22
Mutual funds 114
 185
 106
 192
  Total current trading securities 165
 236
 128
 214
Noncurrent trading securities:        
Money markets 465
 465
 447
 447
Mutual funds 3,625
 4,201
 2,598
 3,280
  Total noncurrent trading securities 4,090
 4,666
 3,045
 3,727
    Total trading securities $4,255
 $4,902
 $3,173
 $3,941

Issuances and Repurchases of Common Stock


As discussed in Note 67 to the consolidated financial statements, from time to time we may repurchase shares on the open market and such shares are then cancelledcanceled and become authorized but unissued shares. It is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders’ Equity. Shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under the Incentive Compensation Plan have been immaterial to date.


Asset Retirement Obligations


The accounting guidance for AROsasset retirement obligations (AROs) addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that conditional AROs exist for our underground mains and services.

In accordance with long-standing regulatory treatment, our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal.


We collect through rates the estimatedhave costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal coststhat are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated

62


removal costs meet the requirements of rate regulatedrate-regulated accounting guidance, we have accounted for these non-legal AROs in “Regulatory Liabilities” as a regulatory liability. We recordpresented in Note 3 to the estimated non-legal AROs in “Cost of removal obligations” in “Noncurrent Liabilities” in the Consolidated Balance Sheets.consolidated financial statements. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.

For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation” in this Note 1.


We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with netting againsta corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 3.86%4.62% to 5.87%5.89% with a time value weighted average of 5.73%5.69% for the twelve months ended October 31, 2012. The estimate was calculated using a time value weighted average credit adjusted risk-free rate.2015. We have recorded a liability on our distribution and transmission mains and services.


The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 20122015 and 20112014 are presented below.

In thousands

  

2012

   

2011

 

Regulatory non-legal AROs

  $464,334    $438,605  

Conditional AROs

   28,629     27,395  
  

 

 

   

 

 

 

Total cost of removal obligations

  $        492,963    $        466,000  
  

 

 

   

 

 

 

In thousands 2015 2014
Regulatory non-legal AROs $521,478
 $506,574
Conditional AROs 19,712
 14,647
Total cost of removal obligations $541,190
 $521,221

A reconciliation of the changes in conditional AROs for the year ended October 31, 20122015 and 20112014 is presented below.

In thousands

  

2012

   

2011

 

Beginning of period

    $27,395      $23,295  

Liabilities incurred during the period

   1,705     3,102  

Liabilities settled during the period

   (2,038)     (1,493)  

Accretion

   1,570     1,365  

Adjustment to estimated cash flows

   (3)     1,126  
  

 

 

   

 

 

 

End of period

    $      28,629      $      27,395  
  

 

 

   

 

 

 

In thousands 2015 2014
Beginning of period $14,647
 $27,016
Liabilities incurred during the period 4,663
 2,108
Liabilities settled during the period (5,563) (3,576)
Accretion 924
 1,548
Adjustment to estimated cash flows 5,041
 (12,449)
End of period $19,712
 $14,647

Unamortized Debt Expense

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt with lives ranging from 5 to 30 years. With the adoption of new accounting guidance in our fourth quarter of 2015 to present debt issuance costs as a direct deduction from the carrying amount of that debt, long-term debt is now presented net of unamortized debt expenses in the accompanying Consolidated Balance Sheets. For further information on the effects on regulatory assets and our long-term debt, see Note 3 and Note 5, respectively, to the consolidated financial statements.

We amortize bank debt expense over the life of the syndicated revolving credit facility, which is 5 years.

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt as a regulatory asset or liability and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

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Revenue Recognition


We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March. Effective March 1, 2012, the WNA mechanism in Tennessee was expanded to include the additional months of April and October in the winter heating season. The WNA mechanisms are designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formula does not ensure full recovery of approved margin during periods when customer consumption patterns vary significantly from consumption patterns used to establish the WNA factors. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of weather and 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, a RSA mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March, and in Tennessee, the months of April and October. The WNA mechanisms are designed to partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. 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. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanisms.

mechanism.


We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee, effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was initially approved in December 2013 in the settlement of our 2013 general rate case and subsequently revised in November 2015. Under the revised North Carolina IMR tariff, we will make filings semi-annually each October 31 and April 30 for certain costs closed to plant through September and March, respectively, with revised rates effective the following December 1 and June 1, respectively. Under the Tennessee IMR, we file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. For further discussion of the IMRs, see Note 3 to the consolidated financial statements.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable.


Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 23 to the consolidated financial statements regarding revenue sharing of secondary market transactions.


Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. For further information regarding taxes, see “Taxes” in this Note 1 to the consolidated financial statements.

1.


Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term.


Cost of Gas and Deferred Purchased Gas Adjustments


We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred and allocated gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers, such that no operating margin is recognized related to these costs, are deferred and included in “Amounts due from customers” in “Current“Regulatory Assets” or “Amounts due to customers” in “Current

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“Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in Note 3 to the Consolidated Balance Sheets.consolidated financial statements. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.


Taxes


We have two categories of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.


Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.


Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.


We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.


Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.


Consolidated Statements of Cash Flows


With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.


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Accounting Standards Update (ASU) - Guidance Adopted in Fiscal Year 2015
GuidanceDescriptionEffective dateEffect on the financial statements or other significant matters
ASU 2015-03, April 2015, Interest: Imputation of Interest - Simplifying the Presentation of Debt Issuance Costs (Subtopic 835-30)
The guidance is part of the Financial Accounting Standards Board's (FASB) simplification initiative to reduce complexity in accounting standards. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this amendment.Annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted for financial statements that have not been previously issued. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015.The adoption of this guidance had no impact on our results of operations or cash flows. We retrospectively changed the presentation of the balance sheet line items current and noncurrent "Regulatory assets," "Other noncurrent assets" and "Long-term debt, net."
ASU 2015-15, August 2015, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting
The guidance provides clarification to ASU 2015-03 for debt issuance costs for line-of-credit arrangements, specifically that the SEC would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.Effective upon adoption of ASU 2015-03, as adopted August 1, 2015.The adoption of this guidance had no impact on our results of operations or cash flows.
ASU 2015-07, May 2015, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (Topic 820)
The guidance amends the required disclosure of investments for which fair value is measured at NAV per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the NAV per share practical expedient.Annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with retrospective application to all periods presented and early adoption permitted. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015.The adoption of this guidance had no impact on our financial position, results of operations or cash flows. We have disclosed certain benefit plan assets under the new guidance.

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GuidanceDescriptionEffective dateEffect on the financial statements or other significant matters
ASU 2015-12, July 2015, Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965)
The FASB issued a three-part standard providing guidance on certain aspects of the accounting by employee benefit plans. The ASU: (1) requires a pension plan to use contract value as the only measure for fully benefit-responsive investment contracts; (2) simplifies and increases the effectiveness of the investment disclosure requirements for employee benefit plans by grouping investments by general type; and (3) provides benefit plans with a measurement-date practical expedient on a month-end date nearest to the employer's fiscal year end.Annual periods beginning after December 15, 2015 with early adoption permitted. The amendments in parts (1) and (2) are retrospectively applied to all periods presented, while the amendment in part (3) is applied prospectively. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015.The adoption of this guidance had no impact on our financial position, results of operations or cash flows. We have disclosed certain benefit plan assets under the new guidance of part (2). Parts (1) and (2) are applicable to our future Form 11-K filing; part (3) is not applicable to us.
Recently Issued Accounting Guidance

GuidanceDescriptionEffective dateEffect 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 efforts of an accounting utility subgroup and its issuance of a revenue implementation guide.
ASU 2014-15, August 2014, Presentation of Financial Statements - Going Concern (Subtopic 205-40)
The amendment provides guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity must provide certain disclosures if there is a "substantial doubt about the entity's ability to continue as a going concern."Annual periods ending after December 15, 2016 (October 31, 2017 for us), and interim and annual periods thereafter; early adoption is permitted.The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. It will require establishing a going concern assessment process to meet the standard.

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GuidanceDescriptionEffective dateEffect 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 guidance amends ASC 350-40 to provide customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software.Annual periods (and interim periods within those periods) 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 currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2015-17, November 2015, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes
The guidance eliminates the current requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax liabilities and assets be classified as noncurrent. The current requirement that deferred tax liabilities and assets be presented as a single amount remains unchanged.Annual periods (and interim periods within those periods) beginning after December 15, 2016, early adoption is permitted.The adoption of this guidance will have no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent will affect presentation of our financial position.

Reclassifications and Changes in Presentation

Reclassifications have been made to the prior year Consolidated Balance Sheets to conform with the current year presentation. We early adopted ASU 2015-03 requiring that issuance costs related to a long-term debt issuance be presented as a direct deduction from the carrying amount of that debt. In January 2010, the Financial Accounting Standards Board (FASB) issuedprior years, we presented unamortized debt expense as current and noncurrent regulatory assets. While these amounts are not regulatory assets under accounting guidance, they are a critical component of the embedded cost of debt financing and cost of capital utilized in rate proceedings in each of our jurisdictions. With the adoption of the new pronouncement, unamortized debt expense associated with outstanding long-term debt has been reclassified from current and noncurrent regulatory assets to require separate disclosures about purchases, sales, issuancesa reduction of the carrying value of long-term debt as of October 31, 2015 and settlements relating to Level 3 fair value measurements, which primarily relates2014. For further information on the impact to our employeepresentation of regulatory assets and long-term debt, see Note 3 and Note 5, respectively, to the consolidated financial statements.

Reclassifications have been made to the prior years Consolidated Statements of Cash Flows to conform with the current year presentation to provide additional detail and to present such information within separate line items. Within “Cash Flows from Operating Activities," we have changed the prior presentation of the cash flows line item "Allowance for doubtful accounts," comprised of the provision and the charge-offs. The provision is now presented on a separate line item "Provision for doubtful accounts" and the charges-offs are now included in the line item "Receivables, net." We have also changed the prior presentation of the cash flows line item "Provision for postretirement benefits, net" comprised of the contributions to benefit plans.plans and other activity. The guidance wascontributions are now presented on a separate line item "Contributions to benefit plans" and the remaining activity is now presented on a separate line item "Accrued/deferred postretirement benefit costs." The presentation for 2014 and 2013 have been changed to conform to the current year presentation. The reclassifications that provide additional detail had no effect on previously reported amounts for net cash flows from operating, investing or financing activities.

2. Proposed Acquisition by Duke Energy Corporation

On October 24, 2015, we entered into a Merger Agreement with 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 for interim periods for fiscal years beginning after December 15, 2010. We adoptedtime of the guidance for Level 3 disclosures for recurringAcquisition, subject to receipt of required shareholder and non-recurring items coveredregulatory 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).

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Completion of the Acquisition is subject to various closing conditions, including, among others (i) the approval of the Merger Agreement by an affirmative vote of the holders of a majority of the outstanding shares of our common stock, (ii) approval from the NCUC, and (iii) expiration or termination of any applicable waiting period under the fair value guidancefederal Hart-Scott-Rodino Antitrust Improvements Act of 1976. The Merger Agreement may be terminated by us or by Duke Energy if the Acquisition is not consummated by October 31, 2016, subject to a six-month extension by either of us under certain circumstances. The Merger Agreement contains certain termination rights for both companies under certain circumstances, and provides that, upon termination of the Merger Agreement under specified circumstances, we would be required to pay Duke Energy a termination fee of $125 million, or Duke Energy would be required to pay us a termination fee of $250 million.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to completion of the Acquisition. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and caps our cash dividend to no more than the current annual per share dividend plus an increase of not more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practices. Also, provision is made for a stub period dividend payment to holders of record of our shares of common stock immediately prior to consummation of the Acquisition.

In connection with this transaction, we recorded Acquisition-related expenses of $8.6 million for costs paid to outside parties in fiscal 2015, which are reflected in “Operations and maintenance” in “Operating Expenses” in the Consolidated Statements of Comprehensive Income. This amount does not include the cost of company personnel participating in Acquisition-related activities. We also recorded incremental share-based compensation expense of $7.2 million in "Operations and maintenance" as noted above for the first quarterend of period remeasurement to market value of the incentive compensation awards and the retention award of our fiscal year endingPresident and Chief Executive Officer based upon the increase in the trading price of our common stock since the announcement of the Acquisition. We treated these costs as tax deductible since the requisite closing conditions to the Acquisition have not yet been satisfied. Upon completion of the Acquisition, we will evaluate the tax deductibility of these costs and reflect any non-deductible amounts in the effective tax rate at the Acquisition closing date. For further information on our employee share-based plans, see Note 11 to the consolidated financial statements.


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3. Regulatory Matters

Rate-Regulated Basis of Accounting    

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2012. 2015 and 2014 are as follows.
In thousands 2015 2014
Regulatory Assets:    
Current:    
  Unamortized debt expense on reacquired debt $238
 $239
  Amounts due from customers —
 16,108
  Environmental costs 1,513
 1,568
  Deferred operations and maintenance expenses 847
 916
  Deferred pipeline integrity expenses 3,470
 3,470
  Deferred pension and other retirement benefit costs 2,757
 2,769
  Robeson LNG development costs 381
 917
  Other 1,730
 1,850
  Total current 10,936
 27,837
     
  Noncurrent:    
    Unamortized debt expense on reacquired debt 4,666
 4,904
    Environmental costs 5,107
 6,470
    Deferred operations and maintenance expenses 3,997
 4,721
    Deferred pipeline integrity expenses 29,824
 24,694
    Deferred pension and other retirement benefits costs 17,861
 18,799
    Amounts not yet recognized as a component of pension and other retirement benefit costs 114,854
 94,265
    Regulatory cost of removal asset 19,087
 18,275
    Robeson LNG development costs 127
 509
    Other 1,203
 1,644
  Total noncurrent 196,726
 174,281
    Total $207,662
 $202,118
Regulatory Liabilities:    
Current:    
  Amounts due to customers $13,367
 $46,231
     
Noncurrent:    
  Regulatory cost of removal obligations 521,478
 506,574
  Deferred income taxes 68,738
 51,930
  Amounts not yet recognized as a component of pension and other retirement benefit costs 85
 94
Total noncurrent 590,301
 558,598
  Total $603,668
 $604,829

The adoption2014 presentation of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, languageunamortized debt expense has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are describedconform with the current year presentation in the same way. The adoption oftable above. As discussed in Note 1 to the guidance, which was effective for interim and annual periods beginning after December 15, 2011, had no material impact on ourconsolidated financial position, results of operations or cash flows.

In June 2011, the FASB issued accounting guidance to increase the prominence of OCI in financial statements. The guidance gave businesses two options for presenting OCI. An OCI statement could be included with the statement of income, and together the two would make a statement of comprehensive income. Alternatively, businesses could present a separate OCI statement, but that statement would have to appear consecutively with the statement of income within the financial report. The guidance, whichstatements, we early adopted andASU 2015-03 requiring that issuance costs related to a recognized long-term debt liability be presented in one continuous statement for the first quarterbalance sheet as a direct deduction from the carrying value of that debt. Consequently, unamortized debt expense of $.9 million current and $9 million noncurrent presented in 2014 as regulatory assets have been reclassified as a reduction of $9.9 million to the carrying value of long-term debt. The amounts presented above in line items "Unamortized debt expense on reacquired debt" represent unamortized debt expense associated with the early retirement or the refunding of debt in accordance with established regulatory practice. Unamortized debt expenses related to short-term bank debt and unallocated expenses of our fiscal year endingopen debt and equity shelf registration are now presented in the line item "Other noncurrent assets" as "Noncurrent Assets" in the Consolidated Balance


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Sheets. See Note 1 with discussion of "Unamortized Debt Expense" and Note 5 to the consolidated financial statements for related discussion of these presentation changes.

As of October 31, 2012, was effective2015, we have $19.1 million of AROs and $117 million of other regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for interimour Tennessee jurisdiction. The recovery of these amounts is authorized by the TRA on a deferred cash basis.

Regulatory Oversight and annual periods beginning after December 15, 2011. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued accounting guidance to improve disclosuresRate and make information more comparable to IFRS regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity’s financial position. The new disclosure requirements are effective for annual periods beginning after January 1, 2013 and interim periods therein and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending October 31, 2014. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.

In November 2012, the FASB finalized the presentation disclosures on items reclassified from OCI. The guidance will be effective for interim and annual periods beginning after December 15, 2012. We will adopt this disclosure guidance for the second quarter of our fiscal year ending October 31, 2013. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.

2. Regulatory Matters

Actions


Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.


The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.


North Carolina


The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.


The NCUC had allowed EasternNC to defer its operations and maintenanceO&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. Thethe deferred amounts accruedaccruing interest at a rate of 8.69% per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005 of $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred operations and maintenanceO&M expenses wasof $9 million at October 31, 2008.2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 7.84%6.55% per annum and is being amortized with amortization beginning January 1, 2014over a twelve year period.an 82-month period ending October 31, 2020. As of October 31, 20122015 and 2011,2014, we had unamortized balances, including accrued interest, of $7$4.8 million and $7.7$5.6 million, respectively.


We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the operations and maintenanceO&M costs applicable to allcertain incremental pipeline integrity external expenditures beginning November 1, 2004. Under the settlementThe approved balance for recovery of the 2008 general rate proceeding, theactual pipeline integrity management O&M costs incurred between July 1, 2005 and June 30, 2008 through August 31, 2013 as established in the settlement of $4.6the 2013 general rate proceeding discussed below was $17.3 million were fullyto be amortized over a three-yearfive-year period beginning Novemberfrom January 1, 2008.2014 through December 31, 2018. As of October 31, 2015 and 2014, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $33.3 million and $28.2 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs continuesis expected to continue until another recovery mechanism is established in a future rate proceeding. The unamortized balance as

With the approval of October 31, 2012 that is subject to a futurethe settlement of the 2013 NCUC general rate proceeding is $20.3 million; we havediscussed below, certain capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR, as revised by a recorded regulatory asset forsubsequent settlement approved by the NCUC in November

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2015. The settlement also approved recovery of $6.3 million of deferred pipeline integrity expenses of $13.7 million.

North Carolina environmental costs over a five-year period from January 2014 through December 2018.


In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. CostsOur gas costs have never been disallowed on the basis of prudence.


In February 2010,November 2013, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2009, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2009 gas cost review period.2013. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.


In January 2011,November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2010 gas cost review period.2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.


In January 2012,November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2011 gas cost review period.2015. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.


Our gas cost hedging plan for North Carolina is designed to provide somea level of protection against significant price increases, targets a percentage range of 22.5%up to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued February 2010, January 2011, January 2012November 2013, November 2014 and November 20122015 found our hedging activities during the review periods to be reasonable and prudent. As part of the February 2010 order,

In April 2013, we withdrew a petition that had been filed with the NCUC approved an adjustment of $1.1 million related to hedging activity that decreased “Amounts due from customers” in “Current Assets” in the Consolidated Balance Sheets as agreed to by us and the North Carolina Public Staff.

In October 2012 we filed a petition seekingrequesting authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. Thisciting our intent to address the matter in a general rate application. The balance in “Plant held for future use” relateswas comprised of real estate and non-real estate costs and related to the development of thea LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. We are waitingThe appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.


In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:

Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a rulingreturn on common equity of 10% and an overall rate of return of 7.51%.
Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.
Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.
Implementation of lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.
Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.
Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.
Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.
Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.

In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provided for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. In February 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8

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million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR:

Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31.
Extension of the IMR tariff from October 31, 2017 to October 31, 2019.
An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings.
Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case:
Transmission integrity: 85% IMR / 15% rate case.
Distribution integrity: 90% IMR / 10% rate case.
Right-of-way clearing for integrity projects: 15% IMR / 85% rate case.
Work and asset management system: 68% IMR / 32% rate case.
Tax-related adjustments.
An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015.

Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $13.4 million in annual IMR margin revenues, effective December 1, 2015, 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 November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase.

In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the NCUC Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014, the NCUC issued an order rejecting the joint stipulation of settlement, finding that we must bill our customers for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further required us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.

In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. For further information on this matter. We are unableshelf registration statement, see Note 5 to predict the outcomeconsolidated financial statements.

In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina. In March 2015, the NCUC issued an order approving our request. The bill credit of this proceeding at this time.

$45.5 million was reflected on customers' April 2015 bills, reducing amounts due to customers in North Carolina.


South Carolina


We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South Carolina. If a utility elects to operate under the RSA,this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2010, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2010 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in an October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS) and us that resulted in a $.75 million annual increase in margin on a return on equity of 11.3%, effective November 1, 2010.

In June 2011, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the ORS and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of 11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service, effective November 1, 2011.


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In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2011 order.2011. In October 2012, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a stipulated return on equity of 11.3%, effective November 1, 2012.

In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in October 2012. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.1$.1 million annual decrease in margin based on a stipulated return on equity of 11.3%, effective November 1, 2012.

2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.


In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in October 2013. In October 2014, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina as discussed above, both with amortization periods of one year beginning November 2014 and ending October 2015.

In June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS 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 South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2010.


The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5%up to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates.

In Februaryan August 2011 the ORS requested thatorder, the PSCSC temporarily suspend the PSCSC-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of theapproved a stipulation that our hedging program was requested to be effective prospectively upon the issuanceshould no longer have a required minimum volume of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing protection policies. In March 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of price stability for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC in April 2011. In June 2011, the ORS withdrew its petition for suspension of gas hedging programs. In July 2011, the PSCSC granted the ORS’ motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings. Because the PSCSC has provided no further guidance, we will address future gas hedging activities in our annual gas cost proceedings to determine the prudence of our gas purchases.

hedging.


In August 2011,2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated that our hedging program should no longer have a required minimum volume of hedging.

2013.


In August 2012,2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.

2014.


In October 2009,September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015.

In July 2014, we filed a petition with the PSCSC requesting approvala limited waiver of certain billing provisions of our tariff related to offer three energy efficiency programs to residential and commercialemergency service for customers at a total annual cost of $.35 million. The proposed programs in South Carolina were designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs through annual RSA filings and were similar to approved energy efficiency programs in North Carolina.January 2014. In May 2010,August 2014, the PSCSC approvedgranted our request and ordered us to continue to collaborate with the energy efficiency programs on a three-year experimental basis with equipment rebates onORS to revise our tariff to address the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers.

situation that led to this petition.


Tennessee


In Tennessee, we operate under the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarkingthat benchmarks gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007,Under the TIP, the TRA modified our TIP to clarify and simplify the calculationestablished an allocation of allocating secondary marketing gains and losses to ratepayers and shareholders by adoptingwith a uniform 75/25 sharing ratio. The TRA also maintained theratio with a $1.6 million annual incentive cap for us on these gains and losses, improved the transparency of plan operations by an agreed to request for proposallosses. The

74


TIP includes procedures for asset management transactions and providedprovides for a triennial review of TIP operations by an independent consultant.

In July 2009, Although the TIP replaced annual prudence reviews of our gas purchasing activities, we filedundergo an annual report forcompliance audit on the twelve months ended December 31, 2008accuracy of our calculations and compliance with all TRA orders and directives regarding the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. There was no material impact from these gas cost adjustments tocalculation of our financial position, results of operations or cash flows. In August 2010, the TRA adopted the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report. The TRA issued its written order approving the deferred gas cost balances in October 2010.

In December 2010, we filed our report with the TRA for the eighteen months ended June 30, 2010 reflecting the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA approved the deferred gas cost account balances and issued its written order.

In September 2010, 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, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances.

In August 2011, 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, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACAActual Cost Adjustment (ACA) mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.


In August 2012, 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, 2012 under the TIP. In February 2013, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2013, the TRA approved the TIP account balances and issued its written order approving our TIP account balances.

In August 2013, 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, 2013 under the TIP. In February 2014, the Audit Staff submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.

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

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


In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2013, the TRA approved the deferred gas cost account balances and issued its written order.

In August 2013, we filed a petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the ACA annual report filed in December 2014 for the twelve-month period ended June 30, 2013. In January 2015, the TRA issued its written order approving the settlement agreement. In October 2015, the TRA approved the deferred gas cost account balances for the twelve-month period ended June 30, 2013 and issued its written order.

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 ACA mechanism. We are waiting on a ruling from the TRA at this time.


In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, for all customersproposed to produce overall incremental revenues of $16.7 million annually, or 8.9% above then current annual revenues.be effective March 1, 2012. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes were proposed to be effective March 1, 2012. In December 2011, we and the Consumer Advocate and Protection DivisionCAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above thenthe current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA’sTRA issued its written order was issued in April 2012.


As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for

75


deferred accounting treatment in October 2010. These deferred expenses are being amortized over 8eight years beginning March 1, 2012.

2012 through February 2020.


In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures of $100.4 million incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the CAD filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015. 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 capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016. We are waiting on the TRA's written order at this time.

In February 2010,2014, we filed a petition with the TRA to adjustauthorize 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 applicableCAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we will begin refunding the $4.7 million to customers through a rate fordecrement over the collection oftwelve month period beginning January 2016. We are waiting on the Nashville franchise fee from certain customers. The proposed rate adjustment was calculatedTRA's written order at this time.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) infrastructure rider to recover the net $2.9 millioncosts of under-collected Nashville franchise fee payments asour capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of May 31, 2009.general rate cases for the return of and on these capital investments. In April 2010,November 2014, the TRA passedconsolidated this docket with a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011,separate petition we filed for reconsideration, which was granted that month. In February 2012,seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. A hearing on this matter was held before the TRA.in January 2015. In May 2012,February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of an additional $.5our prior investments in CNG equipment of $4.7 million since our last rate proceeding in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recordedutility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a reduction in operations and maintenance expenses.regulated service. The TRA's written order was issued by the TRA in June 2012.

October 2015.


All States


Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. InThis sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which2015, 2014 and 2013 is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2010, we generated $42.8 million of margin from secondary market activity, $32.1 million of which is allocated to customers as gas cost reductions and $10.7 million as margin allocated to us.

presented below.

In millions 2015 2014 2013
Allocated to customers as gas cost reductions $60.1
 $72.2
 $26.9
Margin allocated to us 21.1
 25.4
 9.0
Margin from secondary market activity $81.2
 $97.6
 $35.9


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We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas intofor transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

3.


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. SharesIn the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans and forward sale agreements (FSAs) are contingently issuable shares, as determined by applying the treasury stock method, and are includedadded to average common shares outstanding, resulting in our calculation of fullya potential reduction in diluted earnings per share.

EPS.


A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest and FSAs settle, for the years ended October 31, 2012, 20112015, 2014 and 20102013 is presented below.

In thousands except per share amounts

  

2012

   

2011

   

2010

 

Net Income

    $    119,847      $    113,568      $    141,954  
  

 

 

   

 

 

   

 

 

 

Average shares of common stock outstanding for basic earnings per share

   71,977     72,056     72,275  

Contingently issuable shares under incentive compensation plans

   301     210     250  
  

 

 

   

 

 

   

 

 

 

Average shares of dilutive stock

   72,278     72,266     72,525  
  

 

 

   

 

 

   

 

 

 

Earnings Per Share of Common Stock:

      

Basic

    $1.67      $1.58      $1.96  

Diluted

    $1.66      $1.57      $1.96  

4.

In thousands, except per share amounts 2015 2014 2013
Net Income $137,011
 $143,801
 $134,417
       
Average shares of common stock outstanding for basic earnings per share 78,942
 77,883
 74,884
Contingently issuable shares under incentive compensation plans 289
 310
 289
Contingently issuable shares under forward sale agreements —
 —
 160
Average shares of dilutive stock 79,231
 78,193
 75,333
       
Earnings Per Share of Common Stock:      
Basic $1.74
 $1.85
 $1.80
Diluted $1.73
 $1.84
 $1.78

5. Long-Term Debt


Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and medium-term notes: Series A, Series B, Series C and Series E, which wesenior notes issued under an indenture dated April 1, 1993.indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-termNone of our debt is actively traded.

As of October 31, 2015, we early adopted the accounting standard requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt, consistent with the presentation of debt discounts. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 20122015 and 2011 is as follows.

In thousands          2012                   2011         

Senior Notes:

    

  2.92%, due June 6, 2016

    $40,000      $40,000  

  8.51%, due September 30, 2017

   35,000     35,000  

  4.24%, due June 6, 2021

   160,000     160,000  

  3.47%, due July 16, 2027

   100,000     -   

  3.57%, due July 16, 2027

   200,000     -   

Medium-Term Notes:

    

  5.00%, due December 19, 2013

   100,000     100,000  

  6.87%, due October 6, 2023

   45,000     45,000  

  8.45%, due September 19, 2024

   40,000     40,000  

  7.40%, due October 3, 2025

   55,000     55,000  

  7.50%, due October 9, 2026

   40,000     40,000  

  7.95%, due September 14, 2029

   60,000     60,000  

  6.00%, due December 19, 2033

   100,000     100,000  
  

 

 

   

 

 

 

    Total

   975,000     675,000  

Less current maturities

   -      -   
  

 

 

   

 

 

 

    Total

    $975,000      $675,000  
  

 

 

   

 

 

 

2014.


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  Long-Term Debt as of October 31, 2015
In thousands Principal Unamortized Debt Issuance Expenses and Discounts Total
Senior Notes:      
2.92%, due June 6, 2016 $40,000
 $(40) $39,960
8.51%, due September 30, 2017 35,000
 —
 35,000
4.24%, due June 6, 2021 160,000
 (752) 159,248
3.47%, due July 16, 2027 100,000
 (638) 99,362
3.57%, due July 16, 2027 200,000
 (1,307) 198,693
4.10%, due September 18, 2034 250,000
 (2,644) 247,356
4.65%, due August 1, 2043 300,000
 (3,040) 296,960
  3.60%, due September 1, 2025 150,000
 (1,382) 148,618
Medium-Term Notes:     

6.87%, due October 6, 2023 45,000
 (115) 44,885
8.45%, due September 19, 2024 40,000
 (115) 39,885
7.40%, due October 3, 2025 55,000
 (171) 54,829
7.50%, due October 9, 2026 40,000
 (126) 39,874
7.95%, due September 14, 2029 60,000
 (273) 59,727
6.00%, due December 19, 2033 100,000
 (720) 99,280
Total 1,575,000
 (11,323) 1,563,677
Less current maturities 40,000
 —
 40,000
Total $1,535,000
 $(11,323) $1,523,677

  Long-Term Debt as of October 31, 2014
In thousands Principal Unamortized Debt Issuance Expenses and Discounts Total
Senior Notes:      
2.92%, due June 6, 2016 $40,000
 $(107) $39,893
8.51%, due September 30, 2017 35,000
 —
 35,000
4.24%, due June 6, 2021 160,000
 (887) 159,113
3.47%, due July 16, 2027 100,000
 (693) 99,307
3.57%, due July 16, 2027 200,000
 (1,418) 198,582
4.10%, due September 18, 2034 250,000
 (2,644) 247,356
4.65%, due August 1, 2043 300,000
 (3,132) 296,868
Medium-Term Notes:      
6.87%, due October 6, 2023 45,000
 (129) 44,871
8.45%, due September 19, 2024 40,000
 (127) 39,873
7.40%, due October 3, 2025 55,000
 (189) 54,811
7.50%, due October 9, 2026 40,000
 (138) 39,862
7.95%, due September 14, 2029 60,000
 (292) 59,708
6.00%, due December 19, 2033 100,000
 (760) 99,240
Total 1,425,000
 (10,516) 1,414,484
Less current maturities —
 —
 —
Total $1,425,000
 $(10,516) $1,414,484

78



Current maturities for the next five years ending October 31 and thereafter are as follows.

In thousands    

2013

    $-   

2014

   100,000  

2015

   -   

2016

   40,000  

2017

   35,000  

Thereafter

   800,000  
  

 

 

 

  Total

    $    975,000  
  

 

 

 

Payments of $.1 million in 2011 were paid to noteholders of the 6.25% insured quarterly notes based on a redemption right upon the death of the owner of the notes, within specified limitations. On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes, which

In thousands 
2016$40,000
201735,000
2018—
2019—
2020—
Thereafter1,500,000
Total$1,575,000

We had an aggregate principal balance of $196.8 million. We retired the balance of $60 million of our 6.55% medium-term notes in September 2011, as they became due.

On June 6, 2011, we issued $40 million unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term debt used to finance the redemption of the 6.25% insured quarterly notes, as well as for other general corporate purposes and working capital needs.

On July 16, 2012, we issued $100 million of senior notes with an interest rate of 3.47%. On October 15, 2012, we issued $200 million of senior notes with an interest rate of 3.57%. Both issuances will mature on July 16, 2027. These proceeds were used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.

We have an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that iswas available for future use.use until its expiration date of July 6, 2014. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 7 to the consolidated financial statements.


In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC has approved debt and equity issuances under this shelf registration statement up to $1 billion during its three-year life. As of October 31, 2015, we have $544.1 million remaining for debt and equity issuances as approved by the NCUC. 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, includingpurposes.

On September 18, 2014, we issued $250 million of twenty-year, unsecured senior notes with an interest rate of 4.10% and at a discount of .174% or $435,000 under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to March 18, 2034, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after March 18, 2034, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $247.7 million from this issuance to finance capital expenditures, additions to working capital and advances forrepay outstanding short-term, unsecured notes under our investments in our subsidiaries,CP program and for repurchasesgeneral corporate purposes.

On September 14, 2015, we issued $150 million of sharesten-year, unsecured senior notes with an interest rate of our common stock. Pending such use, we may temporarily invest3.60% and at a discount of .065% or $97,500 under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to June 1, 2025, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after June 1, 2025, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds that are not appliedof $148.9 million from this issuance to the purposes mentioned above in investment grade securities.

finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.


The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31, 2012,2015, our retainednet earnings were not restricted as the amount available for restricted payments was greater than our actual retained earnings as presented below.

In thousands

    

Amount available for restricted payments

  $619,375 

Retained earnings

   584,848 

were $1.2 billion.


We are subject to default provisions related to our long-term debt and short-term debt. Since there are cross default provisions in all of our debt agreements, failureborrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements. As of October 31, 2012,2015, we are in compliance with all default provisions.

5.



79


The default provisions of some or all of our senior debt include:

Failure to make principal or interest payments,
Bankruptcy, liquidation or insolvency,
Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
Specified events under the Employee Retirement Income Security Act of 1974,
Change in control, and
Failure to observe or perform covenants, including:
Interest coverage of at least 1.75 times. Interest coverage was 3.96 times as of October 31, 2015;
Funded debt cannot exceed 70% of total capitalization. Funded debt was 57% of total capitalization as of October 31, 2015;
Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2015;
Restrictions on permitted liens;
Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.

6. Short-Term Debt Instruments

On


At October 1, 2012,31, 2015, we amended and restated our $650 million three-year revolving syndicated credit facility as a $650have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. The amended and restated facility has an option to request an expansion of up to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $650 million.amount. The facility provides a line of credit for letters of credit of $10 million, of which $3.6$1.6 million wasand $1.8 million were issued and outstanding at October 31, 2012. The facility as in effect prior to the amendment2015 and restatement also provided a line of credit for letters of credit of $10 million, of which $3.5 million was issued and outstanding at October 31, 2011.2014, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile

liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. DueSee Note 5 to the seasonal natureconsolidated financial statements for discussion of default provisions, including cross default provisions, in all of our business, amounts borrowed can vary significantly duringdebt agreements.


On December 14, 2015, we entered into an agreement with the year.

On March 1, 2012, we established a $650lenders under our existing $850 million five-year revolving syndicated credit facility to amend and extend the facility at substantially similar terms to our existing facility. The amended facility extended the maturity of our facility to December 14, 2020. The amended facility expressly permits the Acquisition by Duke Energy. The CP program will continue to be backstopped by the new credit facility.


We have an $850 million unsecured commercial paper (CP)CP program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million unless$850 million. The notes issued under the optionCP program may have maturities not to expandexceed 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 facility is exercised as discussed above.ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt. The notes under the CP program are not registered and are being offered and issued pursuant to an exemption from registration.

Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.


As of October 31, 2012,2015, we have $365had $340 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets, with original maturities ranging from 7 to 1514 days from their dates of issuance at a weighted average interest rate of .42%.22%.

Our As of October 31, 2014, our outstanding short-term bank borrowings, asnotes under the CP program, included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets as stated above, were $331$355 million as of October 31, 2011 under the revolving syndicated credit facility as in effect prior to the amendment and restatement in LIBOR cost-plus loans at a weighted average interest rate of .94%.17%.


We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2015. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 20122015 is as follows.

Short-Term Debt Activity

           Credit                  Commercial                  Total         

In thousands

          Facility                  Paper                  Borrowings         

      Minimum amount outstanding(1)

    $-      $-     $328,500  

      Maximum amount outstanding(1)

    $    475,500     $    535,000    $    535,000  

      Minimum interest rate(2)

   1.15 %   .22 %   .22 % 

      Maximum interest rate

   1.20 %   .45 %   1.20 % 

      Weighted average interest rate

   1.17 %   .38 %   .66 % 

      (1)  During March 2012, we were borrowing under both the credit facility and CP program for a portion of the month.

        

      (2)  This is the minimum rate when we were borrowing under the credit facility and/or CP program.

        


80


In thousands 
      Minimum amount outstanding$230,000
      Maximum amount outstanding$580,000
      Minimum interest rate.15%
      Maximum interest rate.30%
      Weighted average interest rate.21%

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 57% at October 31, 2012.

6. 2015.


7. Stockholders’ Equity

Capital Stock and Accelerated Share Repurchase


Changes in common stock for the years ended October 31, 2012, 20112015, 2014 and 20102013 are as follows.

In thousands

      Shares             Amount       

Balance, October 31, 2009

   73,266    $471,569  

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

   35     899  

  Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)

   676     17,663  

  Issued to participants in the Incentive Compensation Plan (ICP)

   106     2,804  

  Shares repurchased under Accelerated Share Repurchase (ASR) agreement

   (1,800)     (47,276)  

  Shares repurchased under rescission offer

   (1)     (19)  
  

 

 

   

 

 

 

Balance, October 31, 2010

   72,282     445,640  

  Issued to ESPP

   30     870  

  Issued to DRIP

   657     18,834  

  Issued to ICP

   149     4,451  

  Shares repurchased under ASR agreement

   (800)     (23,004)  
  

 

 

   

 

 

 

Balance, October 31, 2011

   72,318     446,791  

  Issued to ESPP

   30     894  

  Issued to DRIP

   677     20,508  

  Issued to ICP

   25     796  

  Shares repurchased under ASR agreement

   (800)     (26,528)  
  

 

 

   

 

 

 

Balance, October 31, 2012

   72,250    $442,461  
  

 

 

   

 

 

 

In thousands     Shares           Amount      
Balance, October 31, 2012 72,250
 $442,461
Issued to participants in the Employee Stock Purchase Plan (ESPP) 33
 1,056
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) 720
 22,791
Issued to participants in the Incentive Compensation Plan (ICP) 96
 3,065
Issuance of common stock through public share offering, net of underwriting fees 3,000
 92,640
  Costs from issuance of common stock —
 (369)
Balance, October 31, 2013 76,099
 561,644
Issued to ESPP 34
 1,143
Issued to DRIP 698
 23,443
Issued to ICP 100
 3,315
Issuance of common stock through forward sale agreements, net of expenses 1,600
 47,290
Balance, October 31, 2014 78,531
 636,835
Issued to ESPP 31

1,239
Issued to DRIP 669

24,679
Issued to ICP 130

4,964
Issuance of common stock through forward sale agreements, net of expenses 1,522

53,702
Balance, October 31, 2015 80,883
 $721,419

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are cancelledcanceled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.


On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved at that time an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASRaccelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.


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 4, 2012,7, 2015, we entered into an ASR agreement where separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements,

81


we purchased 800,000may 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 beginning January 7, 2015 and 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 an investment bankthird parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. We expect to enter into separate FSAs each fiscal quarter during the term of the Sales Agreements and have done so in our second, third and fourth quarters of 2015.

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

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

Under a FSA that daywe executed with JP Morgan on June 8, 2015, 795,529 shares were borrowed from third parties and sold by JP Morgan, from June 10, 2015 to July 30, 2015, at a weighted average share price of $33.77 per share. The settlement$36.42, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $35.87.

Under a FSA that we executed with Merrill on September 8, 2015, 114,500 shares were borrowed from third parties and retirementsold by Merrill, from September 9, 2015 to September 15, 2015, at a weighted average share price of those$36.58, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $36.03.

Under the terms of these FSAs, at our election, we could physically settle in shares, occurred on January 5, 2012. Total consideration paidcash or net settle for all or a portion of our obligation under the agreements any time prior to purchase theDecember 15, 2015.

On October 29, 2015, we issued 1.5 million shares of $27 million wasour common stock to the forward counterparties by physically settling all of the FSAs entered into during 2015 and received net proceeds of $54.1 million. We recorded this amount in “Stockholders’ equity”"Stockholders' equity" as a reduction in “Common stock”an addition to "Common stock" in the Consolidated Balance Sheets.

As part of Upon settlement, we used the ASR,net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.


On January 29, 2013, we simultaneously entered into a forward sale contract with the investment bank that was expectedan underwriting agreement under our open combined debt and equity shelf registration statement to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the investment bank was requiredsell up to purchase, in the open

market, 800,0004.6 million shares of our common stock duringof which 3 million direct shares were issued and settled on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the termunderwriters at the net price of $30.88 per share, the contract to fulfill its obligation relatedoffering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.


The remaining 1.6 million shares itunder this same underwriting agreement were under FSAs with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to us. At settlement, we,the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid-December 2013. Under the terms of these FSAs, at our option, were required to either payelection, we could physically settle in shares, cash or issuenet share settle for all or a portion of our obligation under the agreements.

On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the investment bank ifforward counterparty and received net proceeds of $47.3 million based on the investment bank’s weighted average purchasenet settlement price of $30.88 per share, the original offering price, less a $.09 per share discount, was higher than the January 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on February 28, 2012, we received $.5 million from the investment bank andcertain adjustments. We recorded this amount in “Stockholders’ equity”"Stockholders' equity" as an addition to “Common stock”"Common stock" in the Consolidated Balance Sheets. The $.5 millionUpon settlement, we used the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.


82


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

Upon physical settlement of the investment bank’s weightedFSAs, delivery of our shares resulted in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average purchasemarket price of $33.25 per share less a discount of $.09our common stock was above the per share adjusted forward sale price described above. See Note 4 to the consolidated financial statements for a settlement pricethe dilutive effect of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares. We had ASR transactions in 2011 and 2010 as presented in the table above with similar structuresFSAs on our EPS at October 31, 2013 with the investment bank, which were accounted forinclusion of the incremental shares in our average shares of dilutive stock as calculated under the same manner.

treasury stock method.


As of October 31, 2012, our2015, shares of common stock were reserved for future issuance under various plans are as follows.

In thousands

ESPP

In thousands		 
ESPP243 145

DRIP

171754 *

ICP

8201,146 
Total1,136

  Total

        2,143 


* On November


Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 13 2012, 754,000 sharesto the consolidated financial statements. Changes in each component of common stock under our 2009 Registration Statementaccumulated OCIL are presented below for the DRIP that remained unsold at the terminationyears ended October 31, 2015 and 2014.
Changes in Accumulated OCIL (1)
     
In thousands 2015 2014
Accumulated OCIL beginning balance, net of tax $(237) $(284)
Hedging activities of equity method investments:    
  OCIL before reclassifications, net of tax (1,601) 355
  Amounts reclassified from accumulated OCIL, net of tax 1,018
 (284)
  Total current period activity of hedging activities of equity method investments, net of tax (583) 71
Net current period benefit activities of equity method investments, net of tax (35) (24)
Accumulated OCIL ending balance, net of tax $(855)
$(237)
(1) Amounts in parentheses indicate debits to accumulated OCIL.

A reconciliation of the offering have been removed from registration. Oneffect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the same day, a Registration Statement was filed registering 2,250,000 shares of our common stock for issuance under the DRIP.

7.years ended October 31, 2015 and 2014.

  
Reclassification Out of
Accumulated OCIL (1)
  
   
  Years Ended  
  October 31 
Affected Line Items on Statement of
 Comprehensive Income
In thousands 2015 2014 
Hedging activities of equity method investments $1,670
 $(461) Income from equity method investments
Income tax expense (652) 177
 Income taxes
   Net hedging activities 1,018
 $(284)  
Net benefit activities of equity method investments (58) (40) Income from equity method investments
Income tax expense 23
 16
 Income taxes
   Net benefit activities (35) (24)  
Total reclassification for the period, net of tax $983
 $(308)  
(1) Amounts in parentheses indicate debits to accumulated OCIL.

83



8. Financial Instruments and Related Fair Value


Derivative Assets and Liabilities under Master Netting Arrangements


We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments and the fair value of the right to reclaim cash collateral.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 October 31, 20122015 and 2011,2014, we had long gas purchase options providing total coverage of 35.834.7 million dekatherms and 38.129.2 million dekatherms, respectively. The long gas purchase options held at October 31, 20122015 are for the period from December 20122015 through October 2013.

2016.


Fair Value Measurements


We use financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those 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.


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 October 31, 20122015 and 2011.2014. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 20122015 and 2011.

Recurring Fair Value Measurements as of October 31, 2012 
           Significant             
       Quoted Prices           Other           Significant         
       in Active           Observable           Unobservable           Total     
       Markets           Inputs           Inputs           Carrying     
In thousands      (Level 1)           (Level 2)           (Level 3)           Value     

Assets:

        

Derivatives held for distribution operations

  $3,153    $-     $-     $3,153  

Debt and equity securities held as trading securities:

        

  Money markets

   243     -      -      243  

  Mutual funds

   2,045     -      -      2,045  
  

 

 

   

 

 

   

 

 

   

 

 

 

  Total fair value assets

  $5,441    $-     $-     $5,441  
  

 

 

   

 

 

   

 

 

   

 

 

 

Recurring Fair Value Measurements as of October 31, 2011 
           Significant             
       Quoted Prices           Other           Significant         
       in Active           Observable           Unobservable           Total     
       Markets           Inputs           Inputs           Carrying     
In thousands      (Level 1)           (Level 2)           (Level 3)           Value     

Assets:

        

Derivatives held for distribution operations

  $2,772    $-     $-     $2,772  

Debt and equity securities held as trading securities:

        

  Money markets

   217     -      -      217  

  Mutual funds

   1,274     -      -      1,274  
  

 

 

   

 

 

   

 

 

   

 

 

 

  Total fair value assets

  $4,263    $-     $-     $4,263  
  

 

 

   

 

 

   

 

 

   

 

 

 

2014. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.

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


84


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

Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net costs and the 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 “Current Liabilities” or “Amounts due from customers” in “Current Assets” inNote 3 to the Consolidated Balance Sheets.consolidated financial statements. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.


Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the 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 recorded at unamortized cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury bench markbenchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances.ratings. The carrying amountprincipal and fair value of our long-term debt, which is classified within Level 2, are shown below.

   Carrying     
In thousands  Amount   Fair Value 

As of October 31, 2012

  $    975,000   $    1,163,227 

As of October 31, 2011

   675,000    831,323 

In thousands Principal Fair Value
As of October 31, 2015 $1,575,000
 $1,720,586
As of October 31, 2014 1,425,000
 1,617,453
Quantitative and Qualitative Disclosures


The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts areof our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and do not reflect any netting of asset and liability amounts orwe have posted no cash collateral amountsnor received any cash collateral under our master netting arrangements.

arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.



85


The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 20122015 and 2011.

Fair Value of Derivative Instruments
In thousands20122011

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:

Asset Financial Instruments:

  Current Assets - Gas purchase derivative assets (December 2012 - October 2013)

$    3,153 

  Current Assets - Gas purchase derivative assets (December 2011 - October 2012)

$    2,772 

2014.

Fair Value of Derivative Instruments
     
In thousands 2015 2014
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:    
Current Assets - Gas purchase derivative assets (December 2015 - October 2016) $1,343
  
Current Assets - Gas purchase derivative assets (December 2014 - November 2015)   $4,898

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs isare to use these financial instruments to provide some level of protection against significant price increases.reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially recordeddeferred as a component of deferred gas costsamounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” as presented in Note 3 to the consolidated financial statements and recognized in the Consolidated Statements of Comprehensive Income as a component of cost“Cost of gasGas” when the related costs are recovered through our rates.


The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 20122015 and 2011,2014, absent the regulatory treatment under our approved PGA procedures.

                   Location of Loss 
   Amount of Loss Recognized   Amount of Loss Deferred   Recognized through 
In thousands  on Derivative Instruments   Under PGA Procedures   PGA Procedures 
   Twelve Months Ended       Twelve Months Ended         
   October 31       October 31         
       2012           2011           2012           2011         

Gas purchase options

  $        8    $        10    $        8    $        10     Cost of Gas   

  Amount of Amount of Location of Gain (Loss)
  Gain (Loss) Recognized Gain (Loss) Deferred Recognized through
  on Derivative Instruments Under PGA Procedures PGA Procedures
       
  Twelve Months Ended     Twelve Months Ended      
  October 31     October 31      
In thousands 2015 2014 2015 2014  
Gas purchase options $(4,423) $6,162
 $(4,423) $6,162
 Cost of Gas 

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


Credit and Counterparty Risk

We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.

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 Consolidated Balance Sheets attributable to these entities amounted to $2.9 million, or approximately 5% of our gross trade accounts receivable at October 31, 2015. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

86



We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2015, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.

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 anthe direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management program. In addition, we have anprogram, including our Energy Price Risk Management Committee that monitors complianceCommittee. Risk management is guided by senior management with our hedging programs,Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

8.


9. Commitments and Contingent Liabilities


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.


Operating lease payments for the years ended October 31, 2012, 20112015, 2014 and 20102013 are as follows.

In thousands      2012           2011           2010     

Operating lease payments(1)

  $3,712    $4,496    $5,303  

(1)

Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

In thousands
2015 2014 2013
Operating lease payments (1)

$5,024
 $4,701
 $4,729
(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

In thousands

    

2013

  $4,265  

2014

   4,186  

2015

   3,984  

2016

   3,939  

2017

   3,739  

Thereafter

   31,895  
  

 

 

 

  Total

  $        52,008  
  

 

 

 

In thousands 
2016$5,052
20174,706
20184,609
20194,433
20204,477
Thereafter24,413
Total$47,690


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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 generally fully recoverable through 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 under gas supply contracts are up to one year.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 fourfive years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.


Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC)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 Consolidated Statements of Comprehensive Income as part of gas purchases and included in cost“Cost of gas.

Gas.”


As of October 31, 2012,2015, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

       Pipeline and               Telecommunications             
       Storage               and Information             
In thousands          Capacity               Gas Supply           Technology           Other               Total         

2013

    $152,163      $6,149      $9,459      $28,798     $196,569  

2014

   140,767     -      8,513     -     149,280  

2015

   132,450     -      3,171     -     135,621  

2016

   76,007     -      560     -     76,567  

2017

   61,006     -      -      -     61,006  

Thereafter

   286,373     -      -      -     286,373  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Total

    $    848,766      $    6,149      $    21,703      $    28,798     $    905,416  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Pipeline Gas Supply Gas Supply Telecommunications    
  and Storage Reservation Purchase and Information    
In thousands Capacity         Fees Commitments Technology     Other     Total        
2016 $178,594
 $4,577
 $65,286
 $6,164
 $45,577
 $300,198
2017 163,806
 165
 89,784
 1,639
 —
 255,394
2018 143,728
 —
 69,569
 669
 —
 213,966
2019 132,259
 —
 69,569
 610
 —
 202,438
2020 114,400
 —
 69,759
 —
 —
 184,159
Thereafter 516,333
 —
 707,698
 —
 —
 1,224,031
Total $1,249,120
 $4,742
 $1,071,665
 $9,082
 $45,577
 $2,380,186

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 $3.6$1.6 million in letters of credit that were issued and outstanding at October 31, 2012.2015. Additional information concerning letters of credit is included in Note 56 to the consolidated financial statements.


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 October 31, 2015, we had open surety bonds with a total contingent obligation of $6.6 million.


88


Environmental Matters


Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental costs.assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and forhave recorded estimated environmental liabilities, recorded.

including those for our manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).


In October 2007,1997, we entered into a settlement with a third-party with respect to nine manufactured gas plant (MGP)MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.


In connection with theour 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly ownedwholly-owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy, Corporation (DEC), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

There are four other


As of October 31, 2015, our estimated undiscounted environmental liability totaled $1.2 million, and consisted of $1.1 million for MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and for which we have an investigationretain responsibility and remediation liability. In fiscal year 2012,$.1 million for the Huntersville LNG facility. The costs we have performed soil remediation work at our Reidsville site. In July 2012,reasonable expect to incur are estimated using assumptions based on actual costs incurred, the North Carolina Departmenttiming of Environmentfuture payments and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which included installing five monitoring wells in September 2012. The water samples from these wells yielded uncontaminated groundwater. We will submit a no further action request to the NCDENR.inflation factors, among others. We have incurred $.6$2.2 million of remediation costs at the Reidsville site through October 31, 2012.

As part of a voluntary agreement with the NCDENR, we conductedrelated to our MGP sites and completed soil remediation for the Hickory, North Carolina MGP site in 2010. A Phase II groundwater investigation was conducted in 2011. A groundwater remedial action plan was submitted and approved by NCDENR in 2012. We continue$4.8 million related to conduct quarterly groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.4 million of remediation costs at this site through October 31, 2012.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been completed, and a final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. We have incurred $1.5 million of remediation costs at this site through October 31, 2012.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the site for this issue. In September 2011, we received a letter from the NCDENR indicating their desire


We continue to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. On April 11, 2012, we entered into a no admit/no deny ACO that imposed a fine of $40,000, unpaid annual fees totaling $18,000 and $1,860 for investigative and administrative costs. As part of the ACO, we are required to develop a site assessment plan to determine the extent of the groundwater contamination related to the sieve burial, a groundwater remediation strategy and a groundwater and surface water site-wide monitoring program. Upon acceptance by the NCDENR of the groundwater remediation plan, we will then be required to develop a program for implementation of the plan within thirty days. Site assessment activities began in July 2012 for the groundwater remediation at this site.

The Huntersville LNG facility was originally coated with lead-based paint. As a precautionary measure to ensure that no lead contamination occurs, removal of lead-based paint from the site was initiated in spring 2010. The last phase of the lead-based paint removal began in July 2012 on the LNG tank and rafters in a nearby building and will continue into fiscal 2013. We have incurred $3.9 million of remediation costs through October 31, 2012 for all issues at the Huntersville LNG plant site. Once the lead-based paint is removed atexpand our Huntersville LNG facility, we expect there will be no potential environmental or employee exposures.

Our Nashville LNG facility was also originally coated with lead-based paint. We completed the remediation of the facility in May 2012 and incurred $.5 million of remediation costs.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina resource center continues to operate USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina resource centers had their tanks removed, and we do not anticipate significant environmental remediation with respect to the removal process. The South Carolina Department of Health and Environmental Control (SCDHEC) requested that we conduct an initial groundwater assessment at our Greenville, South Carolina site to determine its current groundwater quality condition. This assessment was conducted in August 2012, and in November 2012, we received a determination letter from the SCDHEC that no further groundwater remediation would be required at the site for this issue.

In July 2005, we were notified by the NCDENR that we were named as a potentially responsible party for alleged environmental issues associated with a propane UST site in Clemmons, North Carolina. We owned and operated this site from March 1986 until June 1988 in connection with a non-utility venture. There have been at least four owners of the site. We contend that we contractually transferred any and all clean-up costs to the new owner of the site when we sold this venture in June 1988. However, the owners that purchased the property contend that we only transferred the clean-up costs associated with the gasoline pumps and not the USTs. It is unclear of the outcome of this case and how many of the former owners may ultimately be held liable for this site. Based on the uncertainty of the ultimate liability, we established an immaterial non-regulated environmental liability for one-fourth of the estimated cost to remediate the site.

Onesampling of our resource centers haspipelines for coatings containing asbestos on some of their pipelines. We have educatedasbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline, which generally occur only in small increments.

For all the matters discussed above, as of October 31, 2012, our estimated undiscounted environmental liability totaled $2.1 million, and consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.4 million for the LNG facilities, $.3 million for the groundwater remediation at the Huntersville LNG site and $.3 million for USTs not yet remediated. 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.

pipeline.


As of October 31, 2012,2015, our regulatory assets for unamortized environmental costs in our three statethree-state territory totaled $10.2$6.6 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight yeareight-year period beginning March 2012, pursuant to the recent2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings.

The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.1 million of our deferred South Carolina environmental costs over a one-year period beginning November 2014, pursuant to the annual rate stabilization order issued in October 2014.


Further evaluation of the MGP, LNG and UST sites and removal of lead-based paint at our LNG site 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.

9.


10. Employee Benefit Plans


Under accounting guidance, we are required to recognize all obligations related to defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OBEBOPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Our plans’ assets are required to be accounted for at fair value.



89


Pension Benefits


We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.


The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.


Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:


Achieve full funding over the longer term, and
•Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.


We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.


The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.


The qualified pension plan maintains a 45% target allocation to fixedthe following types of investments:

Fixed income securities, includingsecurities: includes U.S. treasuries, corporate bonds, high yield bonds,debt (bank loans), asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to
Equity securities: includes large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in
Real estate: includes a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including
Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies.



90


The target and actual allocations of the qualified pension plan's assets are as follows:
  Target Assets at October 31
Asset Allocations Allocation 2015 2014
Fixed income securities 45% 46% 45%
Equity securities 35% 34% 31%
Real estate 5% 5% 5%
Cash and cash equivalents —% 1% 8%
Other investments 15% 14% 11%
Total 100% 100% 100%

Employees hired or rehired after December 31, 2007 (or December 31, 2008 for employees covered by the bargaining unit contract in Nashville, Tennessee) cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s

compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2012,2015, 2014 and 2013 we contributed $.5$1.4 million, $.9 million and $.7 million, respectively, to the MPP plan.


OPEB Plan


We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. EffectiveEmployees hired after January 1, 2008 (January 1, 2009 for new employees covered under the bargaining unit contract in Nashville, Tennessee), new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after Julybenefit of $15,000.

In September 2015, we announced the replacement of the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA), effective January 1, 2005, this benefit is $15,000.2016. 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 expenses. The life insurance amount for employees who retired priorimpact of the amendment was not material to this date was calculated as a percentage of their basic life insurance prior to retirement.

us.


OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the qualified pension plan as discussed above. We target anabove, except the OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash.portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.



91


The target and actual allocations of the OPEB plan's assets are as follows:
  Target  Assets at October 31
Asset Allocations Allocation  2015 2014
Fixed income securities 45%
(1) 
 47% 44%
Equity securities 47%  44% 42%
Real estate 5%  5% 5%
Cash and cash equivalents 3%  4% 9%
Total 100%  100% 100%
(1) Includes 5% target allocation to high yield fixed income.

Supplemental Executive Retirement Plans


We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.


We have a non-qualified defined contribution restoration plan (DCR plan) for certain Company officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the

one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP. If the officer severs employment before the expiration of the relevant five-year period, he or she receives nothing from that portion of the DCR plan.contributions. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.


We have a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan (VDP), are also informally funded monthly through a rabbi trust with a bank as the trustee. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral PlanVDP on a specified date that is at least two years from the date of deferral, a change in control, on separation of service or upon death.

The


Our funding to the DCR plan accountsaccount for the years ended October 31, 20122015 and 2011,2014, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 20122015 and 20112014, are presented below.

In thousands      2012           2011     

Funding

  $422    $352  

Liability:

    

  Current

   160     52  

  Noncurrent

   2,412     1,766  

In thousands 2015 2014
Funding $548
 $524
Liability:    
Current 236
 214
Noncurrent 5,089
 4,248

We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed, as grossed up for taxes to the individual officer.expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.

In thousands      2012           2011           2010     

Term life policies of certain officers at the vice president level and above

  $43    $56    $57  

Officers and director-level employees

   25     24     24  

In thousands 2015 2014 2013
Term life policies of certain officers at the vice president level and above $35
 $30
 $27
Officers and director-level employees 30
 32
 28


92


Actuarial Plan Information


A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 20122015 and 2011, and2014, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 20122015 and 20112014, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2015 and 2014 are presented below.

       Qualified Pension           Nonqualified Pension           Other Benefits     
In thousands        2012               2011             2012       2011       2012       2011   

Accumulated benefit obligation at year end

    $245,361      $205,159      $5,569      $5,219         N/A             N/A      
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Change in projected benefit obligation:

            

  Obligation at beginning of year

    $236,632      $211,003      $5,219      $5,039      $31,900      $31,919  

  Service cost

   9,573     8,508     39     45     1,387     1,398  

  Interest cost

   10,640     11,024     203     209     1,347     1,495  

  Plan amendments

   -      -      -      290     -      -   

  Actuarial (gain) loss

   54,852     16,896     629     130     2,630     (327)  

  Participant contributions

   -      -      -      -      788     898  

  Administrative expenses

   (420)     (391)     -      -      -      -   

  Benefit payments

   (17,950)     (10,408)     (521)     (494)     (3,222)     (3,483)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Obligation at end of year

   293,327     236,632         5,569         5,219         34,830         31,900  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Change in fair value of plan assets:

            

  Fair value at beginning of year

   259,511     228,345     -      -      22,045     21,636  

  Actual return on plan assets

   31,196     19,965     -      -      1,972     792  

  Employer contributions

   -      22,000     521     494     2,080     2,202  

  Participant contributions

   -      -      -      -      788     898  

  Administrative expenses

   (420)     (391)     -      -      -      -   

  Benefit payments

   (17,950)     (10,408)     (521)     (494)     (3,222)     (3,483)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Fair value at end of year

       272,337     259,511     -      -      23,663     22,045  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Funded status at year end - (under) over

    $(20,990)      $22,879      $(5,569)      $(5,219)      $(11,167)      $(9,855)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Noncurrent assets

    $-       $22,879      $-       $-       $-       $-   

  Current liabilities

   -      -      (502)     (517)     -      -   

  Noncurrent liabilities

   (20,990)     -      (5,067)     (4,702)     (11,167)     (9,855)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Net amount recognized

    $(20,990)      $22,879    $(5,569)      $(5,219)      $(11,167)      $(9,855)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred

            

  Regulatory Account:

            

    Unrecognized transition obligation

    $-       $-       $-       $-       $(667)      $(1,334)  

    Unrecognized prior service (cost) credit

   19,441     21,638     (277)     (358)     -      -   

    Unrecognized actuarial loss

   (137,633)     (99,653)     (1,521)     (941)     (2,633)     (424)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

    Regulatory asset

   (118,192)     (78,015)     (1,798)     (1,299)     (3,300)     (1,758)  

    Cumulative employer contributions in excess of cost

   97,202         100,894     (3,771)     (3,920)     (7,867)     (8,097)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

    Net amount recognized

    $(20,990)       $22,879      $(5,569)      $(5,219)      $(11,167)      $(9,855)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Qualified Pension Nonqualified Pension Other Benefits
In thousands 2015 2014 2015 2014 2015 2014
Accumulated benefit obligation at year end $263,120
 $252,706
 $5,527
 $5,925
 N/A    
 N/A    
             
Change in projected benefit obligation: 
   
   
  
Obligation at beginning of year $302,686
 $272,403
 $5,925
 $4,736
 $37,817
 $33,678
Service cost 11,403
 10,865
 —
 —
 1,182
 1,109
Interest cost 12,018
 11,781
 209
 200
 1,475
 1,448
Plan amendments —
 —
 —
 485
 (1,877) —
Actuarial (gain) loss 3,524
 23,646
 (100) 956
 1,697
 3,734
Participant contributions —
 —
 —
 —
 611
 805
Administrative expenses (590) (465) —
 —
 —
 —
Benefit payments (17,504) (15,544) (507) (452) (3,348) (2,957)
Obligation at end of year 311,537
 302,686
 5,527
 5,925
 37,557
 37,817
Change in fair value of plan assets: 
   
   
  
Fair value at beginning of year 336,443
 300,661
 —
 —
 27,747
 25,961
Actual return on plan assets 958
 31,791
 —
 —
 315
 1,874
Employer contributions 10,000
 20,000
 507
 452
 2,221
 2,064
Participant contributions —
 —
 —
 —
 611
 805
Administrative expenses (590) (465) —
 —
 —
 —
Benefit payments (17,504) (15,544) (507) (452) (3,348) (2,957)
Fair value at end of year 329,307
 336,443
 —
 —
 27,546
 27,747
Funded status at year end - over (under) $17,770
 $33,757
 $(5,527) $(5,925) $(10,011) $(10,070)
             
Noncurrent assets $17,770
 $33,757
 $—
 $—
 $—
 $—
Current liabilities —
 —
 (520) (521) —
 —
Noncurrent liabilities —
 —
 (5,007) (5,404) (10,011) (10,070)
Net amount recognized $17,770
 $33,757
 $(5,527) $(5,925) $(10,011) $(10,070)
             
Amounts Not Yet Recognized as a Component            
of Cost and Recognized in a Deferred            
Regulatory Account:            
Unrecognized prior service credit (cost) $12,848
 $15,046
 $(208) $(439) $1,877
 $—
Unrecognized actuarial loss (120,541) (103,038) (1,560) (1,745) (7,185) (3,995)
Regulatory asset (107,693) (87,992) (1,768) (2,184) (5,308) (3,995)
Cumulative employer contributions in 
















  excess of cost 125,463
 121,749
 (3,759) (3,741) (4,703) (6,075)
Net amount recognized $17,770
 $33,757
 $(5,527) $(5,925) $(10,011) $(10,070)
             
Weighted average assumptions used in the measurement of            
   the benefit obligations:            
Discount rate 4.34% 4.13% 3.85% 3.69% 4.38% 4.03%
Rate of compensation increase 4.07% 3.68% N/A
 N/A
 N/A
 N/A

In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account as presented above instead of OCI as presented above.OCIL. The regulators have allowed future recovery of our pension and OPEB costs to this date.



93


Net periodic benefit cost components for the years ended October 31, 2012, 20112015, 2014 and 2010 includes2013 and the following components.

    

Qualified Pension

   

Nonqualified Pension

   

Other Benefits

 

In thousands

  

2012

   

2011

   

2010

   

2012

   

2011

   

2010

   

2012

   

2011

   

2010

 

Service cost

    $9,573      $8,508      $8,069      $39      $45      $38     $1,387      $1,398      $1,337  

Interest cost

       10,640         11,024         10,898     203     209     243    1,347     1,495         1,906  

Expected return on plan assets

   (20,289)     (20,608)     (18,773)     -      -      -     (1,551)     (1,534)     (1,381)  

Amortization of transition obligation

   -      -      -      -      -      -     667     667     667  

Amortization of prior service cost (credit)

   (2,198)     (2,198)     (2,198)     81     20     20    -      -      -   

Amortization of net loss

   5,966     3,547     1,998     49     41     9    -      -      236  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit (income) cost

   3,692     273     (6)     372     315     310    1,850     2,026     2,765  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other changes in plan assets and benefit obligation recognized through regulatory asset or liability:

                  

Prior service cost

   -      -      -      -      290     -     -      -      -   

Net loss (gain)

   43,945     17,539     (6,587)     629     130     420    2,209     415     (5,229)  

Amounts recognized as a component of net periodic benefit cost:

                  

Transition obligation

   -      -      -      -      -      -     (667)     (667)     (667)  

Amortization of net loss

   (5,966)     (3,547)     (1,998)     (49)     (41)     (9)     -      -      (236)  

Prior service (cost) credit

   2,198     2,198     2,198     (81)     (20)     (20)     -      -      -   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in regulatory asset (liability)

   40,177     16,190     (6,387)     499     359     391    1,542     (252)     (6,132)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in net periodic benefit cost and regulatory asset (liability)

    $43,869      $16,463      $(6,393)      $    871      $    674      $    701     $    3,392      $1,774          $(3,367)  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

weighted average assumptions used to determine net period benefit cost as of October 31, 2015, 2014 and 2013 are presented below.

  
 Qualified Pension Nonqualified Pension Other Benefits
In thousands 2015 2014 2013 2015 2014 2013 2015 2014 2013
Service cost $11,403
 $10,865
 $12,005
 $—
 $—
 $—
 $1,182
 $1,109
 $1,327
Interest cost 12,018
 11,781
 9,946
 209
 200
 157
 1,475
 1,448
 1,130
Expected return on plan assets (23,614) (22,530) (21,105) —
 —
 —
 (1,837) (1,782) (1,663)
Amortization of transition obligation —
 —
 —
 —
 —
 —
 —
 —
 667
Amortization of prior service cost 

     

     

    
  (credit) (2,198) (2,198) (2,198) 231
 243
 81
 —
 —
 —
Amortization of net loss 8,676
 7,685
 11,202
 85
 31
 161
 29
 —
 —
Net periodic benefit cost 6,285
 5,603
 9,850
 525
 474
 399
 849
 775
 1,461
Other changes in plan assets and benefit 
     
     
    
  obligation recognized through 
     
     
    
  regulatory asset or liability: 
     
     
    
  Prior service cost (credit) —
 —
 —
 —
 485
 —
 (1,877) —
 —
  Net loss (gain) 26,179
 14,385
 (30,094) (100) 956
 (540) 3,219
 3,641
 (2,278)
Amounts recognized as a component of 
     
     
    
  net periodic benefit cost: 
     
     
    
Transition obligation —
 —
 —
 —
 —
 —
 —
 —
 (667)
Amortization of net loss (8,676) (7,685) (11,202) (85) (31) (161) (29) —
 —
Prior service (cost) credit 2,198
 2,198
 2,198
 (231) (243) (81) —
 —
 —
Total recognized in regulatory asset 

     

     

    
  (liability) 19,701
 8,898
 (39,098) (416) 1,167
 (782) 1,313
 3,641
 (2,945)
Total recognized in net periodic benefit 

     

     

    
  and regulatory asset (liability) $25,986
 $14,501
 $(29,248) $109
 $1,641
 $(383) $2,162
 $4,416
 $(1,484)
                   
Weighted average assumptions used to determine the net periodic benefit cost:                  
Discount rate 4.13% 4.55% 3.51% 3.69% 3.98% 2.95% 4.03% 4.44% 3.34%
Expected long-term rate of return on plan assets 7.50% 7.75% 8.00% N/A
 N/A
 N/A
 7.50% 7.75% 8.00%
Rate of compensation increase 3.68% 3.72% 3.76% N/A
 N/A
 N/A
 N/A
 N/A
 N/A

The 20132016 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIOCIL discussed above, and expected refunds for our plans are as follows.

In thousands

  Qualified Pension  Nonqualified Pension   Other Benefits 

Amortization of transition obligation

  $-   $-    $667 

Amortization of unrecognized prior service cost (credit)

   (2,198)   81    -  

Amortization of unrecognized actuarial loss

   10,982   161    -  

Refunds expected

   -    -     -  

  Qualified Nonqualified Other
In thousands Pension Pension Benefits
Amortization of unrecognized prior service (credit) cost $(2,198) $208
 $(332)
Amortization of unrecognized actuarial loss 8,164
 81
 459

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s Investors Service’s AA or better-rated non-callable bondsStandard & Poor’s Ratings Services that produces similar results tohave a hypothetical bond portfolio.yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31, 2012,2015, the benchmark by plan was as follows.

PensionQualified pension plan

3.514.34%

NCNG SERP

2.903.78%

Directors’ SERP

3.083.91%

Piedmont SERP

2.323.17%

OPEB

3.344.38%


Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.


We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to

94


receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.

The weighted average


In addition to the assumptions used in the measurementabove table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. Our assumed mortality rates incorporate the benefit obligation asnew set of mortality tables issued by the Society of Actuaries in October 31, 2012 and 2011 are presented below.

    

Qualified Pension

   

Nonqualified Pension

   

Other Benefits

 
    

2012

   

2011

   

2012

   

2011

   

2012

   

2011

 

Discount rate

   3.51%     4.67%     2.95%     4.10%     3.34%     4.36%  

Rate of compensation increase

   3.76%     3.78%     N/A     N/A     N/A     N/A  

The weighted average assumptions used to determine2014. We also applied the net periodic benefit cost asupdated projection scale issued by the Society of Actuaries in October 31, 2012, 2011 and 2010 are presented below.

    

Qualified Pension

  

Nonqualified Pension

 
    

2012

  

2011

  

2010

  

2012

  

2011

  

2010

 

Discount rate

   4.67%   5.47%   5.99%   4.10%   4.37%   5.28% 

Expected long-term rate of return on plan assets

   8.00%   8.00%   8.00%   N/A    N/A    N/A  

Rate of compensation increase

   3.78%   3.87%   3.92%   N/A    N/A    N/A  
   

Other Benefits

    
   

2012

  

2011

  

2010

  

Discount rate

   4.36%   4.85%   5.58%  

Expected long-term rate of return on plan assets

   8.00%   8.00%   8.00%  

Rate of compensation increase

   N/A    N/A    N/A   

2015.


We anticipate that we will contribute the following amounts to our plans in 2013.

In thousands

Qualified pension plan

$    20,000

Nonqualified pension plans

502

MPP plan

695

OPEB plan

1,500

2016.

In thousands 
Qualified pension plan *$10,000
Nonqualified pension plans520
MPP plan1,650
OPEB plan1,300
  
* Funded in November 2015. 

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established aWe are in compliance with the 100% funding target for plan years beginning after December 31, 2007, and we areestablished in compliance.

the PPA.


Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

   Qualified   Nonqualified   Other 

In thousands

  

Pension

   

Pension

   

Benefits

 

2013

  $25,080   $502   $2,002 

2014

   15,035    476    2,129 

2015

   15,325    484    2,209 

2016

   15,099    456    2,261 

2017

   16,101    430    2,354 

2018 - 2022

       101,130        1,988        12,861 

  Qualified Nonqualified Other
In thousands Pension Pension Benefits
2016 $28,147
 $520
 $1,987
2017 19,911
 504
 2,145
2018 20,413
 482
 2,301
2019 21,348
 510
 2,421
2020 21,829
 491
 2,494
2021 - 2025 114,267
 2,100
 13,379

Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2015.

The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2012 and 2011 are2014 is presented below.

   

2012

  

2011

 

Health care cost trend rate assumed for next year

   7.50%   7.70% 

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

   5.00%   5.00% 

Year that the rate reaches the ultimate trend rate

   2027    2027  

2014
Health care cost trend rate assumed for next year7.40%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)5.00%
Year that the rate reaches the ultimate trend rate2027

The health care cost trend rate assumptions could have a significant effect on the amounts reported.reported as benefit cost. A change of 1% would have the following effects.

In thousands

  

1% Increase

   

1% Decrease

 

Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2012

  $33   $(34) 

Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2012

   677    (701) 

effect.

In thousands 1% Increase 1% Decrease
Effect on total of service and interest cost components of net periodic    
 postretirement health care benefit cost for the year ended October 31, 2015 $34
 $(35)

Beginning in 2016, we will change the method we use to estimate the service and interest cost components of net periodic benefit costs for our plans from using a developed zero-coupon spot rate yield curve as discussed above. We have elected to use a full yield curve approach in the estimation of these components of benefit costs by applying the specific spot rates along the yield curve used in the determination of the benefit obligations to the relevant projected cash flows. We will make 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 will not affect the measurement of our

95


total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We will account for this change as a change in estimate and, accordingly, will account for it prospectively beginning in 2016.

Fair Value Measurements

Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.


Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.


Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have beenare valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.


Fixed income securities – These assets include:

U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.

Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.

Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.

High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.

Derivatives – The Level 1 assets wereare valued using a compilation of observable market information on an active market. The Level 2 assets wereare valued using broker quotes on a non-active market.

Large cap core index


Equity securities – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).

Large cap value and small cap value – These are Levellevel 1 assets valued at the market price of the active market on which the individual security is traded.

Large cap growth, international value and global REIT


Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of mutual fund shares in managed equity funds.

the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2.


Common trust fund - International growth – These are Level 2 assets held in a common trust fund in which we own an interest andinterests that are valued at the NAV of the funds as traded on international exchanges. Currently, there are no restrictions on redemptions for the fund.

Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.


Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 5%3.5% but is still being funded through capital calls; $8.5$4 million of the original $12 million subscription remains unfunded. Until a 5%3.5% allocation can be achieved, the balance of the 5%3.5% allocation is invested in a low-cost equity index fund that tracks the S&PStandard & Poor's 500 Stock Index. Our investment is in various funds that invests in North American companies;companies, allocate capital to private equity funds;funds, invest in venture capital partnerships;partnerships and private equity partnerships in emerging markets.


The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Hedge fund of funds – These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently, there are no restrictions on redemptions for the fund.

Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently, there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.


High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund.


96


As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.

  Redemptions
Redemption     

Redemptions

Notice

Investment

  

Frequency

  

Other Redemption Restrictions

  

Period

Common trust fund -
International growth

  Monthly  

None

  30 days

Hedge fund of funds

  Quarterly  

Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2012.

2015.		  65 days

Private equity fund of funds

  Limited  

Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.

  (1)

Commodities fund of funds

  Monthly  

Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.

  35 days
Bank loansDailyNone30 days


(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.


The qualified pension plan’s asset allocations by level within the fair value hierarchy atas of October 31, 20122015 and 20112014 are presented below. 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 their placementconsideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

    Qualified Pension Plan as of October 31, 2012 
    

    Quoted Prices    
in Active

Markets

   Significant
Other
Observable
Inputs		   

Significant
Unobservable  

Inputs

   Total
Carrying  		   % of   

In thousands

  (Level 1)   (Level 2)   (Level 3)   Value   Total   

Cash and cash equivalents

    $5,346       $-        $-       $5,346      2%    
          

 

 

 

Fixed Income Securities:

           45%    
          

 

 

 

U.S. treasuries

   -       17,544      -       17,544      6%    

Long duration bonds

   -       63,565      -       63,565      23%    

Corporate bonds

   -       26,368      -       26,368      10%    

High yield bonds

   13,777      -       -       13,777      5%    

Collateralized mortgage obligations

   -       1,513      -       1,513      1%    

Municipals

   -       345      -       345      -%    

Derivatives

   (3)      (86)      -       (89)      -%    
          

 

 

 

Equity Securities:

           36%    
          

 

 

 

Large cap core index

   10,260      -       -       10,260      4%    

Large cap value

   10,427      -       -       10,427      4%    

Large cap growth

   15,252      -       -       15,252      6%    

Small cap value

   26,335      -       -       26,335      10%    

International value

   14,376      -       -       14,376      5%    

Common trust fund - International growth

   -       18,678      -       18,678      7%    
          

 

 

 

Real Estate:

           6%    
          

 

 

 

Global REIT

   16,252      -       -       16,252      6%    
          

 

 

 

Other Investments:

           11%    
          

 

 

 

Hedge fund of funds

   -       16,995      -       16,995      6%    

Private equity fund of funds

   -       -       3,522      3,522      1%    

Commodities fund of funds

   -       11,871      -       11,871      4%    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets at fair value

    $    112,022       $    156,793       $      3,522       $    272,337          100%    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Percent of fair value hierarchy

   41%      58%      1%      100%    
  

 

 

   

 

 

   

 

 

   

 

 

   

    Qualified Pension Plan as of October 31, 2011 
    Quoted Prices
in Active
Markets		   Significant
Other
Observable
Inputs		   Significant
Unobservable
Inputs		   Total
Carrying		   % of 

In thousands

  (Level 1)   (Level 2)   (Level 3)   Value   Total 

Cash and cash equivalents

    $5,891      $2      $-       $5,893     2%  
          

 

 

 

Fixed Income Securities:

           45%  
          

 

 

 

U.S. treasuries

   -      11,109     -      11,109     4%  

Long duration bonds

   66,824     -      -      66,824     26%  

Corporate bonds

   -      24,383     -      24,383     9%  

High yield bonds

   12,504     -      -      12,504     5%  

Collateralized mortgage obligations

   -      1,448     -      1,448     1%  

Municipals

   -      324     -      324     -%  

Derivatives

   (25)     437     -      412     -%  
          

 

 

 

Equity Securities:

           35%  
          

 

 

 

Large cap core index

   11,206     -      -      11,206     4%  

Large cap value

   8,623     -      -      8,623     3%  

Large cap growth

   15,897     -      -      15,897     6%  

Small cap value

   23,827     -      -      23,827     9%  

International value

   13,770     -      -      13,770     6%  

Common trust fund - International growth

   18,057     -      -      18,057     7%  
          

 

 

 

Real Estate:

           6%  
          

 

 

 

Global REIT

   14,909     -      -      14,909     6%  
          

 

 

 

Other Investments:

           12%  
          

 

 

 

Hedge fund of funds

   -      10,089     6,207     16,296     6%  

Private equity fund of funds

   -      -      1,925     1,925     1%  

Commodities fund of funds

   -      3,632     8,472     12,104     5%  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets at fair value

    $    191,483      $      51,424      $      16,604      $    259,511         100%  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Percent of fair value hierarchy

   74%     20%     6%     100%    
  

 

 

   

 

 

   

 

 

   

 

 

   

During the period, we transferred amounts from Level 3 to Level 2 for our investments in the hedge fund of funds and the commodities fund of funds because inputs became more observable. Long duration bonds and the common trust fund – international growth investments were classified as Level 1 assets as of October 31, 2011 and as Level 2 assets at October 31, 2012 due to changes in observable inputs.

   Qualified Pension Plan 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)
Total Carrying Value 
Cash and cash equivalents $2,782
 $89
 $—
 $2,871
 
Fixed income securities —
 84,135
 —
 84,135
 
Equity securities 44,738
 —
 —
 44,738
 
Mutual funds 78,853
 42,890
 —
 121,743
 
Common trust fund —
 23,571
 —
 23,571
 
Private equity fund of funds —
 —
 8,344
 8,344
 
Other Investments:         
Hedge fund of funds       19,809
(1) 
Commodities fund of funds       7,688
(1) 
High yield debt (bank loans)       16,408
(1) 
Total assets at fair value $126,373
 $150,685
 $8,344
 $329,307
 

97


   Qualified Pension Plan as of October 31, 2014 
In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value 
Cash and cash equivalents $27,932
 $435
 $—
 $28,367
 
Fixed income securities 48
 78,026
 —
 78,074
 
Equity securities 51,266
 —
 —
 51,266
 
Mutual funds 54,502
 48,049
 —
 102,551
 
Common trust fund —
 22,877
 —
 22,877
 
Private equity fund of funds —
 —
 7,158
 7,158
 
Other Investments:         
Hedge fund of funds       19,829
(1) 
Commodities fund of funds       10,134
(1) 
High yield debt (bank loans)       16,187
(1) 
Total assets at fair value $133,748
 $149,387
 $7,158
 $336,443
 
          
(1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

    Hedge Fund   

Private

Equity Fund

   Commodities     

In thousands

  of Funds   of Funds   Fund of Funds   Total 

Balance, October 31, 2010

    $5,196        $580        $-        $5,776    

Actual return on plan assets:

        

Relating to assets still held at the reporting date

   (1,236)       66       (488)       (1,658)    

Relating to assets sold during the period

   -        -       -       -     

Purchases, sales and settlements (net)

   2,247       1,279       8,960       12,486    

Transfer in/out of Level 3

   -        -       -       -     
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance, October 31, 2011

       6,207           1,925           8,472           16,604    

Actual return on plan assets:

        

Relating to assets still held at the reporting date

   -       13       -       13    

Relating to assets sold during the period

   -       145       -       145    

Purchases, sales and settlements (net)

   -       1,439       -       1,439    

Transfer in/out of Level 3

   (6,207)       -       (8,472)       (14,679)    
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance, October 31, 2012

    $-        $3,522        $-        $3,522    
  

 

 

   

 

 

   

 

 

   

 

 

 

  Private
  Equity Fund
In thousands of Funds
Balance, October 31, 2013 $4,659
Actual return on plan assets:  
Relating to assets still held at the reporting date 1,031
Relating to assets sold during the period 113
Purchases, sales and settlements (net) 1,355
Transfer in/out of Level 3 —
Balance, October 31, 2014 7,158
Actual return on plan assets:  
Relating to assets still held at the reporting date 413
Relating to assets sold during the period 618
Purchases, sales and settlements (net) 155
Transfer in/out of Level 3 —
Balance, October 31, 2015 $8,344

During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.


There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.


Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.

plan.


Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.

U.S. treasuries – These are Level 1 assets in an actively managed mutual fund measured at NAV.

Corporate bonds


Mutual funds – These are Level 1 assets valued at the publicly quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to a high yield bond fund.

Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAVper share computed as invested in mutual funds that invest by a specific style.

Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.

International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.

Global REIT – These are Level 1 assets valued at the quoted NAVclose of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.

business on our balance sheet date.



98


The OPEB plan’s asset allocations by level within the fair value hierarchy atas of October 31, 20122015 and 20112014 are presented below. 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 their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

   Other Benefits as of October 31, 2012 
    

Quoted Prices

in Active

Markets

   

Significant

Other

Observable

Inputs

   

Significant

Unobservable
Inputs

   Total Carrying   % of 

In thousands

  

(Level 1)

   

(Level 2)

   

(Level 3)

   

Value

   

Total

 

Cash and cash equivalents

    $926      $-       $-       $926     4%  
          

 

 

 

Fixed Income Securities:

           46%  
          

 

 

 

U.S. treasuries

   2,345     -      -      2,345     10%  

Corporate bonds / Asset-backed securities

   8,474     -      -      8,474     36%  
          

 

 

 

Equity Securities:

           45%  
          

 

 

 

Large cap value

   1,221     -      -      1,221     5%  

Large cap growth

   1,149     -      -      1,149     5%  

Small cap value

   1,177     -      -      1,177     5%  

Small cap growth

   1,155     -      -      1,155     5%  

Large cap index

   2,148     -      -      2,148     9%  

International blend

   3,907     -      -      3,907     16%  
          

 

 

 

Real Estate:

           5%  
          

 

 

 

Global REIT

   1,161     -      -      1,161     5%  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets at fair value

    $        23,663      $-       $-       $        23,663       100%  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Percent of fair value hierarchy

   100%             -%             -%     100%    
  

 

 

   

 

 

   

 

 

   

 

 

   

   Other Benefits as of October 31, 2011 
    Quoted Prices
in Active
Markets		   Significant
Other
Observable
Inputs		   Significant
Unobservable
Inputs		   Total
Carrying		   % of 

In thousands

  

(Level 1)

   

(Level 2)

   

(Level 3)

   

Value

   

Total

 

Cash and cash equivalents

    $1,011      $-       $-       $1,011     5%  
          

 

 

 

Fixed Income Securities:

           45%  
          

 

 

 

U.S. treasuries

   2,162     -      -      2,162     10%  

Corporate bonds / Asset-backed securities

   7,790     -      -      7,790     35%  
          

 

 

 

Equity Securities:

           45%  
          

 

 

 

Large cap value

   1,108     -      -      1,108     5%  

Large cap growth

   1,107     -      -      1,107     5%  

Small cap value

   1,092     -      -      1,092     5%  

Small cap growth

   1,131     -      -      1,131     5%  

Large cap index

   1,996     -      -      1,996     9%  

International blend

   3,557     -      -      3,557     16%  
          

 

 

 

Real Estate:

           5%  
          

 

 

 

Global REIT

   1,091     -      -      1,091     5%  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets at fair value

    $    22,045      $      -       $-       $      22,045         100%  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Percent of fair value hierarchy

   100%     -%     -%     100%    
  

 

 

   

 

 

   

 

 

   

 

 

   

  Other Benefits 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) Total Carrying Value
Cash and cash equivalents $1,164
 $—
 $—
 $1,164
Mutual funds 26,382
 —
 —
 26,382
Total assets at fair value $27,546
 $—
 $—
 $27,546

  Other Benefits as of October 31, 2014
          
In thousands Quoted Prices In Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Carrying Value
Cash and cash equivalents $2,590
 $—
 $—
 $2,590
Mutual funds 25,157
 —
 —
 25,157
Total assets at fair value $27,747
 $—
 $—
 $27,747

401(k) Plan


We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.


Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2012, 20112015, 2014 and 2010,2013, we made matching contributions to participant accounts as follows.

In thousands

  

2012

   

2011

   

2010

 

401(k) matching contributions

  $    5,400   $    5,203   $    5,269 

In thousands 2015 2014 2013
401(k) matching contributions $6,584
 $6,134
 $5,688

As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statement of Stockholders’ Equity as an increase in retained earnings.

10.



99


11. 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 years ended October 31, 2012, 20112015, 2014 and 2010,2013, we recorded compensation expense, and as of October 31, 20122015 and 2011,2014, we have 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.


We have granted three series of awards under the approved incentive compensation plansICP, one with a three-year performance periods endingperiod that ended October 31, 2012,2015 (2015 plan) and two other awards ending on October 31, 20132016 (2016 plan) and October 31, 2014. 50%2017 (2017 plan). For each of the units awarded will bethese performance periods, awards are weighted and based on achievement of relative to:

a target annual compounded increase in basic EPS. For this 50% portion, an EPS performance of 80% of target will result in an 80% payout, an EPS performance of 100% of target will result in a 100% payout and an EPS performance of 120% of target will result in a maximum 120% payout, and EPS performance levels between these levels will be subject to mathematical interpolation. EPS performance below 80% of target will result in no payout of this portion. The other 50% of the units awarded will be based on the achievement of (37.5% weight),
total annual shareholder return (increase in our common stock price plus dividends reinvested over the specified period of time) in comparisonreturns compared to a group of peer group which consists ofcompanies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas companies. The total shareholderdistribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours (37.5% weight), and
an actual average return performance measure will be our percentile ranking in relationshipon equity compared to the peer group. For this 50% portion, a ranking below the 25th percentile will result in no payout, a ranking between the 25th and 39th percentile will result in an 80% payout, a ranking between the 40th and 49th percentile will result in a 90% payout, a ranking between the 50th and 74th percentile will result in a 100% payout, a ranking between the 75th and 89th percentile will result in a 110% payout, and a ranking at or above the 90th percentile will result in a maximum 120% payout.

weighted average return on equity allowed by our regulatory commissions (25% weight).


In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award will vestvested for participants who have met the retention requirements at the end of athe three-year period ending in December 2013 and settled in the same month with payment in the form of shares of our common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2012 and 2011, we recorded compensation expense, and as of October 31, 2012 and 2011, we have accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.


Also under our approved ICP, 64,700 unvested retention stock units (RSUs) were granted to our President and Chief Executive Officer (CEO) in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock unitsRSUs will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vestvested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2012,2015, 2014 and 2013, we recorded compensation expense, and as of October 31, 2012,2015 and 2014, we have accrued a liability for this award based on the fair market value of our common stock at the end of each quarter. The liability is re-measured to market value each quarter and at the settlement date.


The December 15, 2014 vesting covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of our common stock. After withholdings of $.3 million for federal and state income taxes, our President and CEO received 7,231 shares of our common stock at the NYSE composite closing price on December 12, 2014 of $37.89 per share.

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

At the time of distribution of awardsany award under the ICP, the number of shares of common stock issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present thesethe net shares issued in the Consolidated Statements of Stockholders’ Equity.

Equity and in Note 7 to the consolidated financial statements.


The compensation expense related to the incentive compensation plansawards under the ICP for the years ended October 31, 2012, 20112015, 2014 and 2010,2013, 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 Consolidated Balance Sheets as of October 31, 20122015 and 20112014 are presented below.

In thousands  2012   2011   2010 

Compensation expense

  $5,730   $    2,604   $6,118 

Tax benefit

   2,080    673        1,756 

Liability

       10,631    5,015   



100


In thousands 2015 2014 2013
Compensation expense $14,173
 $8,496
 $4,526
Tax benefit 3,966
 2,476
 1,538
Liability 22,037
 15,130
  

Based on current accrual assumptions as of October 31, 2012,2015, the expected payout for the approved incentive compensation plansawards at target will occur in the following fiscal years.

In thousands  2013   2014   2015   2016   2017 

Amount of payout

  $    3,842   $    4,471   $    1,990   $      141   $      187 

years with the 2015 plan paying out in fiscal year 2016, the 2016 plan paying out in fiscal year 2017 and the 2017 plan paying out in fiscal year 2018. Payouts as currently accrued are presented net of estimated federal and state withholding payments.

In thousands
2016
2017
2018
Amount of payout
$10,866
 $8,179
 $2,992

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 RSUs for our President and CEO (accelerated RSUs) 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 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 Tax Code, 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 RSUs, 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 RSUs, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of common stock resulting from the reinvestment of dividends paid with respect to these shares of common stock that are required to be reinvested in additional shares of common stock, to the extent the shares of common stock would not otherwise have been earned or payable absent the acceleration. Under the share repayment agreements, the 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 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. The participants otherwise have all rights of shareholders with respect to the restricted shares of common stock.

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

11.



101


12. Income Taxes


The components of income tax expense for the years ended October 31, 2012, 20112015, 2014 and 20102013 are presented below.

    2012   2011   2010 

In thousands

  Federal   State   Federal   State   Federal   State 

Charged (Credited) to operating income:

            

Current

    $(29,062)      $1,857      $(11,403)      $4,209      $18,133      $3,928  

Deferred

   86,496     10,144     64,806     6,597     33,432     6,866  

Tax Credits:

            

Utilization

   -      -      184     -      105     -   

Amortization

   (334)     -      (325)     -      (382)     -   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   57,100     12,001     53,262     10,806     51,288     10,794  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Charged (Credited) to other income (expense):

            

Current

   5,636     1,027     3,263     (36)     22,519     3,755  

Deferred

   2,214     239     4,167     824     2,963     557  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   7,850     1,266     7,430     788     25,482     4,312  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    $    64,950      $    13,267    $    60,692      $    11,594      $    76,770      $    15,106  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  
2015
2014
2013
In thousands
Federal
State
Federal
State
Federal
State
Charged (Credited) to operating            
  income:











  Current
$(10,449) $(289) $(1,653) $950
 $(3,032) $919
  Deferred (1) (2)

75,644
 12,195
 70,654
 13,434
 67,885
 11,829
  Tax Credits:
           
Amortization
(167) —
 (209) —
 (267) —
Total
65,028
 11,906
 68,792
 14,384
 64,586
 12,748
             
Charged (Credited) to other income            
  (expense):

 
 
 
 
 
  Current
9,709
 1,449
 4,233
 870
 6,049
 984
  Deferred (1) (2)

2,249
 (119) 5,811
 728
 2,225
 (646)
Total
11,958
 1,330
 10,044
 1,598
 8,274
 338
Total
$76,986
 $13,236
 $78,836
 $15,982
 $72,860
 $13,086
(1) Includes benefits from net operating loss (NOL) and tax carryforwards of $64.3 million and $62.3 million for the years ended October 31, 2015 and 2013, respectively.
(2) Includes the utilization of NOL carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.

The Tax Increase Prevention Act of 2014 (the Act), enacted December 19, 2014, retroactively extended the 50% bonus depreciation that expired December 2013 for a year to December 2014. Under the Act, we were able to claim additional depreciation deductions on our tax return for the year ended October 31, 2014. As a result of this additional depreciation, we generated a NOL for our tax year ended October 31, 2014. Prior to the Act's retroactive extension to 2014, we had anticipated utilizing NOL carryforwards to offset taxable income generated in our fiscal year 2014. The benefit from NOL and tax carryforwards for the year ended October 31, 2015 includes $61.1 million to record the retroactive impact of the Act.
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2012, 20112015, 2014 and 20102013 is presented below.

In thousands

  

2012

  

2011

  

2010

 

Federal taxes at 35%

    $    69,322    $    65,049    $    81,841 

State income taxes, net of federal benefit

   8,624   7,536   9,819 

Amortization of investment tax credits

   (334)   (325)   (382) 

Other, net

   605   26   598 
  

 

 

  

 

 

  

 

 

 

Total

    $78,217    $72,286    $91,876 
  

 

 

  

 

 

  

 

 

 

In thousands
2015 2014 2013
Federal taxes at 35%
$79,532
 $83,517
 $77,127
State income taxes, net of federal benefit
8,604
 10,389
 8,506
Amortization of investment tax credits
(167) (209) (267)
Other, net
2,253
 1,121
 580
Total
$90,222
 $94,818
 $85,946


102


As of October 31, 20122015 and 2011,2014, deferred income taxes consisted of the following temporary differences.

In thousands

  

2012

   

2011

 

Deferred tax assets:

    

Benefit of loss carryforwards

  $3,092    $2,474  

Employee benefits and compensation

   22,286     10,267  

Revenue requirement

   10,148     10,306  

Utility plant

   11,285     10,799  

Other

   9,173     6,043  
  

 

 

   

 

 

 

Total deferred tax assets

   55,984     39,889  

Valuation Allowance

   (505)     (505)  
  

 

 

   

 

 

 

Total deferred tax assets, net

   55,479     39,384  
  

 

 

   

 

 

 

Deferred tax liabilities:

    

Utility plant

   523,232     437,388  

Revenues and cost of gas

   26,816     6,896  

Equity method investments

   34,092     32,296  

Deferred costs

   73,744     55,142  

Other

   8,348     18,830  
  

 

 

   

 

 

 

Total deferred tax liabilities

   666,232     550,552  
  

 

 

   

 

 

 

Net deferred income tax liabilities

  $610,753    $511,168  
  

 

 

   

 

 

 


In thousands
2015
2014
Deferred tax assets:

 
Benefit of loss carryforwards
$84,025
 $39,532
Revenues and cost of gas 3,495
 4,960
Employee benefits and compensation
22,134
 16,547
Revenue requirement
26,088
 20,320
Utility plant
7,481
 5,631
Other
10,461
 12,869
Total deferred tax assets
153,684
 99,859
Valuation allowance
(848) (505)
Total deferred tax assets, net
152,836
 99,354
Deferred tax liabilities:
   
Utility plant
849,835
 724,172
Revenues and cost of gas
—
 4,340
Equity method investments
44,778
 42,998
Deferred costs
73,903
 65,828
Other
13,543
 18,065
Total deferred tax liabilities
982,059
 855,403
Net deferred income tax liabilities
$829,223
 $756,049

As of October 31, 20122015 and 2011,2014, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly ownedwholly-owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 20122015 and 2011,2014, we hadhave federal net operating lossNOL carryforwards of $5.9$219.7 million and $6.2$97 million, respectively, which expire from 2021in 2033 through 2025. As2034. We also have $5.9 million of federal NOL carryforwards as of October 31, 2012, we had federal charitable contribution carryforwards of $2.3 million, which2015 and 2014 that expire from 2016in 2023 through 2017. As of October 31, 20122025 and 2011, we had state net operating loss carryforwards of $6.8 million and $7 million, respectively, which expire from 2020 through 2027. We may use the loss carryforwards to offset taxable income. The federal net operating loss carryforwards are subject to an annual limitation of $.3 million.

As of October 31, 2015, we have a capital loss carryforward of $1 million which expires in 2019. We believe that it is more likely than not that the benefit from the capital loss carryforward will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the capital loss carryforward, we recorded a valuation allowance of $.3 million during fiscal year ended October 31, 2015. As of October 31, 2015, we have a $1.1 million alternative minimum tax credit carryforward.


As of October 31, 2015 and 2014, we have state NOL carryforwards of $115.1 million and $7.2 million, respectively, which expire from 2018 through 2030. We may use the carryforwards to offset taxable income.

We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2008,2009, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2008.

2009. The IRS is currently auditing the federal income tax returns for years ended October 31, 2010, 2011 and 2012.


A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2012, 20112015, 2014 and 20102013 is presented below.

In thousands

  

2012

   

2011

   

2010

 

Balance at beginning of year

    $      505      $      1,324      $      1,400  

Credited to income tax expense

   -      (819)     (76)  
  

 

 

   

 

 

   

 

 

 

Balance at end of year

    $505      $505      $1,324  
  

 

 

   

 

 

   

 

 

 


In thousands
2015 2014 2013
Balance at beginning of year
$505
 $505
 $505
Charged to income tax expense
343
 —
 —
Balance at end of year
$848
 $505
 $505

There were no unrecognized tax benefits for the years ended October 31, 20122015 and 2011.

12.2014.


In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduced the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning

103


after January 1, 2015. It also provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. In July 2015, the provision for a 1% state income tax rate reduction based on state tax collections exceeding certain thresholds under the North Carolina tax statutes was announced. Accordingly, the statutory income tax rate for North Carolina will decrease to 4% for our fiscal year 2017. We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse.

As a result of the state income tax rate reductions announced in July 2015, we adjusted our noncurrent deferred income tax balances during fiscal year 2015 by approximately $17.5 million for temporary differences expected to reverse at the lower future rate. We recognized a tax benefit in net income of approximately $.5 million, largely related to our regulated non-utility activities segment, and recorded the remainder of approximately $17 million as regulatory deferred income taxes as presented in noncurrent "Regulatory Liabilities" in Note 3 to the consolidated financial statements, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. As of October 31, 2015, we have approximately $44 million related to the North Carolina tax rate change included in our deferred income taxes recorded in “Regulatory Liabilities,” which would have been an increase to net income predominately in fiscal years 2013 and 2015 without our utility regulation. The NCUC will determine the recovery period of this regulatory liability in future proceedings. In fiscal 2013, we recognized a tax benefit in net income of approximately $1 million related to the corporate income tax reduction.

13. Equity Method Investments


The consolidated financial statements include the accounts of wholly ownedwholly-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 Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.


As of October 31, 2012,2015, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

Cardinal Pipeline Company, L.L.C.


Ownership Interests

We own 21.49% ofhave the following membership interests in these companies as of October 31, 2015 and 2014.
Entity NameInterestActivity
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 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC


104


Accumulated Other Comprehensive Income (Loss)

As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal Pipeline Company, L.L.C. (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 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 Consolidated Statements of Comprehensive Income.

Related Party Transactions
We have related party transactions as a customer of our investments. For the years ended October 31, 2015, 2014 and 2013, these gas costs and the amounts we owed to our equity method investees, as of October 31, 2015 and 2014, are as follows.
Related Party Type of Expense 
Cost of Gas (1)
 
Trade accounts payable (2)
In thousands   2015 2014 2013 2015 2014
Cardinal Transportation costs $8,763
 $8,825
 8,775
 $744
 $747
Pine Needle Gas storage costs 11,441
 11,364
 11,098
 955
 989
Hardy Storage Gas storage costs 9,290
 9,461
 9,702
 774
 774
  Totals   $29,494
 $29,650
 $29,575
 $2,473
 $2,510
             
(1) In the Consolidated Statements of Comprehensive Income.
(2) In the Consolidated Balance Sheets.

We have related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended October 31, 2015, 2014 and 2013, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2015 and 2014, are as follows.
  
Operating Revenues (1)
 
Trade accounts receivable (2)
In thousands 2015 2014 2013 2015 2014
Operating revenues $1,568
 $3,541
 $3,291
 $183
 $460
(1) In the Consolidated Statements of Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Information on Our Equity Method Investments

Cardinal

Cardinal is a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline.pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams-TranscoWilliams – Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is nonrecourse to the members and is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.

In October 2009, we reached an agreement with Progress Energy Carolinas, Inc. (PEC), now a subsidiary of DEC, to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide that delivery service, we executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement on Cardinal to serve PEC. This required Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system for us and another customer. As an equity member of Cardinal, we made capital contributions related to this system expansion from January 2011 through June 2012. As of October 31, 2012, our 2012 fiscal year contributions related to this expansion were $3.6 million, and our total contributions related to this expansion were $9.8 million. Cardinal’s expansion service for the project was placed into service on June 1, 2012.

Our natural gas delivery service for PEC’s Wayne County generation project was placed into service on June 1, 2012. The charges we incur as transportation costs from Cardinal are passed through to PEC under the terms of our natural gas delivery service agreement with PEC. Our service subscription to Cardinal’s capacity following the system expansion increased from approximately 37% to approximately 53%. Subsequent to the project being placed into service, members’ capital was replaced with $45 million of long-term debt issued by Cardinal on June 22, 2012, and we received a distribution of $5.4 million as a partial return of our capital contributions.

Cardinal enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2012, 2011 and 2010, these transportation costs and the amounts we owed Cardinal as of October 31, 2012 and 2011 are as follows.

In thousands

  

2012

   

2011

   

2010

 

Transportation costs

  $        6,613   $        4,104   $        4,104 

Trade accounts payable

   855    349   


Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 20122015 and 2011,2014, and for the twelve months ended September 30, 2012, 20112015, 2014 and 20102013, is presented below.

In thousands

  

2012

   

2011

   

2010

 

Current assets

  $9,179   $25,868   

Noncurrent assets

       120,437    88,329   

Current liabilities

   1,786    5,665   

Noncurrent liabilities

   45,702        24,225   

Revenues

   16,165    13,633   $    13,633 

Gross profit

   16,165    13,633    13,633 

Income before income taxes

   10,433    6,473    6,375 


105


In thousands
2015 2014 2013
Current assets
$9,451
 $8,856
  
Noncurrent assets
106,444
 111,881
  
Current liabilities
1,228
 1,468
  
Noncurrent liabilities
45,446
 45,402
  
Revenues
16,629
 16,705
 $17,649
Gross profit
16,629
 16,705
 17,649
Income before income taxes
7,742
 8,042
 9,361

Pine Needle

Pine Needle LNG Company, L.L.C.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle),is a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc., and SCANA Corporation andCorporation. Effective July 1, 2013, we acquired Hess Corporation.Corporation’s 5% membership interest in Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the FERC.for $2.9 million, increasing our membership interest from 40% to 45%. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%.

Pine Needle enters into interest-rate swap agreements to modify We are dependent on the interest characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets. Pine Needle’s long-term debt is nonrecourse to the members and is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle.

We have related party transactions as a customerWilliams – Transco pipeline system for redelivery of Pine Needle and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2012, 2011 and 2010, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2012 and 2011 are as follows.

In thousands

  

2012

   

2011

   

2010

 

Gas storage costs

  $        10,410   $        10,677   $        12,158 

Trade accounts payable

   914    849   

volumes to our system for service to our customers.


Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 20122015 and 2011,2014, and for the twelve months ended September 30, 2012, 20112015, 2014 and 20102013, is presented below.

In thousands

  

2012

   

2011

   

2010

 

Current assets

  $11,937   $10,984   

Noncurrent assets

   77,463    74,472   

Current liabilities

   4,278    1,826   

Noncurrent liabilities

         35,851    35,657   

Revenues

   16,390          17,666   $      18,808 

Gross profit

   16,390    17,666    18,808 

Income before income taxes

   5,832    5,763    8,317 

In thousands
2015 2014 2013
Current assets
$9,863
 $8,812
  
Noncurrent assets
71,586
 70,837
  
Current liabilities
5,377
 38,029
  
Noncurrent liabilities
35,112
 —
  
Revenues
16,913
 18,025
 $16,810
Gross profit
16,913
 18,025
 16,810
Income before income taxes
6,002
 6,011
 5,804

SouthStar

SouthStar Energy Services LLC

We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar),is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL) who is subject to being acquired by The Southern Company. On September 4, 2015, under the terms of the SouthStar primarily sells natural gaslimited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to residential, commercial and industrial customersremain a member of SouthStar.


In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in the southeastern United States and Ohio with most of its business being conducted in the unregulated retail gas market in Georgia. On January 1, 2010, we sold half ofSouthStar. GNGC’s election to purchase our 30% membershipentire 15% interest in SouthStar is subject to and effective with the consummation of the Acquisition.

In September 2013, GNGC contributed its retail natural gas marketing assets and retainedcustomer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC resulting in an after-tax gain of $30.3 million, or $.42 per diluted share for 2010. GNGC has no further rightsequity ownership, related to acquire our remaining 15% interest. We account for our investment in SouthStar using the equity method, as we have board representation with voting rights equal to GNGC on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

this transaction.


SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.

These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Our share of movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2012, 2011 and 2010, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2012 and 2011 are as follows.

In thousands

  

2012

   

2011

   

2010

 

Operating revenues

  $    2,442   $    4,961   $    5,083 

Trade accounts receivable

   473    736   



106


Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 20122015 and 2011,2014, and for the twelve months ended September 30, 2012, 20112015, 2014 and 20102013, is presented below.

In thousands

  

2012

   

2011

   

2010

 

Current assets

  $      152,422   $      169,286   

Noncurrent assets

   9,803    9,292   

Current liabilities

   42,197    62,869   

Noncurrent liabilities

   1    141   

Revenues

   585,291    733,987   $      843,483 

Gross profit

   161,122    176,010    183,748 

Income before income taxes

   94,631    103,704    107,096 

In thousands
2015 2014* 2013
Current assets
$204,237
 $192,151
  
Noncurrent assets
132,315
 143,958
  
Current liabilities
45,953
 47,923
  
Noncurrent liabilities
—
 —
  
Revenues
769,295
 845,695
 $639,426
Gross profit
224,612
 234,581
 174,993
Income before income taxes
129,340
 136,569
 102,805
       
  * Balance sheet amounts have been changed to reflect SouthStar's reclassification of cash collateral under accounting guidance.

Hardy Storage

Hardy Storage Company, LLC

We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage),is a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, and is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.

In June 2006, Hardy Storage signed a note purchase agreement We are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for interim notes for construction financing. The membersredelivery of Hardy Storage each agreed to guarantee 50% of the construction financing as well as a separate guaranty of 50% of construction expenditures should contingency wells be required based on the performance of the facility over the first three years after the in-service date. We recorded a liability of $1.2 million for the fair value of this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter with the risk of the project evaluated at each quarter end, with a corresponding increasevolumes to our investment account in the venture. In March 2010, Hardy Storage completed their conversionsystem for service to long-term project financing, which terminated our guaranty related to the interim financing with no payments having been made. We reversed the liability and our investment account was adjusted accordingly to reflect the elimination of the guaranty. The long-term project financing is nonrecourse to the members of Hardy Storage and their parent entities.

We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2012, 2011 and 2010, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2012 and 2011 are as follows.

In thousands

  

2012

   

2011

   

2010

 

Gas storage costs

  $    9,702   $    9,702   $    9,386 

Trade accounts payable

   808    808   

customers.


Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 20122015 and 2011,2014, and for the twelve months ended October 31, 2012, 20112015, 2014 and 20102013, is presented below.

In thousands

  

2012

   

2011

   

2010

 

Current assets

  $10,302   $7,358   

Noncurrent assets

       164,374        167,221   

Current liabilities

   14,534    10,945   

Noncurrent liabilities

   95,061    102,490   

Revenues

   24,359    24,378   $23,562 

Gross profit

   24,359    24,378          23,562 

Income before income taxes

   9,939    9,657    8,249 

In thousands
2015 2014 2013
Current assets
$11,658
 $12,644
  
Noncurrent assets
156,803
 157,861
  
Current liabilities
19,078
 17,316
  
Noncurrent liabilities
69,971
 78,830
  
Revenues
23,350
 23,804
 $24,375
Gross profit
23,350
 23,804
 24,375
Income before income taxes
10,403
 10,497
 10,582

Constitution

Constitution Pipeline Company, LLC

On November 9, 2012, we entered into an agreement to become a 24% equity member of Constitution Pipeline Company, LLC,is a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc. and, Cabot Oil & Gas Corporation.Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies iswill be the operator of the project. The purpose of the joint venture is to construct and operate a 121 mile interstate natural gas pipeline and related facilities connecting gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York.pipeline. 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 between $700 – $800approximately $834 million, excluding AFUDC, in total. Our total anticipated contributions are approximately $200.2 million. In November 2012, we made an initial investmentAs of $4.8October 31, 2015, our fiscal year contributions were $19.1 million, and we expectwith our total equity contributions will be an estimated $180for the project totaling $72.7 million through 2015.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 March 2015.the fourth quarter of 2016, which has been extended due to a longer than expected regulatory and permitting process. The capacity of the pipeline is 100% subscribed under fifteen yearfifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

13.


Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2015 and 2014, and for the twelve months ended September 30, 2015, 2014 and 2013, is presented below.

107


In thousands
2015 2014 2013
Current assets
$6,163
 $11,273
 
Noncurrent assets
330,152
 219,208
 
Current liabilities
4,398
 7,667
 
Noncurrent liabilities
—
 —
 
Revenues
—
 —
 $—
Gross profit
—
 —
 —
Income before income taxes
24,604
 10,091
 3,459

ACP

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary will be the operator of the pipeline. The pipeline will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018, subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.

The total cost for 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. As of October 31, 2015, our fiscal year contributions were $10.6 million, with contributions to the project beginning November 2014.

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

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

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

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

Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2015, and for the twelve months ended September 30, 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.

108


In thousands 2015
Current assets $23,422
Noncurrent assets 86,109
Current liabilities 9,105
Noncurrent liabilities —
Revenues —
Gross profit —
(Loss) before income taxes (5,205)

14. Variable Interest Entities

Under accounting guidance,


On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) is a legal entity that conducts a business or holds property whose equity,as defined by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligationsauthoritative guidance on consolidation, and that interest changes as the entity’s net assets change. The consolidating investorif so, which party is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

primary beneficiary. As of October 31, 2012,2015, we have determined that we are not the primary beneficiary as defined by the authoritativeunder VIE accounting guidance related to consolidations, in any of our equity method investments, as discussed in Note 1213 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor,performance, and we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. investments.


Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity.entity included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. As of October 31, 20122015 and 2011,2014, our investment balances are as follows.

   October 31,   October 31, 

In thousands

  2012   2011 

Cardinal

  $17,969    $18,323  

Pine Needle

   19,239     18,690  

SouthStar

   18,118     17,536  

Hardy Storage

   32,541     30,572  
  

 

 

   

 

 

 

Total equity method investments in non-utility activities

  $    87,867    $    85,121  
  

 

 

   

 

 

 

  October 31, October 31,
In thousands 2015 2014
Cardinal $15,083
 $16,073
Pine Needle 18,396
 18,689
SouthStar 41,325
 40,965
Hardy Storage 39,706
 37,179
Constitution 82,403
 57,255
ACP 10,043
 10
  Total equity method investments in non-utility activities $206,956
 $170,171

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

14.



109


15. Business Segments


We have twothree reportable business segments,segments: regulated utility, regulated non-utility activities 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 warranty programs,service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly ownedwholly-owned subsidiaries.

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


All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

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 non-utility activities segment based on earnings from the ventures.


Operations by segment for the years ended October 31, 2012, 20112015, 2014 and 2010,2013, and as of October 31, 2012, 20112015, 2014 and 20102013, are presented below.

    Regulated   Non-Utility    

In thousands

  

Utility

   

Activities

  

Total

 

2012

     

Revenues from external customers

  $    1,122,780   $-   $    1,122,780 

Margin

   575,446    -    575,446 

Operations and maintenance expenses

   242,599    102   242,701 

Depreciation

   103,192    18   103,210 

Income from equity method investments

   -     23,904   23,904 

Interest expense

   20,097    -    20,097 

Operating income (loss) before income taxes

   194,824    (264)   194,560 

Income before income taxes

   174,424    23,640   198,064 

Total assets

   3,475,640    88,247   3,563,887 

Equity method investments in non-utility activities

   -         87,867   87,867 

Construction expenditures

   529,576    -    529,576 
    Regulated   Non-Utility    

In thousands

  

Utility

   

Activities

  

Total

 

2011

     

Revenues from external customers

  $1,433,905   $-   $1,433,905 

Margin

   573,639    -    573,639 

Operations and maintenance expenses

   225,351    109   225,460 

Depreciation

   102,829    28   102,857 

Income from equity method investments

   -     24,027   24,027 

Interest expense

   43,992    -    43,992 

Operating income (loss) before income taxes

   207,079    (120)   206,959 

Income before income taxes

   161,925    23,929   185,854 

Total assets

   2,968,574    85,519   3,054,093 

Equity method investments in non-utility activities

   -     85,121   85,121 

Construction expenditures

   243,641    -    243,641 
    Regulated   Non-Utility    

In thousands

  

Utility

   

Activities

  

Total

 

2010

     

Revenues from external customers

  $1,552,295   $-   $1,552,295 

Margin

   552,592    -    552,592 

Operations and maintenance expenses

   219,829    301   220,130 

Depreciation

   98,494    29   98,523 

Income from equity method investments

   -     28,854   28,854 

Gain on sale of interest in equity method investment

   -     49,674   49,674 

Interest expense

   43,711    -    43,711 

Operating income (loss) before income taxes

   200,360    (697)   199,663 

Income before income taxes

   155,923    77,907   233,830 

Total assets

   2,784,087    80,808   2,864,895 

Equity method investments in non-utility activities

   -     80,287   80,287 

Construction expenditures

   199,059    -    199,059 


110


    Regulated
Unregulated  
  Regulated Non-Utility
Non-Utility  
In thousands Utility Activities
Activities Total
2015        
Revenues from external customers $1,371,718

$—
 $—

$1,371,718
Margin 727,294

—
 —

727,294
Operations and maintenance expenses 294,517

81
 105

294,703
Depreciation 128,704

—
 18

128,722
Operating income (loss) before income taxes 261,963

(152) (217)
261,594
Income from equity method investments —

15,060
 19,401

34,461
Interest charges 68,631

—
 —

68,631
Income before income taxes 193,140

14,909
 19,184

227,233
Total assets 4,742,284

165,630
 41,682

4,949,596
Equity method investments in non-utility activities —

165,630
 41,326

206,956
Construction expenditures 443,654

—
 —

443,654
         
  

Regulated
Unregulated  
   Regulated
Non-Utility
Non-Utility  
In thousands Utility
Activities
Activities Total
2014        
Revenues from external customers $1,469,988
 $—
 $—
 $1,469,988
Margin 690,208
 —
 —
 690,208
Operations and maintenance expenses 270,877
 132
 92
 271,101
Depreciation 118,996
 —
 18
 119,014
Operating income (loss) before income taxes 263,041
 (183) (203) 262,655
Income from equity method investments —
 12,318
 20,435
 32,753
Interest charges 54,686
 —
 —
 54,686
Income before income taxes 206,253
 12,135
 20,231
 238,619
Total assets (1)
 4,432,239
 129,206
 41,309
 4,602,754
Equity method investments in non-utility activities —
 129,206
 40,965
 170,171
Construction expenditures 460,444
 —
 —
 460,444
         
    Regulated Unregulated  
   Regulated Non-Utility Non-Utility  
In thousands Utility Activities Activities Total
2013        
Revenues from external customers $1,278,229
 $—
 $—
 $1,278,229
Margin 621,490
 —
 —
 621,490
Operations and maintenance expenses 253,120
 103
 78
 253,301
Depreciation 112,207
 —
 18
 112,225
Operating income (loss) before income taxes 221,528
 (150) (202) 221,176
Income from equity method investments —
 10,584
 15,472
 26,056
Interest charges 24,938
 —
 —
 24,938
Income before income taxes 194,659
 10,434
 15,270
 220,363
Total assets (1)
 4,045,259
 90,097
 38,735
 4,174,091
Equity method investments in non-utility activities —
 90,097
 38,372
 128,469
Construction expenditures 599,999
 —
 —
 599,999
         
(1) Regulated utility total assets have been adjusted in 2014 and 2013 to reflect the netting of debt issuance costs with its debt carrying value in accordance with the 2015 adoption of new accounting guidance related to this balance sheet presentation.

111


Reconciliations to the consolidated financial statements for the years ended October 31, 2012, 20112015, 2014 and 2010,2013, and as of October 31, 20122015 and 20112014 are as follows.

In thousands

  

2012

   

2011

   

2010

 

Operating Income:

      

Segment operating income before income taxes

    $194,560      $206,959      $199,663  

Utility income taxes

   (69,101)     (64,068)     (62,082)  

Non-utility activities operating loss before income taxes

   264     120     697  
  

 

 

   

 

 

   

 

 

 

Total

    $125,723      $143,011      $138,278  
  

 

 

   

 

 

   

 

 

 

Net Income:

      

Income before income taxes for reportable segments

    $198,064      $185,854      $233,830  

Income taxes

   (78,217)     (72,286)     (91,876)  
  

 

 

   

 

 

   

 

 

 

Total

    $119,847      $113,568      $    141,954  
  

 

 

   

 

 

   

 

 

 

In thousands

  

2012

   

2011

     
      

Consolidated Assets:

      

Total assets for reportable segments

    $  3,563,887      $  3,054,093    

Eliminations/Adjustments

   206,052     188,448    
  

 

 

   

 

 

   

Total

    $3,769,939      $3,242,541    
  

 

 

   

 

 

   

15.

In thousands 2015 2014 2013
Operating Income: 
    
Segment operating income before income taxes $261,594
 $262,655
 $221,176
Utility income taxes (76,934) (83,176) (77,334)
Regulated non-utility activities operating loss before income taxes 152
 183
 150
Unregulated non-utility activities operating loss before income taxes 217
 203
 202
Total $185,029
 $179,865
 $144,194
  
    
Net Income: 
    
Income before income taxes for reportable segments $227,233
 $238,619
 $220,363
Income taxes (90,222) (94,818) (85,946)
Total $137,011
 $143,801
 $134,417
In thousands 2015 2014  
Consolidated Assets:     
Total assets for reportable segments $4,949,596
 $4,602,754
 
Eliminations/Adjustments 161,154
 171,553
 
Total $5,110,750
 $4,774,307
 

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, capital stock, environmental mattersshort-term debt instruments, employee share-based plans and equity method investments, see Note 2,3, Note 6, Note 811 and Note 12,13, respectively, to the consolidated financial statements.

16.


17. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)

    Operating       Operating
Income		  

Net

Income

  

Earnings (Loss)

Per Share of

Common Stock

 
    

Revenues

   

Margin

   

(Loss)

  

(Loss)

  

Basic

  

Diluted

 

Fiscal Year 2012

         

January 31

  $    471,840   $    220,237   $      79,819  $      76,227  $          1.06  $          1.05 

April 30

   308,432    171,951    48,782   50,192   0.70   0.70 

July 31

   161,123    86,460    (2,513)   (4,613)   (0.06)   (0.06) 

October 31

   181,385    96,798    (365)   (1,959)   (0.03)   (0.03) 

Fiscal Year 2011

         

January 31

  $652,056   $230,006   $90,869  $84,440  $1.17  $1.16 

April 30

   392,567    172,931    52,927   47,408   0.66   0.66 

July 31

   197,274    81,963    389   (8,703)   (0.12)   (0.12) 

October 31

   192,008    88,739    (1,174)   (9,577)   (0.13)   (0.13) 

          Earnings (Loss)
      Operating Net Per Share of
   Operating   Income Income Common Stock
  Revenues Margin (Loss) (Loss) Basic Diluted
Fiscal Year 2015            
January 31 $607,271
 $270,070
 $105,758
 $92,978
 $1.18
 $1.18
April 30 424,924
 225,621
 75,123
 66,402
 0.84
 0.84
July 31 158,266
 111,572
 5,233
 (8,260) (0.10) (0.10)
October 31 181,257
 120,031
 (1,085) (14,109) (0.18) (0.18)
             
Fiscal Year 2014            
January 31 $657,733
 $261,512
 $102,319
 $97,572
 $1.27
 $1.26
April 30 462,247
 211,523
 67,299
 62,540
 0.80
 0.80
July 31 164,187
 104,847
 3,254
 (7,344) (0.09) (0.09)
October 31 185,821
 112,326
 6,993
 (8,967) (0.11) (0.11)

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.



112


Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure


None.


Item 9A. Controls and Procedures


Management’s Evaluation of Disclosure Controls and Procedures


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


We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the fourth quarter of fiscal 20122015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


113



MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING


December 21, 2012

23, 2015


Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined in Rules 13a-15(f) under the Securities Exchange Act of 1934 is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written Code of Ethics and Business Conduct adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.


Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.


We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control—Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, 2012,2015, our internal control over financial reporting was effective.


The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of October 31, 2012.

2015.


Piedmont Natural Gas Company, Inc.
 /s/ Thomas E. Skains
 

Thomas E. Skains

Chairman, President and Chief Executive Officer

 /s/ Karl W. Newlin
 

Karl W. Newlin

Senior Vice President and Chief Financial Officer

 /s/ Jose M. Simon
 

Jose M. Simon

Vice President and Controller



114



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina


We have audited the internal control over financial reporting of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2012,2015, based on the criteria established inInternal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.


We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.


A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2012,2015, based on the criteria established inInternal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.


We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended October 31, 20122015 of the Company and our report dated December 21, 201223, 2015 expressed an unqualified opinion on those financial statements.


/s/ Deloitte & Touche LLP


Charlotte, North Carolina

December 21, 2012

23, 2015


115




Item 9B. Other Information


None.


PART III


Item 10. Directors, Executive Officers and Corporate Governance


Information concerning our executive officers and directors is set forth in the sections entitled “Board of Directors” and “Executive Officers” in our Proxy Statement for the 20132016 Annual Meeting of Shareholders (2013(2016 Proxy Statement), which sections are incorporated in this annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our 20132016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.


Information concerning our Audit Committee and our Audit Committee financial experts is set forth in the section entitled “Committees of the Board” in our 20132016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.


We have adopted a Code of Ethics and Business Conduct that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, which serves as the code of ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions under Item 406(b) of Regulation S-K. The Code of Ethics and Business Conduct is available on the “For Investors-Corporate Governance” section of our website atwww.piedmontng.com. If we amend or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct that apply to the principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) of Regulation S-K, we will disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.


Item 11. Executive Compensation


Information for this item is set forth in the sections entitled “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our 20132016 Proxy Statement, which sections are incorporated in this annual report on Form 10-K by reference.


Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


Information for this item is set forth in the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our 20132016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.


Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our 20132016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.


Item 13. Certain Relationships and Related Transactions, and Director Independence


Information for this item is set forth in the section entitled “Director Independence and Related Person Transactions” in our 20132016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.


Item 14. Principal Accounting Fees and Services


Information for this item is set forth in “Proposal 2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year 2013”2016” in our 20132016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.


116



PART IV


Item 15. Exhibits, Financial Statement Schedules


(a)

 1. Financial Statements

The following consolidated financial statements for the year ended October 31, 2012,2015, are included in Item 8 of this report as follows:

Consolidated Balance Sheets – October 31, 20122015 and 2011

2014

Consolidated Statements of Comprehensive Income – Years Ended
October 31, 2012, 20112015, 2014 and 2010

2013

Consolidated Statements of Cash Flows – Years Ended
October 31, 2012, 20112015, 2014 and 2010

2013

Consolidated Statements of Stockholders’ Equity – Years Ended
October 31, 2012, 20112015, 2014 and 2010

2013

Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

(a)

 2. Supplemental Consolidated Financial Statement Schedules

None

Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

(a)

 3. Exhibits
  Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
  The exhibits numbered 10.1 through 10.2110.17 are management contracts or compensatory plans or arrangements.
2.1Agreement and Plan of Merger, dated as of October 24, 2015, by and among Duke Energy Corporation, Forest Subsidiary, Inc. and Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 2.1, Form 8-K dated October 26, 2015).
 3.1 Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009 (incorporated by reference to Exhibit 3.1, Form 10-Q for the quarter ended July 31, 2009).
 3.2 Bylaws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (incorporated by reference to Exhibit 3.1, Form 8-K dated September 13, 2011).

 4.1 Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).
 4.2 Amendment to September 1992 Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007).
 4.3 Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (incorporated by reference to Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).


117


 4.4 Medium-Term Note, Series A, dated as of October 6, 1993 (incorporated by reference to Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
 4.5 First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.2, Form S-3 Registration Statement No. 33-59369).
 4.6 Medium-Term Note, Series A, dated as of September 19, 1994 (incorporated by reference to Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
 4.7 Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 33-59369).
 4.8 Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (incorporated by reference to Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).
 4.9 Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (incorporated by reference to Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).
 4.10 Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).

 4.11 Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (incorporated by reference to Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).
 4.12 Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.3, Form S-3 Registration Statement No. 333-106268).
 4.13Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.1, Form 8-K, dated December 23, 2003).
4.14 Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.2, Form 8-K, dated December 23, 2003).
 4.154.14 Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (incorporated by reference to Exhibit 4.1, Form 8-K dated June 20, 2006).
 4.164.15 Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007).
 4.174.16 Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10, Form 8-K, dated May 12, 2011).
 4.184.17 Form of 2.92% Series A Senior Notes due June 6, 2016 (incorporated by reference to Exhibit 4.1, Form 8-K dated May 12, 2011).
 4.194.18 Form of 4.24% Series B Senior Notes due June 6, 2021 (incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011).


118


 4.204.19 Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386).

 4.214.20 Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011).
 4.224.21 Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1, Form 8-K dated March 29, 2012).
 4.234.22 Form of 3.47% Series A Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.1, Form 8-K dated March 29, 2012).
 4.244.23 Form of 3.57% Series B Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.2, Form 8-K dated March 29, 2012).
 4.254.24 Corporate Commercial Paper Master Note dated March 1, 2012 between U.S. Bank National Association as Paying Agent and Piedmont Natural Gas Company, Inc. as Issuer (incorporated by reference to Exhibit 4.1, Form 10-Q for the quarter ended April 30, 2012).
 4.25
Fifth Supplemental Indenture, dated August 1, 2013, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated August 1, 2013).


4.26
Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013).

4.27Sixth Supplemental Indenture, dated September 18, 2014, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 18, 2014).
4.28Form of 4.10% Senior Notes due 2034 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 18, 2014).
4.29Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 2014).
4.30Seventh Supplemental Indenture, dated September 14, 2015, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 14, 2015).
4.31Form of 3.60% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 14, 2015).
 Compensatory Contracts:
 10.1 Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (incorporated by reference to Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999).


119


 10.2 Severance Agreement with Thomas E. Skains, dated September 4, 2007 (substantially identical agreements have been entered into as of the same date with Franklin H. Yoho, Kevin M. O’Hara and Jane R. Lewis-Raymond) (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007).
 10.3 Schedule of Severance Agreements with Executives (incorporated by reference to Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007).
 10.4 Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (incorporated by reference to Appendix A, Form DEF14A dated January 14, 2011).

 10.5 Form of Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011).Agreement.
 10.6Resolution of Board of Directors, June 3, 2011, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2011).
10.7Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009).
10.8 Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2009).
 10.9Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (incorporated by reference to Exhibit 4.1, Form 8-K dated April 3, 2009).
10.1010.7 Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2009).
 

10.11

10.8		 Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010).
 10.12Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011. (incorporated by reference to Exhibit 10.19, Form 10-K for the fiscal year ended October 31, 2011).
10.13Form of 2013 Retention Award Agreement, dated as of December 15, 2010 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2011).

10.14Consulting Agreement dated as of November 1, 2011 between David J. Dzuricky and Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.21, Form 10-K for the fiscal year ended October 31, 2011).
10.1510.9 Instrument of Amendment for Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of January 23, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2012).
 10.1610.10 2011 Retention Award Agreement, dated December 15, 2011, between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2012).
 10.17Employment Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2012).
10.1810.11 Severance Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2012).
 10.1910.12 Amended and Restated Employment Agreement, dated May 25, 2012, between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho) (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2012).
 10.2010.13 Schedule of Amended and Restated Employment Agreements with Executives (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2012).
 10.2110.14 Amendment to the Piedmont Natural Gas Company Employee Stock Purchase Plan dated September 18, 2012, by Piedmont Natural Gas Company, Inc.

Other Contracts:
10.22Amended and Restated Limited Liability Company AgreementResolution of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas CompanyBoard of Directors, June 6, 2014, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004)July 31, 2014).
 10.2310.15 First Amendment toPiedmont Natural Gas Company Employee Stock Purchase Plan Amended and Restated Limited Liability Company Agreementas of SouthStar Energy Services LLC,November 1, 2014, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2006).
10.24Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006).
10.25Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 2006).
10.26Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas CompanyJanuary 30, 2015 (incorporated by reference to Exhibit 10.1, Form 8-K dated November 16, 2004)10-Q for the quarter ended January 31, 2015).


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 10.2710.16 Operating Agreement of Hardy StoragePiedmont Natural Gas Company, LLC,Inc. Voluntary Deferral Plan, amended and restated effective March 31, 2015, dated as of November 12, 2004May 1, 2015 (incorporated by reference to Exhibit 10.3,10.1, Form 8-K dated November 16, 2004)10-Q for the quarter ended July 31, 2015).
 10.2810.17 Second Amendment to Amended and Restated Limited Liability Company AgreementResolution of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009Board of Directors, June 5, 2015, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009)2015).
 10.29 Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.1, Form 8-K dated August 4, 2009).

Other Contracts:
 10.30Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.2, Form 8-K dated August 4, 2009).
10.31Credit Agreement dated as of January 25, 2011 among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender, and L/C Issuer, Branch Banking and Trust Company and U.S. Bank National Association as Co-Syndication Agents, and the other Lenders party thereto (incorporated by reference to Exhibit 10.1, Form 8-K filed January 31, 2011).
10.32Amendment No. 1 to Credit Agreement dated as of March 21, 2011 by and among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the Lenders thereunder (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2011).
10.3310.18 Form of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and Dealers party thereto (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2012).
 10.3410.19 Amended and Restated Credit Agreement dated as of October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender.Lender (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2012).
10.20Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC dated April 9, 2012, by and among Williams Partners Operating LLC and Cabot Pipeline Holdings LLC (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2013).
10.21First Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of November 9, 2012, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, and Piedmont Constitution Pipeline Company, LLC (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2013).
10.22Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1, Form 8-K filed September 4, 2013).
10.23Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company (incorporated by reference to Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 2013).
10.24Increasing Lender Agreement dated as of November 1, 2013 among Wells Fargo Bank, National Association, Bank of America, N.A., Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each as a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated November 4, 2013).

10.25 *Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc. (incorporated by reference to Exhibit 10.35, Form 10-K for the fiscal year ended October 31, 2014).
10.26ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 1.1, Form 8-K dated January 7, 2015).


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10.27ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.2, Form 8-K dated January 7, 2015).
 12 Computation of Ratio of Earnings to Fixed Charges.

 21 List of Subsidiaries.
 23.1 Consent of Independent Registered Public Accounting Firm.
 31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
 31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.
 32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.


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

101.SCH

 XBRL Taxonomy Extension Schema
 

101.CAL

 XBRL Taxonomy Calculation Linkbase
 

101.DEF

 XBRL Taxonomy Definition Linkbase
 

101.LAB

 XBRL Taxonomy Extension Label Linkbase
 

101.PRE

 XBRL Taxonomy Extension Presentation Linkbase
*Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets as of October 31, 2015 and 2014; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2015, 2014 and 2013; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2015, 2014 and 2013; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2015, 2014 and 2013; and Notes to Consolidated Financial Statements.

Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2012 and 2011; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2012, 2011 and 2010; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2012, 2011 and 2010; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2012, 2011 and 2010; and Notes to Consolidated Financial Statements.


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SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Piedmont Natural Gas Company, Inc.
 (Registrant)
By: /s/ Thomas E. Skains
 Thomas E. Skains
 Chairman of the Board, President
 and Chief Executive Officer
Date: December 21, 201223, 2015


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title
Signature
Title
/s/ Thomas E. Skains   Chairman of the Board, President and
Thomas E. Skains Chief Executive Officer
 (Principal Executive Officer)
Date: December 21, 201223, 2015 
/s/ Karl W. Newlin     Senior Vice President and
Karl W. Newlin Chief Financial Officer
 (Principal Financial Officer)
Date: December 21, 201223, 2015 
/s/ Jose M. Simon     Vice President and Controller
Jose M. Simon (Principal Accounting Officer)
Date: December 21, 201223, 2015 


123


Signature Title
Signature
Title

/s/ E. James Burton

    Director
E. James Burton    

/s/ Malcolm E. Everett III

    Director
Malcolm E. Everett III    

/s/ John W. Harris

Gary A. Garfield		    Director
John W. HarrisGary A. Garfield    

/s/ Aubrey B. Harwell, Jr.

Director
Aubrey B. Harwell, Jr.

/s/ Frank B. Holding, Jr.

    Director
Frank B. Holding, Jr.    

/s/ Frankie T. Jones, Sr.		    Director
Frankie T. Jones, Sr.    

/s/ Vicki W. McElreath

    Director
Vicki W. McElreath    

/s/ Thomas M. Pashley

Director
Thomas M. Pashley
/s/ Minor M. Shaw

    Director
Minor M. Shaw    

/s/ Muriel W. Sheubrooks

Jo Anne Sanford		    Director
Muriel W. SheubrooksJo Anne Sanford    

/s/ David E. Shi

    Director
David E. Shi    

/s/ Michael C. Tarwater

Director
Michael C. Tarwater
/s/ Phillip D. Wright

    Director
Phillip D. Wright    

Piedmont Natural Gas Company, Inc.

Form 10-K

For the Fiscal Year Ended October 31, 2012

Exhibits


124


10.21 Amendment to the Piedmont Natural Gas Company Employee Stock Purchase Plan dated September 18, 2012, by Piedmont Natural Gas Company, Inc.
10.34 Amended and Restated Credit Agreement dated as of October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender.Form 10-K
For the Fiscal Year Ended October 31, 2015
Exhibits
10.5Form of Performance Unit Award Agreement
12  Computation of Ratio of Earnings to Fixed Charges
21  List of Subsidiaries
23.1  Consent of Independent Registered Public Accounting Firm
31.1  Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2  Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1  Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2  Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer



125