10-K 1 d644063d10k.htm 10-K 10-K
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

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

    For the fiscal year ended October 31, 2013

or

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

    For the transition period from                          to                         

    Commission file number 1-6196

 

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

 

North Carolina

  

56-0556998

(State or other jurisdiction of 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. Yes x No ¨

    Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ¨ No x

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. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x 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. x

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

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2013.

Common Stock, no par value - $2,575,772,202

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 13, 2013

Common Stock, no par value    76,116,503

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 6, 2014 are incorporated by reference into Part III.


Table of Contents

Piedmont Natural Gas Company, Inc.

2013 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

 

         Page  
Part I.     
  Item 1.  

Business

     1   
  Item 1A.  

Risk Factors

     11   
  Item 1B.  

Unresolved Staff Comments

     19   
  Item 2.  

Properties

     19   
  Item 3.  

Legal Proceedings

     20   
  Item 4.  

Mine Safety Disclosures

     20   
Part II.     
  Item 5.   Market for Registrant’s Common Equity, Related
  Stockholder Matters and Issuer Purchases of Equity Securities
     21   
  Item 6.   Selected Financial Data      24   
  Item 7.   Management’s Discussion and Analysis of Financial
  Condition and Results of Operations
     24   
  Item 7A.   Quantitative and Qualitative Disclosures about Market Risk      56   
  Item 8.   Financial Statements and Supplementary Data      58   
  Item 9.   Changes in and Disagreements With Accountants on
  Accounting and Financial Disclosure
     134   
  Item 9A.   Controls and Procedures      134   
  Item 9B.   Other Information      137   
Part III.     
  Item 10.   Directors, Executive Officers and Corporate Governance      137   
  Item 11.   Executive Compensation      137   
  Item 12.   Security Ownership of Certain Beneficial Owners and
  Management and Related Stockholder Matters
     137   
  Item 13.   Certain Relationships and Related Transactions, and Director
  Independence
     138   
  Item 14.   Principal Accounting Fees and Services      138   
Part IV.     
  Item 15.   Exhibits, Financial Statement Schedules      139   
  Signatures      148   


Table of Contents

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

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 two reportable business segments, regulated utility and 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 non-utility activities segment consists of our equity method investments in joint venture energy-related businesses. The percentage of assets as of October 31, 2013 and earnings before taxes by segment for the year ended October 31, 2013 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%   
  

 

 

       

 

 

 

Operations of both segments are conducted within the United States of America. 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.

 

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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. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulator-approved sharing mechanisms between our utility customers and our shareholders. Operations of the non-utility activities segment are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”

Operating revenues by major customer class for the years ended October 31, 2013 and 2012 are presented below.

 

     2013      2012  

Residential customers

     46 %         48 %   

Commercial customers

     26 %         27 %   

Large volume customers, including industrial, power generation and resale customers

     15 %         12 %   

Secondary market activities

     12 %         12 %   

Other sources

     1 %         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, 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. 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.

We hold non-exclusive franchises for natural gas service in many of the communities we serve, with expiration dates from December 2013 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

 

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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 a specific franchise agreement 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. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag through 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.

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 recover certain costs through tracking mechanisms or riders without the need to file general base rate cases. They can also recognize the impact of energy efficiency and conservation on a utility’s revenue stream and thus separate or decouple 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. The approval of our settlement with the Public Staff of the 2013 NCUC rate proceeding includes implementation of an IMR in North Carolina that will separately track and recover the costs associated with capital expenditures to comply with federal pipeline safety and integrity requirements. Under this mechanism, we will make annual filings every November to capture costs closed to plant through October with revised rates effective the following February. A similar mechanism in Tennessee was approved by the TRA in December 2013. In South Carolina, we operate under a rate stabilization adjustment (RSA) tariff mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina 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. Our WNA formulas calculate the actual weather variance from normal, using 30 years of history, and increase revenues when weather is warmer than normal and decrease revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors and when weather is significantly warmer than normal or colder than normal. Weather in 2013 on average over our three-state market area was 2% colder than normal and 25% colder than 2012. For the year ended October 31, 2013, the margin decoupling mechanism in North Carolina increased margin by $6 million, and the WNA mechanisms in South Carolina and Tennessee together increased margin by $3 million.

 

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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 increasing levels of margin stabilization. The following table presents the breakdown of our gas utility margin for the years ended October 31, 2013, 2012 and 2011. For further information, see Note 2 to the consolidated financial statements in this Form 10-K.

 

     2013        2012        2011  

Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts)

     73 %            72 %            70 %    

Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)

     16 %            17 %            18 %    

Volumetric or periodic renegotiation

     11            11            12    

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.

Our Strategies

We monitor our progress and measure our performance related to our strategic directives and 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, employee satisfaction, operations and maintenance (O&M) expense discipline, employee health and safety, pipeline safety, and sustainable business practices.

Safety is a critical component to our ongoing success as a company. We have always placed a high 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 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 currently being discussed by federal regulators include possible mandates addressing the integrity verification process of maximum allowable operating pressure of transmission pipelines. Potential regulatory changes resulting from the rulemaking could increase our future capital and O&M expenditures for pipeline integrity, safety and compliance. 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.

 

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We believe natural gas is a safe and reliable energy source that is clean, affordable, reliable and environmentally responsible. It is also 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.

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 see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We continued to execute our plan in 2013 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.

With the environmental and cost benefits of using natural gas compared to coal in the generation of electricity, we have participated in the development of gas-fired power generation facilities in our market area. We completed pipeline expansion projects over the last three fiscal years to provide long-term natural gas delivery service to new power generation facilities in our market area. 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 and has enhanced future opportunities for economic growth and development.

Our capital program primarily supports our system infrastructure and the growth in our customer base. We are increasing our spending for 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 2014 – 2016, 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 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 and innovative rate designs for the benefit of our customers and shareholders.

 

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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 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.

To further our strategy of expanding our complementary energy-related businesses, in November 2012, we became 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 approximately 120 miles of interstate natural gas pipeline and related facilities 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 of 24% for the development and construction of the new pipeline, which is expected to cost approximately $680 million. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

 

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Operating Statistics

The following is a five-year comparison of operating statistics for the years ended October 31, 2009 through 2013.

 

    

2013

    

2012

    

2011

    

2010

    

2009

 

Operating Revenues (in thousands):

              

Sales and Transportation:

              

Residential

     $ 588,546         $ 534,321         $ 658,892         $ 743,346         $ 787,994   

Commercial

     331,831         301,013         379,846         428,085         462,160   

Industrial

     113,182         95,177         104,774         116,122         126,855   

Power Generation

     64,109         36,027         28,969         21,708         19,609   

For Resale

     9,549         9,512         9,692         11,061         11,746   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,107,217         976,050         1,182,173         1,320,322         1,408,364   

Secondary Market Sales

     164,130         140,380         244,824         224,973         221,300   

Miscellaneous

     6,882         6,350         6,908         7,000         8,452   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     $     1,278,229         $     1,122,780         $     1,433,905         $     1,552,295         $     1,638,116   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Gas Volumes - Dekatherms

              

(in thousands):

              

System Throughput:

              

Residential

     55,283         43,788         57,778         58,327         55,298   

Commercial

     39,602         33,774         40,749         39,994         38,526   

Industrial

     95,019         89,234         90,842         82,805         74,363   

Power Generation

     190,862         151,675         83,522         63,024         39,639   

For Resale

     6,834         5,829         6,870         8,465         9,048   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     387,600         324,300         279,761         252,615         216,874   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Secondary Market Sales

     41,605         48,373         48,835         46,823         46,057   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Number of Customers Billed

              

(12-month average):

              

Residential

     890,887         878,851         871,401         864,205         855,670   

Commercial

     96,009         95,100         94,485         94,287         94,404   

Industrial

     2,271         2,265         2,265         2,273         2,358   

Power Generation

     24         22         22         20         20   

For Resale

     15         15         15         16         17   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     989,206         976,253         968,188         960,801         952,469   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Cost of Gas (in thousands):

              

Natural Gas Commodity Costs

     $     526,703         $     379,145         $     666,930         $     753,529         $     727,744   

Capacity Demand Charges

     151,369         129,090         136,139         127,137         128,081   

Natural Gas Withdrawn From

              

(Injected Into) Storage, net

     (5,867)         27,580         11,362         5,293         126,480   

Regulatory Charges (Credits), net

     (15,466)         11,519         45,835         113,744         94,237   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $     656,739       $     547,334       $     860,266       $     999,703       $     1,076,542   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Supply Available for Distribution

              

(dekatherms in thousands):

              

Natural Gas Purchased

     142,884         132,426         155,550         157,021         149,696   

Transportation Gas

     287,980         235,474         175,005         147,038         115,519   

Natural Gas Withdrawn From

              

(Injected Into) Storage, net

     (509)         (378)         196         (1,309)         1,010   

Company Use

     (369)         (296)         (309)         (282)         (283)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     429,986         367,226         330,442         302,468         265,942   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

During the year ended October 31, 2013, we delivered 387.6 million dekatherms to our utility retail customers compared to 324.3 million dekatherms the year before. Of this amount, 292.7 million dekatherms of gas were sold to or transported for large volume customers compared with 246.7 million dekatherms in 2012. Of these volumes sold to or transported for large volume

 

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customers, we transported 190.9 million dekatherms in 2013 to power generation facilities compared with 151.7 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 weather, totaled 94.9 million dekatherms in 2013, compared with 77.6 million dekatherms in 2012. Weather, as measured by degree days, was 2% colder than normal in 2013 and 19% warmer than normal in 2012.

With continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas in our service areas, we have made gains in utility customer growth. For the year ended October 31, 2013 and 2012, we added the following new customers.

 

     2013     2012  

Residential new home construction

     10,299        7,939    

Residential conversion

     2,463        3,789 

Commercial

           1,512              1,546    
  

 

 

   

 

 

 

  Total new customers

         14,274            13,274    
  

 

 

   

 

 

 

* Includes a large, multi-unit conversion project.

We forecast continuing gross customer growth in fiscal 2014 of approximately 1.5%.

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 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, 2013, we had contracts for the following pipeline firm transportation in dekatherms per day.

 

Williams-Transco

     632,200   

El Paso-Tennessee Pipeline

     74,100   

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

     36,700   

Oneok-Midwestern (through either Tennessee, Columbia Gulf, East Tennessee or Transco)

     120,000   

NiSource-Columbia Gas (through Transco and Columbia Gulf)

     42,800   

NiSource-Columbia Gulf

     15,000   
  

 

 

 

Total

         920,800   
  

 

 

 

 

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As of October 31, 2013, 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)

     250,000   

Pine Needle LNG (through Transco)

     263,400   

Williams-Transco Storage

     86,100   

NiSource-Columbia Gas Storage

     96,400   

Hardy Storage (through Columbia Gas and Transco)

     68,800   

Dominion Storage (through Transco)

     13,200   

Kinder Morgan-Tennessee Pipeline Storage

     55,900   
  

 

 

 

Total

         833,800   
  

 

 

 

As of October 31, 2013, we own or have under contract 35.5 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capacity is used to supplement or replace regular pipeline supplies.

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, 2013, the amount of natural gas in storage varied from 10.9 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 25.1 million dekatherms, and the weighted average commodity cost of this gas in storage varied from $43.6 million to $95.5 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 six years, we have been 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 serve. 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.

We purchase our 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. 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.

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.

 

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In November 2012, we continued to diversify our supply portfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply arrangements are scheduled to begin in late 2015, and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.

Competition

The regulated utility competes with 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. 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 lead to slower customer growth or customer conservation, or both, resulting in reduced gas purchases and customer billings. In turn, this can impact our capital expenditures and overall cash needs, including working capital needs. 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. However, the use of natural gas for power generation also adds significant value as a result of natural gas’ environmental attributes, competitive cost advantage and efficiency of delivery.

During the year ended October 31, 2013, approximately 4% 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 prices. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the U.S. dollar versus other currencies. Our margin 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, 2013, no bypass occurred. The future level of bypass activity cannot be predicted.

Natural gas for power generation competes with other fuel sources for the generation of electricity, including coal, nuclear and renewable resources. Additionally, as with industrial customers, we compete with other pipeline providers to serve the generation plants.

 

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Other

During the year ended October 31, 2013, our largest revenue generating customer contributed $75.4 million, or 6%, of total operating revenues. Our largest margin generating customer contributed $53.1 million, or 9% 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 in 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 components 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 when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. See discussion above for information on IMRs to track and recover costs in North Carolina and Tennessee outside of a general rate case. In South Carolina, we operate under a rate stabilization mechanism that reduces regulatory lag to one year, but we reserve the right to file general rate cases when necessary. Regulatory lag can impact earnings.

As of October 31, 2013, our fiscal year end, we had 1,795 employees compared with 1,752 as of October 31, 2012.

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 at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission.

Item 1A. Risk Factors

An overall economic downturn could negatively impact our earnings.

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.

 

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

A supply and demand imbalance 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 Commodity 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 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 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 or requirements, including remediation 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.

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 filed that could result in an adjustment of our returns. Once rate cases are

 

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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. All of this 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. State regulators have approved various mechanisms to stabilize our gas utility margin, including margin decoupling in North 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 supply 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 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

 

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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, 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 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. 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. As the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. All of these events 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 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.

 

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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 do not ensure full protection, especially for significantly warmer-than-normal winter weather. As a result of these events, our results of operations and earnings could vary and be negatively impacted.

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.

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 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 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 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.

 

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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 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 experience 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 rates, 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 flow.

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 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 our CP program is dependent on investor demand for our commercial paper. Disruptions and volatility in the global credit markets could limit the demand for our commercial paper or result in the need to offer higher interest rates to investors, which would result in higher expense and could adversely impact 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.

 

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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 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 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.

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 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.

 

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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.

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. 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. All the above could adversely affect our earnings from or return of our investment in these businesses. We could make future equity method investments or acquisitions of regulated or 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 results of operations or financial condition.

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 skilled workforce, our ability to provide safe quality service to our customers and meet our regulatory requirements will be challenged, and this could negatively impact our earnings.

 

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Cyber-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, 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. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.

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. These 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 and property insurance in place in amounts that we consider appropriate 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 for 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.

Item 1B. Unresolved Staff Comments

None.

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 2,900 linear miles of transmission pipeline up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline

 

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suppliers. We distribute natural gas through approximately 22,000 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” 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 is comprised of land located in Robeson County, North Carolina. For further information on this Robeson County property, see Note 1 and Note 2 to the consolidated financial statements in this 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 $4.2 million for the year ended October 31, 2013.

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 litigation in the normal course of business.

Item 4. Mine Safety Disclosures

Not applicable.

 

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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, 2013 and 2012.

 

2013         High      Low         2012        High      Low  

Quarter ended:

          Quarter ended:      

    January 31

     $  33.10      $   28.51           January 31    $   34.74      $   29.90  

    April 30

     34.92        31.73           April 30      34.00        29.05  

    July 31

     35.53        32.39           July 31      33.03        28.90  

    October 31

     35.05        31.56           October 31      33.72        31.03  

Holders

As of December 13, 2013, our common stock was owned by 13,749 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, 2013 and 2012. We expect that comparable cash dividends will continue to be paid in the future.

 

     Dividends Paid              Dividends Paid
2013          

Per Share

       

2012

  

Per Share

Quarter ended:

         Quarter ended:   

January 31

   30¢      

January 31

   29¢

April 30

   31¢      

April 30

   30¢

July 31

   31¢      

July 31

   30¢

October 31

   31¢      

October 31

   30¢

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, 2013, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

 

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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, 2013.

 

Period

  

Total Number

of Shares

Purchased

  

Average Price

Paid Per Share

  

Total Number of

Shares Purchased

as Part of Publicly

Announced Program

  

Maximum Number

of Shares that May

Yet be Purchased

Under the Program (1)

Beginning of the period

              2,910,074

8/1/13 - 8/31/13

   -   

$

  -        -    2,910,074

9/1/13 - 9/30/13

   -   

$

  -        -    2,910,074

10/1/13 - 10/31/13

   -   

$

  -        -    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. 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, 2014, in connection with our Annual Meeting to be held on March 6, 2014, 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, 2008 through October 31, 2013 (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). Our LDC Peer Group index is comprised of peer group companies that are domiciled in the United States, publicly traded in 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 relative total shareholder returns, which we use for market benchmarking for our executive compensation plans.

 

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The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2008 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, 2008

 

LOGO

 

 

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.

 

    

2008

    

2009

    

2010

    

2011

    

2012

    

2013

 

Piedmont

   $         100      $           74      $           97      $         112      $         113      $         126  

LDC Peer Group

     100        104        132        156        167        205  

S&P 500 Index

     100        110        128        138        159        203  

This graph represents the relative value of an investment in Common Stock made on a particular day, October 31, 2008. On that particular day, Piedmont’s common stock closed at $32.92, within 99% of a new all-time high price of $33.24 reached on September 19, 2008, having surged in price during the U.S. and world financial crisis that occurred in the late summer and fall of 2008. During that time, the S&P 500 dropped dramatically, and most of our LDC Peer Group stock prices declined as well, with lower closing stock values on October 31, 2008 compared to Piedmont. By early February 2009, the price of Piedmont’s stock declined to pre-August 2008 levels and did not close above $27 until late December 2009. Piedmont’s ten- and twenty-year cumulative total returns (from October 31, 2003 and October 31, 1993) are 153% and 527%, respectively, versus 105% and 454% for the S&P 500 and 160% and 436% for the LDC Peer Group.

 

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Item 6. Selected Financial Data

The following table provides selected financial data for the years ended October 31, 2009 through 2013.

 

In thousands except per share amounts

  

2013

    

2012

    

2011

    

2010

    

2009

 

Operating Revenues

   $ 1,278,229      $ 1,122,780      $ 1,433,905      $ 1,552,295      $ 1,638,116  

Margin (operating revenues less cost of gas)

   $ 621,490      $ 575,446      $ 573,639      $ 552,592      $ 561,574  

Net Income

   $ 134,417      $ 119,847      $ 113,568      $ 141,954      $ 122,824  

Earnings per Share of Common Stock:

              

Basic

   $ 1.80      $ 1.67      $ 1.58      $ 1.96      $ 1.68  

Diluted

   $ 1.78      $ 1.66      $ 1.57      $ 1.96      $ 1.67  

Cash Dividends per Share of Common Stock

   $ 1.23      $ 1.19      $ 1.15      $ 1.11      $ 1.07  

Total Assets

   $   4,368,609      $   3,769,939      $   3,242,541      $   3,053,275      $   3,118,819  

Long-Term Debt (less current maturities)

   $ 1,174,857      $ 975,000      $ 675,000      $ 671,922      $ 732,512  

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

Forward-Looking Statements

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

 

   

Economic conditions in our markets

   

Wholesale price of natural gas

   

Availability of adequate interstate pipeline transportation capacity and natural gas supply

   

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

   

Competition from other companies that supply energy

   

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

   

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

   

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

   

Weather conditions

   

Operational interruptions to our gas distribution and transmission activities

   

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

   

Elevated levels of capital expenditures

   

Our credit ratings

   

Availability and cost of capital

   

Federal and state fiscal, tax and monetary policies

   

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

 

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Ability to satisfy all of our outstanding debt obligations

   

Ability of counterparties to meet their obligations to us

   

Costs of providing pension benefits

   

Earnings from the joint venture businesses in which we invest

   

Ability to attract and retain professional and technical employees

   

Risk of cyber-attack, acts of cyber-terrorism, or failure of technology systems

   

Ability to obtain and maintain sufficient insurance

   

Change in number of outstanding shares

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

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

Overview

Piedmont Natural Gas Company, Inc. is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation businesses.

We operate with two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities. Factors critical to the success of the regulated utility 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 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.

 

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Executive Summary

A summary of our annual results is as follows:

Comprehensive Income Statement Components

                          Percent Change  
                          2013 vs.     2012 vs.  
In thousands except per share amounts    2013      2012      2011      2012     2011  

Operating Revenues

     $   1,278,229         $   1,122,780         $   1,433,905         13.8     (21.7 )% 

Cost of Gas

     656,739         547,334         860,266         20.0     (36.4 )% 
  

 

 

    

 

 

    

 

 

      

  Margin

     621,490         575,446         573,639         8.0     0.3
  

 

 

    

 

 

    

 

 

      

Operations and Maintenance

     253,120         242,599         225,351         4.3     7.7

Depreciation

     112,207         103,192         102,829         8.7     0.4

General Taxes

     34,635         34,831         38,380         (0.6 )%      (9.2 )% 

Utility Income Taxes

     77,334         69,101         64,068         11.9     7.9
  

 

 

    

 

 

    

 

 

      

  Total Operating Expenses

     477,296         449,723         430,628         6.1     4.4
  

 

 

    

 

 

    

 

 

      

Operating Income

     144,194         125,723         143,011         14.7     (12.1 )% 

Other Income (Expense), net of tax

     15,161         14,221         14,549         6.6     (2.3 )% 

Utility Interest Charges

     24,938         20,097         43,992         24.1     (54.3 )% 
  

 

 

    

 

 

    

 

 

      

Net Income

     $ 134,417         $ 119,847         $ 113,568         12.2     5.5
  

 

 

    

 

 

    

 

 

      

Average Shares of Common Stock:

             

  Basic

     74,884         71,977         72,056         4.0     (0.1 )% 

  Diluted

     75,333         72,278         72,266         4.2     -

Earnings per Share of Common Stock:

             

  Basic

     $ 1.80         $ 1.67         $ 1.58         7.8     5.7

  Diluted

     $ 1.78         $ 1.66         $ 1.57         7.2     5.7

 

Margin by Customer Class   

In thousands

  

2013

   

2012

   

2011

 

Sales and Transportation:

               

Residential

     $ 331,920         54   $ 321,056         56   $ 319,675         56

Commercial

     155,065         25     150,306         26     150,681         26

Industrial

     52,268         8     46,993         8     47,176         8

Power Generation

     56,312         9     32,289         6     23,970         4

For Resale

     7,477         1     7,465         1     8,550         2
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

     603,042         97     558,109         97     550,052         96

Secondary Market Sales

     8,979         1     9,681         2     14,016         2

Miscellaneous

     9,469         2     7,656         1     9,571         2
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

     $       621,490           100     $       575,446           100     $       573,639           100
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

 

                    Percent Change
                    2013 vs.    2012 vs.
    

2013

  

2012

  

2011

  

2012

  

2011

Deliveries in Dekatherms (in thousands):

                        

Residential

       55,283          43,788          57,778          26.3 %          (24.2)%  

Commercial

       39,602          33,774          40,749          17.3 %          (17.1)%  

Industrial

       95,019          89,234          90,842          6.5 %          (1.8)%  

Power Generation

       190,862          151,675          83,522          25.8 %          81.6 %  

For Resale

       6,834          5,829          6,870          17.2 %          (15.2)%  
                                                        

Throughput

       387,600          324,300          279,761          19.5 %          15.9 %  
                                                        

Secondary Market Volumes

       41,605          48,373          48,835          (14.0)%          (0.9)%  
                                                        

Customers Billed (at period end)

       979,909          969,239          958,307          1.1 %          1.1 %  

Gross Residential and Commercial Customer Additions

       14,274          13,274          10,522          7.5 %          26.2 %  

Degree Days

                        

Actual

       3,336          2,668          3,662          25.0 %          (27.1)%  

Normal

       3,276          3,310          3,318          (1.0)%          (0.2)%  

Percent colder (warmer) than normal

       1.8 %          (19.4)%          10.4 %          n/a          n/a  
                                                        

Number of Employees (at period end)

       1,795          1,752          1,782          2.5 %          (1.7)%  
                                                        

Financial Performance – Fiscal 2013 Compared with Fiscal 2012

We closed the fiscal year with a 12% increase in net income. Margin increased 8% primarily due to increased transportation services from new contracts for power generation customers and higher volumes delivered to residential, commercial and industrial customers due to colder weather and customer growth. Operations and maintenance (O&M) expenses and depreciation expense increased 4% and 9%, respectively. The increase in O&M expenses was related to higher costs for contract labor related to process improvement and pipeline integrity programs, payroll from short-term incentive plans, bad debt expense and regulatory amortizations, partially offset by a decrease in employee benefits costs. Depreciation was higher due to increases in plant in service from our capital expansion programs for customer growth, power generation, pipeline delivery projects and system integrity and infrastructure investments. Other Income (Expense) increased 7% with an increase in income from equity method investments, including additional markets served by one of our investments and a new pipeline venture investment on November 1, 2012, partially offset by the cumulative amortization of non-real estate costs related to the allowed deferral of a regulatory asset for certain non-real estate costs included in the 2013 settlement agreement as approved by the NCUC in December 2013. Utility interest charges increased 24% due to increases in long-term debt, partially offset by an increase in capitalized interest income and lower balances of short-term debt used from our commercial paper (CP) program at lower interest rates.

Business Summary – Fiscal 2013 Compared with Fiscal 2012

Our fiscal 2013 performance reflects our continued execution of our long-term business strategy. As discussed above, financial performance was solid for the year with increased earnings and an increase in our dividend rate per share to our investors.

Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we 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 with a goal of maintaining a long-term debt to capital ratio between 45% and 50%. To meet our short-term liquidity needs, we continue to rely on our CP program.

 

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We issued long-term debt and equity during fiscal 2013 for total proceeds of $389.8 million. In February 2013, we issued 3 million shares of our common stock and entered into forward sale agreements (FSAs) related to the future issuance of up to an additional 1.6 million shares. Early in fiscal 2014, we issued 1.6 million shares on December 16, 2013 under the FSAs, receiving proceeds of $47.3 million. In August 2013, we issued $300 million of 30-year, unsecured senior notes. In November 2013, we entered into an agreement with our revolving credit facility lenders to increase our borrowing capacity to $850 million. For further information on these transactions, see Note 4, Note 5 and Note 6 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 November 2012, in order to provide additional 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 capacity and supply arrangements are scheduled to begin in late 2015.

Customer Growth – We have added more customers in our service areas each year during our last three fiscal years. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. With continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas, total residential and commercial customer additions increased 8% in 2013 compared to 2012. Customer gains in our residential new construction and conversion markets increased 9% in 2013 compared to 2012. Commercial customer additions decreased 2% in 2013 compared to 2012, reflecting a slight reduction in new commercial construction activity coupled with a longer sales cycle for conversions.

Capital Expenditures – We continued to execute our large capital expansion 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 increased capital expenditures are currently being driven by increased expenditures for pipeline integrity, safety and compliance programs, and investments for customer growth and systems and technology infrastructure, specifically a new comprehensive work and asset management system.

We completed pipeline expansion projects over our last three fiscal years that provide natural gas delivery service to new power generation facilities in our market area. We currently provide service to a total of 23 power generation customer accounts and two power generation fuel tracker customer accounts. See the discussion of our forecasted capital investments 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.

As we incur significantly higher capital costs under our system integrity programs, we have sought new regulatory mechanisms that will allow us to recover and earn on those investments in a timely manner. In December 2013, the NCUC approved the settlement of our 2013 general rate application, including the implementation of an integrity management rider (IMR)

 

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to separately track and recover the costs associated with capital expenditures in order to comply with federal pipeline safety and integrity requirements. Under the IMR tariff, we will make annual filings every November to capture such costs closed to plant through October with revised rates effective the following February. With its approval of the settlement, the NCUC continued to allow regulatory asset treatment of our external pipeline integrity management O&M costs and recovery of these costs through future amortization in rates. In August 2013, we filed for an IMR in Tennessee to recover the costs of our capital investments associated with federal and state mandated safety and integrity programs, the settlement of which was approved by the TRA in December 2013. The effective date is January 1, 2014 for the first rate adjustment under the rider based on capital expenditures incurred through October 2013 with annual rate updates thereafter.

Business Process and Technology Improvements – We are in the process of a multi-year, multi-project program designed to bring additional technology and automation to our field operations by providing systems, tools 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.

Regulatory and Legislative Activity – We continue our regulatory strategy to implement rate structures that better align and balance the interests of shareholders and customers. As discussed above with the NCUC approval of the settlement of our 2013 general rate application, we will make an adjustment in our rates and charges to provide incremental annual total revenues of $30.7 million, an increase of 3.58% over pre-existing rates, with an annual pre-tax income increase of $24.2 million, effective January 1, 2014. This revenue increase is a .7% annual rate increase for our customers since the last general rate proceeding in 2008. The new rates are based on a rate base in North Carolina of $1.8 billion as of September 30, 2013, an equity capital structure component of 50.7% and a return on common equity of 10%.

An important outcome from the NCUC approved rate settlement discussed above was the agreement for implementation of an IMR in North Carolina allowing an annual true up and recovery on and of our capital investments related to federal pipeline integrity compliance. With the IMR mechanism, we will avoid having to file costly and more frequent future general rate proceedings, consuming both our resources and the resources of the NCUC and its staff. As also discussed above, we have a similar IMR that was approved in Tennessee.

In June 2013, legislation was passed in North Carolina that increased criminal penalties and fines for interference with natural gas, water and electric lines in the state. This law will help us and all utility providers protect the integrity and safety of their system infrastructures as well as protect the general public.

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. In November 2012, we became a 24% equity member of Constitution Pipeline Company, LLC (Constitution). To date, this is our largest investment in a natural gas infrastructure venture for the development and construction of a new pipeline that will transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. With an estimated total cost of $680 million, we expect our total 24% equity contributions will be an estimated $163 million through 2015. We contributed $15.9 million during our first year of ownership in 2013.

 

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We also made additional investments in our existing ventures during the year. In July 2013, we purchased an incremental 5% equity ownership stake in Pine Needle LNG Company, L.L.C. (Pine Needle) from Hess Corporation (Hess) for $2.9 million, increasing our overall ownership percentage to 45%. In September 2013, we contributed $22.5 million to SouthStar Energy Services LLC (SouthStar), maintaining our 15% equity ownership, with our partner contributing retail natural gas marketing assets and related customers located in Illinois. We expect this investment to be accretive to our 2014 earnings.

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 believe 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 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, and

   

Enhance our healthy, high performance culture

We believe that by focusing on these priorities, we will enhance long-term shareholder value. For a full discussion of our strategy and focus areas, see Item 1. Business.

Additional information on operating results for the years ended October 31, 2013, 2012 and 2011 follows.

 

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Results of Operations

Operating Revenues

Changes in operating revenues for 2013 and 2012 compared with the same prior periods are presented below.

 

Changes in Operating Revenues - Increase (Decrease)   
      2013 vs.      2012 vs.  

In millions

   2012      2011  

Residential and commercial customers

   $         136.2       $         (275.4)   

Industrial customers

     18.0         (9.8)   

Power generation customers

     28.1         7.1   

Secondary market

     23.8         (104.4)   

Margin decoupling mechanism

     (40.8)         53.7  

WNA mechanisms

     (10.4)         18.2  

Other

     .5         (.5)   
  

 

 

    

 

 

 

Total

   $ 155.4       $         (311.1)   
  

 

 

    

 

 

 

2013 compared to 2012:

 

  Residential and commercial customers – the increase is primarily due to higher consumption from colder weather, customer growth and higher wholesale gas costs passed through to customers.

 

  Industrial customers – the increase is primarily due to colder weather and customer growth.

 

  Power generation customers – the increase is primarily due to increased transportation services due to new contracts that began in June 2012 and June 2013.

 

  Secondary market – the increase is primarily due to higher commodity gas costs, partially offset by decreased activity. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulatory-approved margin sharing mechanisms between our utility customers and our shareholders.

 

  Margin decoupling mechanism – the decrease is due to colder 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.

 

  Weather normalization adjustment (WNA) mechanisms – the decrease is due to colder weather in South Carolina and Tennessee. As discussed in “Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.

2012 compared to 2011:

 

  Residential and commercial customers – the decrease is primarily due to lower consumption from warmer weather and lower wholesale gas costs passed through in rates.

 

  Industrial customers – the decrease is primarily due to lower consumption and lower wholesale gas costs passed through to sales customers.

 

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

 

  Secondary market – the decrease is due to lower secondary market margins in the wholesale market.

 

  Margin decoupling mechanism – the increase is due to warmer weather in North Carolina.

 

  WNA mechanisms – the increase is due to warmer weather in South Carolina and Tennessee.

Cost of Gas

Changes in cost of gas for 2013 and 2012 compared with the same prior periods are presented below.

 

Changes in Cost of Gas - Increase (Decrease)   

In millions

   2013 vs.
2012
     2012 vs.
2011
 

Commodity gas costs passed through to sales customers

   $         96.8       $         (194.3)   

Commodity gas costs in secondary market transactions

     24.5         (100.1)   

Pipeline demand charges

     22.3         (7.0)   

Regulatory approved gas cost mechanisms

     (34.2)         (11.5)   
  

 

 

    

 

 

 

Total

   $ 109.4       $ (312.9)   
  

 

 

    

 

 

 

2013 compared to 2012:

 

  Commodity gas costs passed through to sales customers – the increase is primarily due to higher volumes sold due to colder weather and slightly higher wholesale gas costs passed through to sales customers.

 

  Commodity gas costs in secondary market transactions – the increase is primarily due to increased average wholesale gas costs, partially offset by decreased activity.

 

  Pipeline demand charges – the increase is primarily due to increased demand costs, decreased asset manager payments and decreased capacity release revenues.

 

  Regulatory approved gas cost mechanisms – the decrease is primarily due to commodity gas cost true-ups.

2012 compared to 2011:

 

  Commodity gas costs passed through to sales customers – the decrease is due to lower volumes sold due to warmer weather and lower wholesale gas costs passed through to sales customers.

 

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  Commodity gas costs in secondary market transactions – the decrease is due to lower average wholesale gas costs.

 

  Pipeline demand charges – the decrease is primarily due to changing asset manager agreement terms.

 

  Regulatory approved gas cost mechanisms – the decrease is due to the effects of various regulatory true-up mechanisms.

In all three states, we are authorized to recover from customers all prudently incurred gas costs. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account and are added to or deducted from cost of gas and are in current “Regulatory assets” or current “Regulatory liabilities” in the Consolidated Balance Sheets. For the amounts included in “Amounts due from customers” or “Amounts due to customers,” see “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial statements in this Form 10-K.

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory passthrough 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 41% of revenues for the year ended October 31, 2013, and our pipeline transportation and storage costs accounted for 12%.

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

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These include WNA 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.

 

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Changes in margin for 2013 and 2012 compared with the same prior periods are presented below.

 

Changes in Margin - Increase (Decrease)   
     2013 vs.      2012 vs.  

In millions

   2012      2011  

Residential and commercial customers

   $ 15.6       $ 1.0   

Industrial customers

     5.3         (1.3)   

Power generation customers

     24.0         8.3   

Secondary market activity

     (.7)         (4.3)   

Net gas cost adjustments

     1.8         (1.9)   
  

 

 

    

 

 

 

  Total

   $         46.0       $           1.8   
  

 

 

    

 

 

 

2013 compared to 2012:

 

  Residential and commercial customers – the increase is primarily due to increased volumes delivered due to colder weather, customer growth in all three states and the general rate increase in Tennessee, effective March 1, 2012.

 

  Industrial customers – the increase is primarily due to higher consumption in the industrial market from colder weather and customer growth.

 

  Power generation customers – the increase is primarily due to increased transportation services due to new contracts placed in service in June 2012 and June 2013.

 

  Secondary market activity – the decrease is primarily due to lower commodity gas price volatility and decreased activity.

2012 compared to 2011:

 

  Residential and commercial customers – the increase is primarily due to the general rate increase in Tennessee effective March 1, 2012 and customer growth in all three states, offset by lower consumption in Tennessee and South Carolina where the WNA mechanisms did not perfectly adjust for significantly warmer-than-normal weather.

 

  Industrial customers – the decrease is primarily due to lower consumption in the industrial market from warmer 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.

 

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Operations and Maintenance Expenses

Changes in O&M expenses for 2013 and 2012 compared with the same prior periods are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)

 

In millions

         2013 vs.      
2012
           2012 vs.      
2011
 

Contract labor

   $ 2.4        $ 3.7    

Payroll

     1.8          4.0    

Bad debt

     1.4          (1.2)    

Regulatory

     1.0          1.3    

Employee benefits

     (1.1)          7.1    

Other

     5.0          2.3    
  

 

 

    

 

 

 

  Total

   $ 10.5        $ 17.2    
  

 

 

    

 

 

 

2013 compared to 2012:

 

  Contract labor – the increase is primarily due to increased process improvement projects and pipeline integrity, maintenance and safety programs.

 

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

 

  Bad debt – the increase is primarily due to a higher level of projected charge-offs due to higher bills.

 

  Regulatory – the increase is primarily due to amortization of regulatory assets with new amortization amounts established in the Tennessee general rate proceeding effective in March 2012.

 

  Employee benefits – the decrease is primarily due to reduced group medical insurance expense from lower claims and a regulatory pension deferral in Tennessee in the current year related to the funding of the defined benefit plan in November 2012 compared to no plan funding in the prior year, partially offset by an increase in pension expense.

2012 compared to 2011:

 

  Contract labor – the increase is primarily due to increased process improvement projects and pipeline integrity, maintenance and safety programs.

 

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

 

  Regulatory – the increase is primarily due to amortization of regulatory assets that began with the Tennessee general rate increase.

 

  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 2012.

 

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Depreciation

Depreciation expense increased from $102.8 million to $112.2 million over the three-year period 2011 to 2013 primarily due to increases in plant in service, particularly related to major additions to serve new power generation customers, system integrity and upgrades to our liquefied natural gas facilities.

General Taxes

Changes in general taxes for 2013 compared with the same prior period are insignificant. Changes in general taxes for 2012 compared with the same prior period are presented below.

Changes in General Taxes Expense - Increase (Decrease)

 

In millions

         2012 vs.      
2011
 

Sales tax accrual

     $ (2.5)    

Gross receipts tax

     (.8)    

Property taxes

     .4    

Other

     (.6)    
  

 

 

 

Total

     $   (3.5)    
  

 

 

 

2012 compared to 2011:

 

  Sales tax accrual – the decrease is primarily due to the accrual of a liability of $2.7 million in 2011 for sales 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.

Other Income (Expense)

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

2013 compared with 2012:

Other Income (Expense) increased $.9 million in 2013 compared with 2012. The primary changes were an increase in income from equity method investments and an increase in non-operating expenses. All other changes for the year ended October 31, 2013 compared with 2012 were insignificant.

Income from equity method investments from SouthStar increased $1.3 million in 2013 primarily due to higher average customer usage from colder weather compared to the prior year, net of weather derivatives, the recording of a lower cost or market inventory adjustment in the

 

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prior year and new margin from the Illinois business that was contributed to the venture with our sharing beginning in September 2013, partially offset by higher gas costs, increased operating expenses and lower retail price spreads. Beginning November 1, 2012 with our initial investment in Constitution, we recorded earnings of $1 million due to the allowance for funds used during construction (AFUDC), partially offset by operating expenses. For further information on the contribution of the Illinois business made to SouthStar and our cash contribution in our equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

Non-operating expense increased $3.3 million in 2013 compared with 2012 primarily due to $1.8 million of cumulative amortization of non-land costs related to the allowed deferral of a regulatory asset for certain non-real estate costs, construction of which was suspended in March 2009, as included in the 2013 settlement agreement with the NCUC Public Staff. We had a balance of $6.7 million of capital costs held in “Plant held for future use” comprised of $3.2 million in land costs and $3.5 million in non-land development costs. Under the NCUC approved settlement of the 2013 North Carolina general rate proceeding, we agreed to the amortization and collection of $1.2 million of the non-real estate costs to be amortized over 38 months beginning January 1, 2014, which we recorded as a regulatory asset along with a portion of the costs that we allocated to South Carolina operations. In addition, charitable contributions increased $.8 million primarily due to the funding of our charitable foundation.

2012 compared with 2011:

The primary change to Other Income (Expense) in 2012 compared with 2011 was income from equity method investments, primarily from SouthStar 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 AFUDC and increased revenues as a result of the expansion project to serve a subsidiary of Duke Energy Corporation, (DEC), the Duke Energy Progress, Inc. (DEP) Wayne County generation project, partially offset by higher depreciation and operating expenses.

 

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Utility Interest Charges

Changes in utility interest charges for 2013 and 2012 compared with the same prior periods are presented below.

Changes in Utility Interest Charges - Increase (Decrease)

 

In millions

         2013 vs.      
2012
           2012 vs.      
2011
 

Interest expense on long-term debt

   $ 12.7       $ (4.6)   

Borrowed AFUDC

     (5.8)         (16.6)   

Interest expense on short-term debt

     (1.5)         .8   

Regulatory interest expense, net

     .1         (3.8)   

Other

     (.7)         .3   
  

 

 

    

 

 

 

  Total

   $ 4.8       $ (23.9)   
  

 

 

    

 

 

 

2013 compared to 2012:

 

  Interest expense on long-term debt – the increase is primarily due to the issuance of debt in 2013 and a full year of interest expense on the debt issued in 2012.

 

  Borrowed AFUDC – the decrease is due to an increase in capitalized interest primarily resulting from increased construction expenditures.

 

  Interest expense on short-term debt – the decrease is primarily due to lower balances outstanding during the current period at interest rates that are 34 basis points lower than the prior year period. We paid down short-term debt as we issued long-term debt and equity securities during our fiscal year.

2012 compared to 2011:

 

  Interest expense on long-term debt – the decrease is primarily due to the replacement of higher rate debt with lower rate debt.

 

  Borrowed AFUDC – the decrease is due to an increase in capitalized interest primarily as a result of increased project construction expenditures.

 

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

 

  Regulatory interest expense, net – the decrease is primarily due to an increase in interest charged on amounts due from customers, which is recorded as interest income.

Financial Condition and Liquidity

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

 

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is subject to regulation by the NCUC. For information on the issuance of long-term debt and equity securities, see Note 4 and Note 6, respectively to the consolidated financial statements in this Form 10-K.

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

Short-term debt is vital to meet the timing of 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 investments in customer growth, pipeline integrity programs, system infrastructure and contributions to our joint ventures.

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

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by the extension of bonus depreciation legislation. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities.”

Short-Term Debt. We have a $650 million five-year revolving syndicated credit facility that expires in October 2017 and has an option to request an expansion of up to $850 million. On November 1, 2013, we entered into an agreement with the lenders under the facility which increased our borrowing capacity to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The five-year revolving syndicated credit facility contains normal and customary financial covenants.

At October 31, 2013, we have a $650 million unsecured CP program that is backstopped by the revolving syndicated credit facility. Effective in November 2013, we exercised the expansion option under the revolving syndicated credit facility. With the exercise of the option, the amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.

 

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Highlights for our short-term debt as of October 31, 2013 and 2012 and for the quarter and year ended October 31, 2013 and 2012 are presented below.

 

In thousands

   Credit
         Facility        
          Commercial      
Paper
    Total
    Borrowings     
 

2013

      

End of period (October 31, 2013):

      

Amount outstanding

       $ -          $ 400,000         $ 400,000  

Weighted average interest rate

     -     .36     .36

During the period (August 1, 2013 - October 31, 2013):

      

Average amount outstanding

       $ -          $ 319,700         $ 319,700  

Minimum amount outstanding

       $ -          $ 220,000         $ 220,000  

Maximum amount outstanding

       $ -          $ 475,000         $ 475,000  

Minimum interest rate

     -     .23     .23

Maximum interest rate

     -     .43     .43

Weighted average interest rate

     -     .28     .28

Maximum amount outstanding during the month:

      

August 2013

       $ -          $ 475,000         $ 475,000  

September 2013

     -        335,000       335,000  

October 2013

     -        430,000       430,000  

During the year ended October 31, 2013:

      

Average amount outstanding

       $ -          $ 397,800         $ 397,800  

Minimum amount outstanding (1)

       $ -          $ 220,000         $ 220,000  

Maximum amount outstanding (1)

       $ 10,000         $     555,000         $     555,000  

Minimum interest rate (2)

     1.12     .23     .23

Maximum interest rate

     1.12     .45     1.12

Weighted average interest rate

     1.12     .32     .32

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

(1) During December 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.

  

  

 

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As of October 31, 2013, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $2.1 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, 2013, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $247.9 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 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 monthly bills. 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 increase 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 in amounts due to or from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

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

Net cash provided by operating activities was $313.2 million in 2013, $304.5 million in 2012 and $311.2 million in 2011. Net cash provided by operating activities reflects a $14.6 million increase in net income for 2013 compared with 2012 primarily due to increased margin, partially offset by higher operating costs and utility interest charges in 2013. The effect of changes in working capital on net cash provided by operating activities is described below:

 

 

Trade accounts receivable and unbilled utility revenues increased $23.5 million in the current period primarily due to colder weather and higher consumption of natural gas.

 

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  Volumes sold to weather-sensitive residential and commercial customers increased 17.3 million dekatherms as compared with the same prior period primarily due to 25% colder weather during the current period. Total throughput increased 63.3 million dekatherms as compared with the same prior period, largely from 39.2 million dekatherms, or 26%, increased deliveries to power generation customers, as well as increased sales to residential and commercial customers.
  Net amounts due from customers decreased $15.3 million in the current period primarily due to margin decoupling and deferred gas cost collections through rates.
  Gas in storage increased $1.3 million in the current period primarily due to an increase in the weighted average cost of gas purchased for injections slightly offset by decreased volumes of gas in storage from higher customer sales in 2013 due to colder weather.
  Prepaid gas costs increased $4.7 million in the current period primarily due to an increase in the weighted average cost of gas purchased for 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.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee, which includes the additional months of April and October in 2013 and 2012 for Tennessee, generated charges to customers of $3 million and $13.3 million in 2013 and 2012, respectively, and credits of $4.9 million in 2011. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” in Note 1 to the consolidated 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 consumption patterns. The margin decoupling mechanism increased margin by $6 million and $46.8 million in 2013 and 2012, respectively, and reduced margin by $7 million in 2011. Our gas costs are recoverable through purchased gas adjustment (PGA) procedures and are not affected by the WNA or the margin decoupling mechanisms.

The American Taxpayer Relief Act of 2012, enacted in January 2013, and The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010 (the Acts), 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 – 2015. Based on current capital projections and timelines, we anticipate that bonus depreciation will reduce cash needed to pay federal income taxes during fiscal years 2010 – 2015 by $165 – $180 million as compared with cash tax needs prior to the Acts. 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 increased for 2013, but less than if bonus depreciation had not been in effect.

 

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Primarily due to bonus depreciation, we generated a federal net operating loss (NOL) in our tax years 2012 and 2013. We will file 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 the refundable income taxes that we anticipate will be generated from the carryback of these NOLs. Any NOLs that are not carried back will be carried forward to offset future taxable income. From the carryforward of 2013 NOLs, we anticipate we will completely offset 2014 taxable income and will generate taxable income sufficient to utilize all NOLs prior to the expiration of the loss carryforward periods.

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 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. 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 relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the U.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of 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 O&M cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system.

Cash Flows from Investing Activities. Net cash used in investing activities was $663.5 million in 2013, $549.3 million in 2012 and $252.6 million in 2011. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures were $600 million in 2013 as compared to $529.6 million in 2012 primarily due to increased expenditures for system integrity projects, partially offset by decreased expenditures for the construction of power generation service delivery projects. Gross utility capital expenditures were $529.6 million in 2012 as compared to $243.6 million in 2011 primarily due to expending $284.3 million and $103.6 million, respectively, for the construction of power generation service delivery projects.

 

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

Detail of our forecasted 2014 – 2016 capital expenditures, including AFUDC, is presented below. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 45 – 50% in long-term debt and 50 – 55% 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.

 

In millions

  

2014

    

2015

    

2016

 

Customer growth and other

   $           200      $           190      $           190  

System integrity

     250        225        215  
  

 

 

    

 

 

    

 

 

 

Total forecasted utility capital expenditures

   $ 450      $ 415      $ 405  
  

 

 

    

 

 

    

 

 

 

Our estimates for utility capital expenditures in 2014, particularly those associated with system integrity, have increased compared to previous estimates in prior years. These increases are primarily due to costs associated with the development and enhancement of programs and processes designed to mitigate risk on our system to comply with federally mandated pipeline safety and integrity requirements. Such programs include retrofitting transmission lines to facilitate internal inspections, transmission line replacements, corrosion control, casing remediation and distribution integrity management. The increased expenditures in 2014 also include costs associated with the completion of a major transmission line replacement in Nashville, the construction of which began in 2013.

In October 2009, we reached an agreement with DEP, 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 requiring us to construct 38 miles of transmission pipeline along with additional compression facilities. Service began in June 2012 and is supported by a long-term service agreement with fixed monthly payments. We also executed an agreement with Cardinal to expand our firm capacity requirement on Cardinal to serve the DEP Wayne County site requiring Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system, which began service in June 2012. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million from January 2011 through June 2012 related to this system expansion. In June 2012, due to Cardinal obtaining permanent financing of 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 this Form 10-K.

 

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In April 2010, we reached another agreement with DEP 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 called for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant, which was placed into service as scheduled on June 1, 2013. Our investment in the pipeline and compression facilities is supported by a long-term service agreement with fixed monthly payments.

The Sutton facilities created cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. The approval of our 2013 NCUC rate settlement provided for a portion of the revenue requirement of this project to be recovered through tariff rates to customers in North Carolina.

During fiscal 2011, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a DEP power generation facility located in Richmond County, North Carolina. During fiscal 2011, we also placed into service natural gas pipeline facilities to provide natural gas delivery service to a DEC power generation facility located in Rowan County, North Carolina. In December 2011, we placed into service natural gas pipeline facilities to provide natural gas delivery service to a DEC power generation facility located in Rockingham County, North Carolina. Our investments in the pipeline facilities are supported by long-term service agreements with fixed monthly payments.

In July 2013, we acquired an incremental 5% membership interest in Pine Needle from Hess for $2.9 million, which increased our membership interest from 40% to 45%. For further information regarding this transaction, see Note 12 to the consolidated financial statements in this Form 10-K.

In September 2013, we made an additional $22.5 million capital contribution to our existing SouthStar investment associated with our partner contributing retail natural gas marketing assets and related customer accounts located in Illinois. For further information regarding this transaction, see Note 12 to the consolidated financial statements in this Form 10-K.

In November 2012, we became a 24% equity member of Constitution, a Delaware limited liability company. The purpose of the joint venture is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to 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 $680 million. Our contributions through October 31, 2013 were $15.9 million, and we expect our total contributions will be an estimated $55 million and $92.1 million in our fiscal 2014 and 2015 years, respectively. The target in service date of the project is March 2015. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-K.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $356.3 million in 2013, $240 million in 2012 and ($57.5) million in 2011. Funds are primarily provided from long-term debt securities, short-term borrowings and the issuance of common stock

 

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through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments. We may sell common stock and long-term debt when market and other conditions favor such long-term financing to maintain our target long-term capital structure of 50 – 55% 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, pay quarterly dividends on our common stock and general corporate purposes.

Outstanding debt under our revolving syndicated credit facility and CP program increased from $365 million as of October 31, 2012 to $400 million as of October 31, 2013 primarily due to increased utility capital expenditures and investments in our equity method investments, partially offset by the net proceeds received from the issuance of our common stock and long-term debt. Our five-year revolving syndicated credit facility had an option to request an expansion of up to $850 million. In November 2013, we entered into an agreement with the lenders under the facility which increased our borrowing capacity to $850 million. Our unsecured CP program, which is backstopped by our credit facility, was established in March 2012. For further information on short-term debt, see the previous discussion of “Short-Term Debt” 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 open combined debt and equity shelf registration statement filed with the SEC in July 2011 that is available for future use until its expiration on July 6, 2014. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used 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. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities. We plan to issue new long-term debt and equity capital over fiscal years 2014 and 2015, at such amounts to support our capital investment program and maintain our target capital structure of 45 – 50% in long-term debt and 50 – 55% in common equity.

On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock. The offering for 3 million shares was settled on February 4, 2013, and we received net proceeds of $92.6 million from the underwriters at the net price of $30.88, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.

We have two FSAs totaling 1.6 million shares that must be settled no later than mid December 2013. Under the terms of the FSAs, at our election, we may physically settle in shares, cash or net share settle for all or a portion of our obligations under the agreements. On December 16, 2013, we physically settled by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments.

We used the net proceeds from the January 2013 sale of our common stock to finance capital expenditures, repay outstanding unsecured notes under the CP program and for general corporate purposes. We used the proceeds from the FSAs to finance capital expenditures, repay outstanding unsecured notes under our CP program and for general corporate purposes. For further information on our common stock and for more details on these equity issuance transactions, see Note 6 to the consolidated financial statements in this Form 10-K.

 

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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 August 2013, we issued unsecured senior notes in the amount of $300 million with an interest rate of 4.65% under our open debt and equity shelf registration statement. These notes will mature on August 1, 2043. The net proceeds of $297.2 million were used to finance capital expenditures, to repay the balance of $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. For further information on our long-term debt instruments, see Note 4 to the consolidated financial statements in this Form 10-K.

In March 2012, we entered into an agreement to issue $300 million of notes 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.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Note 6 to the consolidated financial statements in this Form 10-K. During 2013, we did not repurchase any of our common stock. Under our Common Stock Open Market Purchase Program during 2012 and 2011, we repurchased and retired .8 million shares in each year for $26.5 million and $23 million, respectively. We do not anticipate repurchasing our common stock in our fiscal year 2014.

During 2013, we issued $24.6 million of common stock through DRIP and ESPP. During 2012 and 2011, we issued $22.1 million and $20.2 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 2013, 2012 and 2011. Dividends of $92.1 million, $85.7 million and $82.9 million for 2013, 2012 and 2011, 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, 2013, our retained earnings were not restricted. On December 12, 2013, the Board of Directors declared a quarterly dividend on common stock of $.31 per share, payable January 15, 2014 to shareholders of record at the close of business on December 24, 2013. For further information, see Note 4 to the consolidated financial statements in this Form 10-K.

Our long-term debt targeted capitalization ratio is 45 – 50% in long-term debt and 50 – 55% in common equity. As of October 31, 2013, our capitalization, excluding current maturities of long-term debt, if any, consisted of 50% in long-term debt and 50% in common equity.

 

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The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2013 and 2012 are summarized in the table below.

 

     October 31      October 31  

 

  

 

 

    

 

 

    

 

 

    

 

 

 

In thousands

   2013      Percentage      2012      Percentage  

Short-term debt

     $ 400,000        14 %         $ 365,000        16 %   

Current portion of long-term debt

     100,000        3 %         -        - %   

Long-term debt

     1,174,857        41 %         975,000        41 %   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total debt

     1,674,857        58 %         1,340,000        57 %   

Common stockholders’ equity

     1,188,596        42 %         1,027,004        43 %   

 

  

 

 

    

 

 

    

 

 

    

 

 

 

Total capitalization (including short-term debt)

     $   2,863,453        100 %         $   2,367,004        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 credit facility and our CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds.

The lenders under our revolving credit facility and our CP program are major financial institutions, all of which have investment grade credit ratings as of October 31, 2013. 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, 2013, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A3” by Moody’s Investors Service (Moody’s). Currently, with respect to 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. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, capital structure, a change from the conservative regulatory environments in which we operate or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our 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, 2013, 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

 

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  Failure to observe or perform covenants, including:

 

  Interest coverage of at least 1.75 times. Interest coverage was 4.6 times as of October 31, 2013;
  Funded debt cannot exceed 70% of total capitalization. Funded debt was 59% of total capitalization as of October 31, 2013;
  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, 2013;
  Restrictions on permitted liens;
  Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
  Restrictions on burdensome agreements.

 

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Contractual Obligations and Commitments

We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2013, 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)

     $ 100,000         $ 75,000         $         $ 1,100,000         $ 1,275,000   

Short-term debt (2)

     400,000                                 400,000   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total recorded contractual obligations

     500,000         75,000                 1,100,000         1,675,000   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
Unrecorded contractual obligations and commitments: (3)               

Pipeline and storage capacity (4)

     170,430         453,445         276,550         647,982         1,548,407   

Gas supply (5)

     6,356                                 6,356   

Interest on long-term debt (6)

     62,191         178,387         111,311         648,294         1,000,183   

Capital contributions to joint ventures (7)

     55,000         92,052                         147,052   

Telecommunications and information technology (8)

     11,045         5,436                         16,481   

Qualified and nonqualified pension plan funding (9)

     21,330         35,097         12,028                 68,455   

Postretirement benefits plan funding (9)

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

Operating leases (10)

     4,543         13,380         8,362         27,359         53,644   

Other purchase obligations (11)

     24,951                                 24,951   

Letters of credit (12)

     2,078                                 2,078   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total unrecorded contractual obligations and commitments

     359,424         781,797         409,551         1,323,635         2,874,407   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations and commitments

     $       859,424         $       856,797         $       409,551         $   2,423,635         $   4,549,407   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) See Note 4 to the consolidated financial statements in this Form 10-K.
(2) See Note 5 to the consolidated financial 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 recoverable through PGA procedures.
(6) See Note 4 to the consolidated financial statements in this Form 10-K.
(7) See Note 12 to the consolidated financial statements in this Form 10-K.
(8) 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.
(9) Estimated funding beyond five years is not available. See Note 9 to the consolidated financial statements in this Form 10-K.
(10) See Note 8 to the consolidated financial statements in this Form 10-K. Operating lease payments do not include payment for common area maintenance, utilities or tax payments.
(11) Consists primarily of pipeline products, vehicles, contractors and merchandise.
(12) See Note 5 to the consolidated financial statements in this Form 10-K.

 

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Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of credit and operating leases are discussed in Note 5 and Note 8, respectively, to the consolidated financial statements in this Form 10-K and are reflected in the table above.

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 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 lower by $9 million and by $60.1 million in 2013 and 2012, respectively, and higher by $11.9 million in 2011.

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

 

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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 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 the income statement 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. 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, 2013 and 2012 totaled $246.3 million and $293.1 million, respectively. Regulatory liabilities as of October 31, 2013 and 2012 totaled $541.9 million and $489.7 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial 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 9 to the consolidated financial statements in this Form 10-K. 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 addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may

 

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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 non-callable bonds rated AA or better by either Moody’s or S&P that have a yield higher than the regression mean yield curve. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plan changed from 3.51% in 2012 to 4.55% in 2013. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 2.95% in 2012 to 3.98% in 2013. Similarly, the weighted average discount rate for postretirement benefits changed from 3.34% in 2012 to 4.44% in 2013. The higher discount rates discussed above reflect the higher yields found in the AA corporate bond market where the bond price has decreased together with the use of an above-mean yield curve. 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 7.5% in 2013 declining gradually to 5% by 2027.

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% equity securities and 50% 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 2011, 2012 and 2013. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.78% in 2011, decreasing to 3.76% in 2012 and 2013 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 2013, we recorded costs of $11.3 million related to our qualified pension plan and postretirement benefits plan. We estimate 2014 expenses for these two plans to be in the range of $6 to $7 million representing a decrease of $4.3 to $5.3 million from 2013. These estimates reflect the discount rates and assumed rate of return on the plan assets discussed above for each plan.

 

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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.

 

Actuarial Assumption

   Change in
Assumption
    Impact on 2013
Benefit Cost
     Impact on Projected
Benefit Obligation
 
          

Increase (Decrease)

In thousands

 

Discount rate

     (.25 )%    $ 629            $ 6,544        

Rate of return on plan assets

     (.25 )%      660              N/A         

Rate of increase in compensation

     .25      719               3,762        

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 2013      Impact on Accumulated  
     Change in     Postretirement      Postretirement Benefit  
Actuarial Assumption    Assumption     Benefit Cost      Obligation  
           Increase (Decrease)  
          

In thousands

 

Discount rate

     (.25 )%    $ -            $ 840        

Rate of return on plan assets

     (.25 )%      57              N/A         

Health care cost trend rate

     .25      3              171        

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.

Gas Supply and Regulatory Proceedings

The source of our gas supply that we distribute to our customers is contracted from a diverse portfolio of major and independent producers and marketers and interstate and intrastate pipeline and storage operators. In November 2012, we continued to diversify our supply portfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply arrangements are scheduled to begin in late 2015, and we believe they 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 located in North Carolina 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. For further information on our equity venture with Cardinal that expanded our firm capacity requirement in 2012 in order to serve a power generation facility in Wayne County, North Carolina, see Note 12 to the consolidated financial statements in this Form 10-K.

 

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Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity when market conditions permit and the capacity and supply are not required to serve our retail distribution system. For further information on secondary market transactions, see Note 2 to the consolidated financial 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 2 to the consolidated financial statements in this Form 10-K.

Equity Method Investments

For information about our equity method investments, see Note 12 to the consolidated financial 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 MGP 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 8 to the consolidated financial statements in this Form 10-K.

Accounting Guidance

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

Financial Accounting Standards Board and International Accounting Standards Board

With a goal to improve the U.S. financial accounting standards for the benefit of investors and other users of financial statements, the Financial Accounting Standards Board (FASB) has pursued convergence of select accounting standards with the International Accounting Standards Board (IASB) for the past ten years. The path toward convergence has been a collaborative effort by the FASB and the IASB to improve both U.S. GAAP and International Financial Reporting Standards and to eliminate or minimize the differences between them.

Over the next year and a half, the FASB plans to complete the open major convergence projects. By the first quarter of 2014, the final standard on revenue recognition should be released. In the first half of 2014, the FASB intends to issue final standards on the two financial instruments projects of classification and measurement as well as impairment. A final standard on leasing may be completed in 2014 followed by an insurance standard.

 

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

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, 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, 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 all three states, gas costs related to uncollectible accounts are recovered through PGA procedures. 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 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, 2013, 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.

 

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As of October 31, 2013, we had $400 million of short-term debt outstanding as commercial paper at an interest rate of .36%. 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 million during 2013.

As of October 31, 2013, information about our long-term debt is presented below.

 

                                               Fair Value as  
     Expected Maturity Date           of October 31,  
In millions      2014         2015         2016         2017         2018         Thereafter         Total         2013    

Fixed Rate Long-term Debt

   $         100     $         -      $ 40     $ 35     $         -      $         1,100     $         1,275     $         1,409.9  

Average Interest Rate

     5     -             2.92             8.51     -     5.06     5.08  

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. 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 “Regulatory Assets” or any over-recoveries are included in “Amounts due to customers” in “Regulatory Liabilities” as presented in Note 1 to the consolidated 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 most 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.

 

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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 South Carolina and October through 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 WNA 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.

 

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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, 2013 and 2012, 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, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2013, 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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 23, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, 2013

 

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Consolidated Balance Sheets

October 31, 2013 and 2012

ASSETS

 

In thousands    2013      2012  

Utility Plant:

     

  Utility plant in service

   $ 4,421,937       $ 3,746,178   

    Less accumulated depreciation

     1,088,331         1,036,814   
  

 

 

    

 

 

 

      Utility plant in service, net

     3,333,606         2,709,364   

  Construction work in progress

     297,717         388,979   

  Plant held for future use

     3,155         6,743   
  

 

 

    

 

 

 

      Total utility plant, net

         3,634,478             3,105,086   
  

 

 

    

 

 

 
Other Physical Property, at cost (net of accumulated
  depreciation of $876 in 2013 and $843 in 2012)
     382         415   
  

 

 

    

 

 

 

Current Assets:

     
  Cash and cash equivalents      8,063         1,959   

  Trade accounts receivable (less allowance for doubtful

    accounts of $1,604 in 2013 and $1,579 in 2012)

     79,210         56,700   
  Income taxes receivable      31,065         31,606   
  Other receivables      1,988         2,104   
  Unbilled utility revenues      24,967         24,012   
  Inventories:      
    Gas in storage      73,929         72,661   
    Materials, supplies and merchandise      1,725         934   
  Gas purchase derivative assets, at fair value      1,834         3,153   
  Regulatory assets      77,204         81,626   
  Prepayments      35,038         30,600   
  Deferred income taxes      12,695          
  Other current assets      338         287   
  

 

 

    

 

 

 

    Total current assets

     348,056         305,642   
  

 

 

    

 

 

 

Noncurrent Assets:

     

  Equity method investments in non-utility activities

     128,469         87,867   

  Goodwill

     48,852         48,852   

  Regulatory assets

     169,102         211,478   

  Marketable securities, at fair value

     2,995         2,131   

  Overfunded postretirement asset

     28,258          

  Other noncurrent assets

     8,017         8,468   
  

 

 

    

 

 

 

      Total noncurrent assets

     385,693         358,796   
  

 

 

    

 

 

 

      Total

   $ 4,368,609       $ 3,769,939   
  

 

 

    

 

 

 

See notes to consolidated financial statements.

 

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Consolidated Balance Sheets

October 31, 2013 and 2012

CAPITALIZATION AND LIABILITIES

 

In thousands    2013      2012  

Capitalization:

     
  Stockholders’ equity:      
    Cumulative preferred stock - no par value - 175 shares authorized    $      $  
    Common stock - no par value - shares authorized: 200,000;
      shares outstanding: 76,099 in 2013 and 72,250 in 2012
     561,644         442,461   
    Retained earnings      627,236         584,848   
    Accumulated other comprehensive loss      (284)         (305)   
  

 

 

    

 

 

 
      Total stockholders’ equity      1,188,596         1,027,004   
  Long-term debt      1,174,857         975,000   
  

 

 

    

 

 

 
      Total capitalization      2,363,453         2,002,004   
  

 

 

    

 

 

 
Current Liabilities:      
  Current maturities of long-term debt      100,000          
  Short-term debt      400,000         365,000   
  Trade accounts payable      96,281         94,269   
  Other accounts payable      43,855         47,699   
  Accrued interest      28,205         21,450   
  Customers’ deposits      19,831         21,739   
  Current deferred taxes             13,542   
  General taxes accrued      21,454         21,504   
  Regulatory liabilities             28   
  Other current liabilities      7,024         7,320   
  

 

 

    

 

 

 
      Total current liabilities      716,650         592,551   
  

 

 

    

 

 

 
Noncurrent Liabilities:      
  Deferred income taxes      681,369         597,211   
  Unamortized federal investment tax credits      1,402         1,669   
  Accumulated provision for postretirement benefits      12,042         37,299   
  Regulatory liabilities      541,897         489,664   
  Conditional cost of removal obligations      27,016         28,629   
  Other noncurrent liabilities      24,780         20,912   
  

 

 

    

 

 

 
      Total noncurrent liabilities      1,288,506         1,175,384   
  

 

 

    

 

 

 
Commitments and Contingencies (Note 8)      
     
  

 

 

    

 

 

 
      Total    $     4,368,609       $     3,769,939   
  

 

 

    

 

 

 

See notes to consolidated financial statements.

 

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Consolidated Statements of Comprehensive Income

For the Years Ended October 31, 2013, 2012 and 2011

 

      2013      2012      2011  
In thousands except per share amounts                     
Operating Revenues    $     1,278,229       $     1,122,780       $     1,433,905   
Cost of Gas      656,739         547,334         860,266   
  

 

 

    

 

 

    

 

 

 
Margin      621,490         575,446         573,639   
  

 

 

    

 

 

    

 

 

 
Operating Expenses:         
  Operations and maintenance      253,120         242,599         225,351   
  Depreciation      112,207         103,192         102,829   
  General taxes      34,635         34,831         38,380   
  Utility income taxes      77,334         69,101         64,068   
  

 

 

    

 

 

    

 

 

 
    Total operating expenses      477,296         449,723         430,628   
  

 

 

    

 

 

    

 

 

 
Operating Income      144,194         125,723         143,011   
  

 

 

    

 

 

    

 

 

 
Other Income (Expense):         
  Income from equity method investments      26,056         23,904         24,027   
  Non-operating income      2,839         1,288         1,762   
  Non-operating expense      (5,122)         (1,855)         (3,022)   
  Income taxes      (8,612)         (9,116)         (8,218)   
  

 

 

    

 

 

    

 

 

 
    Total other income (expense)      15,161         14,221         14,549   
  

 

 

    

 

 

    

 

 

 
Utility Interest Charges:         
  Interest on long-term debt      54,158         41,412         46,070   
  Allowance for borrowed funds used during construction      (30,975)         (25,211)         (8,619)   
  Other      1,755         3,896         6,541   
  

 

 

    

 

 

    

 

 

 
    Total utility interest charges      24,938         20,097         43,992   
  

 

 

    

 

 

    

 

 

 
Net Income      134,417         119,847         113,568   
  

 

 

    

 

 

    

 

 

 
Other Comprehensive Income (Loss), net of tax:         
  Unrealized loss from hedging activities of equity method
    investments, net of tax of ($69), ($530) and ($371) for the years
    ended October 31, 2013, 2012 and 2011, respectively.
     (109)         (826)         (576)   

  Reclassification adjustment of realized gain from hedging activities

    of equity method investments included in net income, net of tax of
    $85, $621 and $420 for the years ended October 31, 2013, 2012
    and 2011, respectively.

     130         973         654   
  

 

 

    

 

 

    

 

 

 
    Total other comprehensive income      21         147         78   
  

 

 

    

 

 

    

 

 

 
Comprehensive Income    $ 134,438       $ 119,994       $ 113,646   
  

 

 

    

 

 

    

 

 

 
Average Shares of Common Stock:         
  Basic      74,884         71,977         72,056   
  Diluted      75,333         72,278         72,266   
Earnings Per Share of Common Stock:         
  Basic    $ 1.80       $ 1.67       $ 1.58   
  Diluted    $ 1.78       $ 1.66       $ 1.57   

See notes to consolidated financial statements.

 

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Consolidated Statements of Cash Flows

For the Years Ended October 31, 2013, 2012 and 2011

 

In thousands    2013      2012      2011  
Cash Flows from Operating Activities:         
  Net income    $       134,417       $       119,847       $       113,568   
  Adjustments to reconcile net income to net
    cash provided by operating activities:
        
      Depreciation and amortization      120,797         109,230         107,046   

  Allowance for doubtful accounts

     25         232         418   

  Net gain on sale of property

     (349)                 

  Income from equity method investments

     (26,056)         (23,904)         (24,027)   

  Distributions of earnings from equity method investments

     22,139         19,590         22,685   

  Deferred income taxes, net

     57,637         99,159         76,821   

  Changes in assets and liabilities:

        

    Gas purchase derivatives, at fair value

     1,319         (381)         47   

    Receivables

     (23,327)         5,403         (3,019)   

    Inventories

     (2,059)         18,897         13,789   

    Settlement of legal asset retirement obligations

     (2,389)         (2,038)         (1,493)   

    Overfunded postretirement asset

     (28,258)         22,879         (5,537)   

    Other assets

     47,967         (95,582)         8,360   

    Accounts payable

     2,381         4,283         (4,085)   

    Provision for postretirement benefits

     (25,257)         22,628         (134)   

    Other liabilities

     34,260         4,272         6,806   
  

 

 

    

 

 

    

 

 

 
Net cash provided by operating activities      313,247         304,515         311,245   
  

 

 

    

 

 

    

 

 

 
Cash Flows from Investing Activities:         
  Utility capital expenditures      (599,999)         (529,576)         (243,641)   
  Allowance for borrowed funds used during construction      (30,975)         (25,211)         (8,619)   
  Contributions to equity method investments      (41,348)         (3,566)         (6,222)   
  Distributions of capital from equity method investments      4,700         5,372         3,029   
  Proceeds from sale of property      1,951         1,250         1,074   
  Investments in marketable securities      (414)         (606)         (486)   
  Other      2,609         3,044         2,292   
  

 

 

    

 

 

    

 

 

 
Net cash used in investing activities      (663,476)         (549,293)         (252,573)   
  

 

 

    

 

 

    

 

 

 

 

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Consolidated Statements of Cash Flows

For the Years Ended October 31, 2013, 2012 and 2011

 

In thousands    2013      2012      2011  
Cash Flows from Financing Activities:         
  Borrowings under credit facility      10,000                    350,000                 1,723,000   
  Repayments under credit facility      (10,000)         (681,000)         (1,634,000)   
  Net borrowings - commercial paper      35,000         365,000          
  Proceeds from issuance of long-term debt, net of discount      299,856         300,000         200,000   
  Retirement of long-term debt                    (256,922)   
  Expenses related to issuance of debt      (3,250)         (3,908)         (3,902)   
  Proceeds from issuance of common stock, net of expenses      92,271                 

  Issuance of common stock through dividend reinvestment and employee stock plans

     24,610         22,123         20,233   
  Repurchases of common stock             (26,528)         (23,004)   
  Dividends paid      (92,146)         (85,693)         (82,913)   
  Other      (8)         (34)         (6)   
  

 

 

    

 

 

    

 

 

 
Net cash provided by (used in) financing activities      356,333         239,960         (57,514)   
  

 

 

    

 

 

    

 

 

 
Net Increase (Decrease) in Cash and Cash Equivalents      6,104         (4,818)         1,158   
Cash and Cash Equivalents at Beginning of Year      1,959         6,777         5,619   
  

 

 

    

 

 

    

 

 

 
Cash and Cash Equivalents at End of Year        $ 8,063           $ 1,959           $ 6,777   
  

 

 

    

 

 

    

 

 

 
Cash Paid During the Year for:         
  Interest        $         50,275           $ 44,571           $ 50,136   
  

 

 

    

 

 

    

 

 

 
  Income Taxes:         

  Income taxes paid

       $ 5,760           $ 4,770           $ 5,649   

  Income taxes refunded

     169         8,437         16,958   
  

 

 

    

 

 

    

 

 

 

  Income taxes, net

       $ 5,591           $ (3,667)           $ (11,309)   
  

 

 

    

 

 

    

 

 

 
Noncash Investing and Financing Activities:         
  Accrued construction expenditures        $ 39,389           $ 43,643           $ 18,055   

See notes to consolidated financial statements.

 

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Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2013, 2012 and 2011

 

In thousands except per share amounts    Common
Stock
     Retained
Earnings
    

Accumulated

Other
Comprehensive

Income (Loss)

     Total  

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   
           

 

 

 

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   
           

 

 

 

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   
  

 

 

    

 

 

    

 

 

    

 

 

 

The components of accumulated other comprehensive income (loss) (OCIL) as of October 31, 2013 and 2012 are as follows.

 

In thousands

   2013      2012  

Hedging activities of equity method investments

   $       (284)       $             (305)   

See notes to consolidated financial statements.

 

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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, 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 2 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont and its wholly owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. 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-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.

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 15 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 and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the periods reported. Actual results could differ significantly from estimates and assumptions.

 

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Segment Reporting

Our segments are based on the components of the Company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker 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-making activities. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance (O&M) expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures.

We have two reportable business segments, regulated utility and 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, with activities conducted by the utility. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures that are held by our wholly owned subsidiaries. See Note 14 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.

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. 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.

 

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Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2013 and 2012 are as follows.

 

In thousands

  

2013

    

2012

 

Regulatory Assets:

     

Unamortized debt expense

       $ 15,423           $ 13,583   

Amounts due from customers

     66,321         81,626   

Environmental costs

     9,416         10,202   

Deferred operations and maintenance expenses

     6,376         7,050   

Deferred pipeline integrity expenses

     19,449         13,691