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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   


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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   

Deferred pension and other retirement benefits costs

     20,736         20,139   

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

     80,604         123,290   

Regulatory cost of removal asset

     22,974         21,129   

Robeson LNG development costs

     1,808          

Other

     3,199         2,394   
  

 

 

    

 

 

 

Total

       $ 246,306           $ 293,104   
  

 

 

    

 

 

 

Regulatory Liabilities:

     

Regulatory cost of removal obligations

       $ 493,111           $ 464,334   

Amounts due to customers

            28   

Deferred income taxes

     48,647         25,330   

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

     139          
  

 

 

    

 

 

 

Total

       $       541,897           $       489,692   
  

 

 

    

 

 

 

As of October 31, 2013, we had regulatory assets totaling $.4 million on which we do not earn a return during the recovery period. The original amortization period for these assets is 15 years and the $.4 million will be fully amortized by 2018. We have $1.9 million related to unrealized mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing amounts due to/from customer accounts when realized and $80.6 million of regulatory postretirement assets, $23 million of asset retirement obligations (AROs) and $7.9 million of estimated environmental costs on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.

Utility Plant and Depreciation

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

 

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The classification of total utility plant, net, for the years ended October 31, 2013 and 2012 is presented below.

 

In thousands

  

2013

    

2012

 

Intangible plant

   $ 3,374       $ 3,374   

Other storage plant

     171,349         118,277   

Transmission plant

     1,403,829         866,000   

Distribution plant

     2,505,160         2,422,988   

General plant

     335,847         329,867   

Asset retirement cost

     7,565         10,819   

Contributions in aid of construction

     (5,187)         (5,147)   
  

 

 

    

 

 

 

Total utility plant in service

     4,421,937         3,746,178   

Less accumulated depreciation

     (1,088,331)         (1,036,814)   
  

 

 

    

 

 

 

Total 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   
  

 

 

    

 

 

 

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

AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the Consolidated Statements of Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For the three years ended October 31, 2013, 2012 and 2011, all of our AFUDC was attributable to borrowed funds.

AFUDC for the years ended October 31, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

AFUDC

   $ 30,975      $ 25,211      $ 8,619  

In accordance with utility accounting practice, we classified real estate and development costs associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina as “Plant held for future use” in the Consolidated Balance Sheets, due to construction being suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real

 

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estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs to be amortized over 38 months beginning January 1, 2014. We recorded $1.2 million as a regulatory asset along with $.5 million of costs that we allocated to South Carolina operations. We recorded cumulative amortization of $1.8 million of non-real estate costs in fiscal year 2013 that is included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on the 2013 general rate proceeding settlement of these costs, see Note 2 to the consolidated financial statements.

We compute depreciation expense using the straight-line method over periods ranging from 4 to 88 years. The composite weighted-average depreciation rates were 2.77% for 2013, 2.94% for 2012 and 3.19% for 2011.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina and March 1, 2012 for Tennessee. The new depreciation rates become effective January 1, 2014 in North Carolina under the settlement of the 2013 general rate proceeding.

As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in this Note 1. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.

Cash and Cash Equivalents

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31, 2013 and 2012.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of

 

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recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets.

We are exposed to credit risk when we enter into contracts with third parties to buy and sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. 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 credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2013 and 2012, our trade accounts receivable consisted of the following.

 

In thousands

  

2013

    

2012

 

Gas receivables

       $ 78,540           $ 55,956   

Non-regulated merchandise and service work receivables

     2,274         2,323   

Allowance for doubtful accounts

     (1,604)         (1,579)   
  

 

 

    

 

 

 

Trade accounts receivable

       $       79,210           $       56,700   
  

 

 

    

 

 

 

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

Balance at beginning of year

   $ 1,579       $ 1,347       $ 929   

Additions charged to uncollectibles expense

     5,314         4,584         4,842   

Accounts written off, net of recoveries

     (5,289)         (4,352)         (4,424)   
  

 

 

    

 

 

    

 

 

 

Balance at end of year

   $         1,604       $         1,579       $         1,347   
  

 

 

    

 

 

    

 

 

 

Inventories

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

 

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

At October 31, 2013 and 2012, such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of $31.5 million and $26.7 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The AMAs expire at various times through March 31, 2014. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.

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

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, short-term debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the Consolidated Balance Sheets in accordance with derivative accounting standards and marketable securities that are held in rabbi trusts established for our deferred compensation plans and are classified as trading securities. Our qualified pension and postretirement plan assets and liabilities are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of

 

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observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.

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

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities fund of funds, common trust funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.

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

In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement

 

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date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.

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

For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.

Goodwill, Equity Method Investments and Long-Lived Assets

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.

Our annual goodwill impairment assessment was performed as of October 31, 2013, and we determined that there was no impairment to the carrying value of our goodwill. No impairment has been recognized during the years ended October 31, 2013, 2012 and 2011. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. There were no events or circumstances during the years ended October 31, 2013, 2012 and 2011 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.

Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

 

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

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2013 and 2012 is as follows.

 

In thousands

   2013      2012  
      

Cost

    

Fair Value

    

Cost

    

Fair Value

 

Current trading securities:

           

Money markets

   $      $      $      $  

Mutual funds

     134         199         134         157   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total current trading securities

     134         199         134         157   
  

 

 

    

 

 

    

 

 

    

 

 

 

Noncurrent trading securities:

           

Money markets

     380         380         243         243   

Mutual funds

     1,995         2,615         1,668         1,888   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total noncurrent trading securities

     2,375         2,995         1,911         2,131   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total trading securities

   $       2,509       $       3,194       $       2,045       $       2,288   
  

 

 

    

 

 

    

 

 

    

 

 

 

Unamortized Debt Expense

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

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

Issuances and Repurchases of Common Stock

As discussed in Note 6 to the consolidated financial statements, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares. It

 

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is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders’ Equity. Shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under the Incentive Compensation Plan have been immaterial to date.

Asset Retirement Obligations

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

We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return. For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation” in this Note 1.

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.61% to 5.87% with a weighted average of 5.73% for the twelve months ended October 31, 2013. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. We have recorded a liability on our distribution and transmission mains and services.

 

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The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2013 and 2012 are presented below.

 

In thousands

  

2013

    

2012

 

Regulatory non-legal AROs

   $ 493,111       $ 464,334   

Conditional AROs

     27,016         28,629   
  

 

 

    

 

 

 

Total cost of removal obligations

   $         520,127       $         492,963   
  

 

 

    

 

 

 

A reconciliation of the changes in conditional AROs for the year ended October 31, 2013 and 2012 is presented below.

 

In thousands

  

2013

    

2012

 

Beginning of period

     $ 28,629         $ 27,395   

Liabilities incurred during the period

     2,052         1,705   

Liabilities settled during the period

     (2,389)         (2,038)   

Accretion

     1,641         1,570   

Adjustment to estimated cash flows

     (2,917)         (3)   
  

 

 

    

 

 

 

End of period

     $       27,016         $       28,629   
  

 

 

    

 

 

 

Revenue Recognition

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

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

 

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Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.

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

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

Cost of Gas and Deferred Purchased Gas Adjustments

We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers are deferred and included in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

Taxes

We have two categories of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.

 

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Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.

Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

Consolidated Statements of Cash Flows

With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Recently Issued Accounting Guidance

In December 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance to improve disclosures and make information more comparable to International Financial Reporting Standards regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity’s financial position. The new disclosure requirements are effective for annual periods beginning after January 1, 2013 and interim periods within those periods, and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending October 31, 2014. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.

In November 2012, the FASB finalized the presentation disclosures on items reclassified from accumulated other comprehensive income (OCI). We adopted this disclosure guidance for the second quarter of our fiscal year ending October 31, 2013. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

 

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In July 2013, the FASB issued accounting guidance on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist. The guidance was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2013, with early adoption permitted. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.

Reclassifications and Changes in Presentation

Reclassifications have been made to certain prior year financial statements to conform with the current year presentation. We have changed our 2012 presentation of regulatory assets and liabilities on the Consolidated Balance Sheets where regulatory assets and liabilities were presented in various line items to the 2013 presentation of a more cohesive presentation of the regulatory balances in single “Regulatory assets” and “Regulatory liabilities” line items. The corresponding line items within “Cash Flows from Operating Activities” in the Consolidated Statements of Cash Flows were also changed to reflect this balance sheet presentation; the reclassifications had no effect on previously reported amounts for net cash flows from operating, investing or financing activities. The changes in presentation had no effect on total assets or liabilities reported in the Consolidated Balance Sheets, or on any subtotals within the Consolidated Balance Sheets, or on previously reported operating income, net income, comprehensive income, earnings per share (EPS) or stockholders’ equity.

2. Regulatory Matters

Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.

The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.

North Carolina

The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing

 

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natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.

The NCUC had allowed EasternNC to defer its O&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. The deferred amounts accrued interest at a rate of 8.69% per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005 of $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses was $9 million at October 31, 2008. This balance is accruing interest at a rate of 7.84% per annum and is being amortized over a twelve year period. As of October 31, 2013 and 2012, we had unamortized balances of $6.4 million and $7 million, respectively.

Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance will accrue interest at a rate of 6.55% per annum and will be amortized over an 82-month period beginning January 1, 2014.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to all incremental external expenditures beginning November 1, 2004. Under the settlement of the 2008 general rate proceeding, the pipeline integrity management costs incurred between July 1, 2005 and June 30, 2008 of $4.6 million were fully amortized over a three-year period beginning November 1, 2008. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding discussed below was $17.3 million to be amortized over a five-year period beginning January 1, 2014. As of October 31, 2013, we have recorded a regulatory asset for deferred pipeline integrity expenses of $19.4 million. The existing regulatory asset treatment for ongoing pipeline integrity management costs continues until another recovery mechanism is established in a future rate proceeding.

Based on the approval of the settlement of the 2013 NCUC general rate proceeding discussed below, future capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an integrity management rider (IMR). The settlement also would approve recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period beginning January 2014.

 

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In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

In January 2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2013, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2013. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued January 2011, January 2012, November 2012 and November 2013 found our hedging activities during the review periods to be reasonable and prudent.

In October 2012, we filed a petition with the NCUC seeking authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In April 2013, we withdrew the petition, citing our intent to address the matter in a general rate application. The appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.

 

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In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges to produce overall increased annual revenues of $79.8 million, or 9.3% above the current annual revenues. In October, we reached a settlement with the NCUC Public Staff and intervening parties, in which the parties agreed to the following:

 

   

Adjusted rates and charges to provide incremental annual total revenues of $30.7 million, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.

   

An overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10%.

   

A new IMR designed to separately track and recover the costs associated with capital expenditures that are made to comply with federal pipeline safety and integrity requirements outside of a general rate case. IMR filings will occur annually in November to capture costs closed to plant through October with revised rates effective in February, which will provide revised rates in 2014.

   

Lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.

   

Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.

   

Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.

   

Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.

   

Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.

With the approval on December 17, 2013 by the NCUC of the settlement discussed above, the new rates will become effective January 1, 2014. The increase in annual total revenues of $30.7 million represents a 3.58% increase in total revenues, or .7% annual increase per year since the last general rate proceeding in 2008.

South Carolina

We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2011, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS) and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of 11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service, effective November 1, 2011.

In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012.

 

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In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2012 order. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013.

In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates.

In August 2011, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated that our hedging program should no longer have a required minimum volume of hedging.

In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.

In August 2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2013.

Tennessee

In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in O&M expenses. The written order was issued by the TRA in June 2012.

 

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In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.

In September 2010, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances.

In December 2010, we filed our report with the TRA for the eighteen months ended June 30, 2010 reflecting the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA approved the deferred gas cost account balances and issued its written order.

In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA approved the TIP account balances. The TRA issued its written order approving our TIP account balances in March 2013.

In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2013, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in March 2013.

In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under the TIP. We are waiting on a ruling from the TRA at this time.

 

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In August 2013, we filed an ACA petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. We are waiting on a ruling from the TRA at this time. We intend to file our ACA annual report for the twelve months ended June 30, 2013 upon resolution of this petition.

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above then current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes were proposed to be effective March 1, 2012. In December 2011, we and the Consumer Advocate and Protection Division reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above then current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA’s written order was issued in April 2012.

As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for deferred accounting treatment in October 2010. These deferred expenses are being amortized over 8 years beginning March 1, 2012.

In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. On November 27, 2013, we filed with the TRA a settlement with the Tennessee Attorney General’s Consumer Advocate Division agreeing to the IMR. A hearing on this matter was held December 18, 2013, and the TRA approved the IMR settlement as filed.

All States

Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. In all three jurisdictions

 

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for the twelve months ended October 31, 2013, we generated $35.9 million of margin from secondary market activity, $26.9 million of which is allocated to customers as gas cost reductions and $9 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us.

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

3. Earnings Per Share

We compute basic EPS using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans and forward sale agreements are contingently issuable shares, as determined by applying the treasury stock method, and are included in our calculation of fully diluted EPS.

A reconciliation of basic and diluted EPS for the years ended October 31, 2013, 2012 and 2011 is presented below.

 

In thousands except per share amounts

  

2013

    

2012

    

2011

 

Net Income

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

 

 

    

 

 

    

 

 

 

Average shares of common stock outstanding for basic earnings per share

     74,884         71,977         72,056   

Contingently issuable shares under incentive compensation plans

     289         301         210   

Contingently issuable shares under forward sale agreements

     160                  
  

 

 

    

 

 

    

 

 

 

Average shares of dilutive stock

     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   

 

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4. Long-Term Debt

Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2013 and 2012 is as follows.

 

In thousands             2013                        2012           

Senior Notes:

     

  2.92%, due June 6, 2016

     $ 40,000         $ 40,000   

  8.51%, due September 30, 2017

     35,000         35,000   

  4.24%, due June 6, 2021

     160,000         160,000   

  3.47%, due July 16, 2027

     100,000         100,000   

  3.57%, due July 16, 2027

     200,000         200,000   

  4.65%, due August 1, 2043

     300,000          

Medium-Term Notes:

     

  5.00%, due December 19, 2013

     100,000         100,000   

  6.87%, due October 6, 2023

     45,000         45,000   

  8.45%, due September 19, 2024

     40,000         40,000    

  7.40%, due October 3, 2025

     55,000         55,000   

  7.50%, due October 9, 2026

     40,000         40,000   

  7.95%, due September 14, 2029

     60,000         60,000   

  6.00%, due December 19, 2033

     100,000         100,000   
  

 

 

    

 

 

 

    Total

     1,275,000         975,000   

Less current maturities

     100,000          

Less discount on issuance of notes

     143          
  

 

 

    

 

 

 

    Total

     $ 1,174,857         $ 975,000   
  

 

 

    

 

 

 

Current maturities for the next five years ending October 31 and thereafter are as follows.

 

In thousands       

2014

     $ 100,000   

2015

      

2016

     40,000   

2017

     35,000   

2018

      

Thereafter

     1,100,000   
  

 

 

 

  Total

     $     1,275,000   
  

 

 

 

On July 16, 2012, we issued $100 million of senior notes with an interest rate of 3.47%. On October 15, 2012, we issued $200 million of senior notes with an interest rate of 3.57%. Both issuances mature on July 16, 2027. These proceeds were used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.

We have an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that is available for future use until its expiration date of 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, advances for or investments in our subsidiaries and for repurchases of shares of our common stock. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements.

 

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On August 1, 2013, we issued $300 million of thirty-year, unsecured senior notes with an interest rate of 4.65% and at a discount of .048% or $144,000, which we began to amortize ratably over the expected life of the notes, under the registration statement noted above. We have the option to redeem all or part of the notes before the stated maturity prior to February 1, 2043, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after February 1, 2043, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.2 million from this issuance to finance capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term, unsecured notes under our commercial paper (CP) program and for general corporate purposes.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31, 2013, our retained earnings were not restricted as the amount available for restricted payments was greater than our actual retained earnings as presented below.

 

In thousands

      

Amount available for restricted payments

   $ 760,870  

Retained earnings

     627,236  

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, we are in compliance with all default provisions.

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

 

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

 

  Interest coverage of at least 1.75 times. Interest coverage was 4.6 times as of October 31, 2013;

 

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  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.

5. Short-Term Debt Instruments

We have a $650 million five-year revolving syndicated credit facility that expires on October 1, 2017. The facility 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 facility provides a line of credit for letters of credit of $10 million, of which $2.1 million and $3.6 million were issued and outstanding at October 31, 2013 and 2012, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. See Note 4 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements.

We have a $650 million unsecured CP program that is backstopped by the revolving syndicated credit facility. In conjunction with the exercise of the option in November 2013, the amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, have been increased to, but cannot exceed, $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

As of October 31, 2013, we have $400 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets, with original maturities ranging from 1 to 37 days from their dates of issuance at a weighted average interest rate of .36%. As of October 31, 2012, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $365 million at a weighted average interest rate of .42%.

 

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A summary of the short-term debt activity for the twelve months ended October 31, 2013 is as follows.

Short-Term Debt Activity

 

             Credit                     Commercial                     Total          

In thousands

           Facility                     Paper                     Borrowings          

      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 

       (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.

        

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 59% at October 31, 2013.

6. Stockholders’ Equity

Capital Stock

Changes in common stock for the years ended October 31, 2013, 2012 and 2011 are as follows.

 

In thousands

        Shares                  Amount         

Balance, October 31, 2010

     72,282       $ 445,640   

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

     30         870   

  Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)

     657         18,834   

  Issued to participants in the Incentive Compensation Plan (ICP)

     149         4,451   

  Shares repurchased under Accelerated Share Repurchase (ASR) agreement

     (800)         (23,004)   
  

 

 

    

 

 

 

Balance, October 31, 2011

     72,318         446,791   

  Issued to ESPP

     30         894   

  Issued to DRIP

     677         20,508   

  Issued to ICP

     25         796   

  Shares repurchased under ASR agreement

     (800)         (26,528)   
  

 

 

    

 

 

 

Balance, October 31, 2012

     72,250         442,461   

  Issued to ESPP

     33         1,056   

  Issued to DRIP

     720         22,791   

  Issued to ICP

     96         3,065   

  Issuance of common stock through public share offering, net of underwriting fees

     3,000         92,640   

  Costs from issuance of common stock

            (369)   
  

 

 

    

 

 

 

Balance, October 31, 2013

     76,099        $ 561,644   
  

 

 

    

 

 

 

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are cancelled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.

 

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On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved at that time an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our 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.

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 as follows.

 

   

Direct shares – 3 million shares were issued by us and delivered directly to the underwriters with settlement on February 4, 2013. We received $92.6 million from the underwriters and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share. The net proceeds from this sale of our common stock were used to repay outstanding short-term, unsecured notes under our CP program.

 

   

Forward shares – 1 million shares were borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013. Under this initial forward sale agreement (FSA) that we executed with the forward counterparty on January 29, 2013, we agreed to sell 1 million shares to the forward counterparty at the same price as the direct shares to be settled no later than mid December 2013. Under the terms of this FSA, at our election, we may physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreement.

 

   

Additional shares – Up to .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock at the net price described above of $30.88 per share with settlement on February 22, 2013. We elected to place the .6 million shares under an additional FSA having substantially similar terms as the original FSA, including settlement options at our election as described above. In connection with the additional FSA, the .6 million shares were borrowed from third parties and sold to the underwriters by the forward counterparty.

On December 16, 2013, we physically settled the FSAs 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. Upon

 

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settlement, we used the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

In accordance with ASC 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity , we have classified the FSAs as equity transactions because the forward sale transactions are indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts were recorded in the consolidated financial statements until settlement of each FSA.

Upon physical settlement of the FSAs, delivery of our shares resulted in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

On January 4, 2012, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $33.77 per share. The settlement and retirement of those shares occurred on January 5, 2012. Total consideration paid to purchase the shares of $27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the Consolidated Balance Sheets.

As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.09 per share discount, was higher than the January 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on February 28, 2012, we received $.5 million from the investment bank and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets. The $.5 million was the difference between the investment bank’s weighted average purchase price of $33.25 per share less a discount of $.09 per share for a settlement price of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares. We had an ASR transaction in 2011 as presented in the table above with a similar structure with the investment bank, which were accounted for in the same manner.

 

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As of October 31, 2013, our shares of common stock were reserved for issuance as follows.

 

In thousands

      

ESPP

     210   

DRIP

     1,538   

ICP

     1,050   
  

 

 

 

  Total

             2,798   
  

 

 

 

Other Comprehensive Income (Loss)

OCIL is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 12 to the consolidated financial statements. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2013 and 2012.

 

Changes in Accumulated OCIL (1)  

In thousands

  

Balance, October 31, 2011

   $ (452)   
  

 

 

 

OCIL before reclassifications, net of tax

     (826)   

Amounts reclassified from accumulated OCIL, net of tax

     973  
  

 

 

 

  Total current period activity, net of tax

     147  
  

 

 

 

Balance, October 31, 2012

     (305)   
  

 

 

 

OCIL before reclassifications, net of tax

     (109)   

Amounts reclassified from accumulated OCIL, net of tax

     130  
  

 

 

 

  Total current period activity, net of tax

     21  
  

 

 

 

Balance, October 31, 2013

   $             (284)   
  

 

 

 

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

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2013 and 2012.

 

     Reclassifications Out of       
     Accumulated OCIL  (1)       
     Years Ended       
     October 31,      Affected Line Items on Statement of
In thousands    2013      2012      Comprehensive Income

Hedging activities of equity method investments

   $ (215)       $ (1,594)       Income from equity method investments

Income tax expense

     85        621      Income taxes
  

 

 

    

 

 

    

  Total reclassification for the period, net of tax

   $ (130)       $ (973)      
  

 

 

    

 

 

    

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

 

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7. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2013 and 2012, we had long gas purchase options providing total coverage of 25.4 million dekatherms and 35.8 million dekatherms, respectively. The long gas purchase options held at October 31, 2013 are for the period from December 2013 through October 2014.

Fair Value Measurements

We use financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of October 31, 2013 and 2012. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2013 and 2012.

 

Recurring Fair Value Measurements as of October 31, 2013  
                Significant                    
         Quoted Prices              Other              Significant             
         in Active              Observable              Unobservable              Total      
         Markets              Inputs              Inputs              Carrying      
In thousands         (Level 1)                (Level 2)                (Level 3)                Value       

Assets:

           

Derivatives held for distribution operations

   $ 1,834       $       $      $ 1,834   

Debt and equity securities held as trading securities:

           

  Money markets

     380                       380   

  Mutual funds

     2,814                       2,814   
  

 

 

    

 

 

    

 

 

    

 

 

 

  Total fair value assets

   $ 5,028       $       $      $ 5,028   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Recurring Fair Value Measurements as of October 31, 2012  
                Significant                    
         Quoted Prices              Other              Significant             
         in Active              Observable              Unobservable              Total      
         Markets              Inputs              Inputs              Carrying      
In thousands         (Level 1)                (Level 2)                (Level 3)                Value       

Assets:

           

Derivatives held for distribution operations

   $ 3,153       $       $       $ 3,153   

Debt and equity securities held as trading securities:

           

  Money markets

     243                       243   

  Mutual funds

     2,045                       2,045   
  

 

 

    

 

 

    

 

 

    

 

 

 

  Total fair value assets

   $ 5,441       $       $       $ 5,441   
  

 

 

    

 

 

    

 

 

    

 

 

 

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

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

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

 

     Carrying         
In thousands    Amount      Fair Value  

As of October 31, 2013

   $     1,275,000      $     1,409,892  

As of October 31, 2012

     975,000        1,163,227  

Quantitative and Qualitative Disclosures

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts are presented on a gross basis and do not reflect any netting of asset and liability amounts or cash collateral amounts under master netting arrangements.

 

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The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2013 and 2012.

 

Fair Value of Derivative Instruments  
In thousands         2013                2012       

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:

     

Asset Financial Instruments:

     

  Current Assets - Gas purchase derivative assets (December 2013 - October 2014)

   $     1,834      
  

 

 

    

  Current Assets - Gas purchase derivative assets (December 2012 - October 2013)

      $     3,153   
     

 

 

 

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due to/from customers included as “Regulatory Assets” or “Regulatory Liabilities” in Note 1 to the consolidated financial statements and recognized in the Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2013 and 2012, absent the regulatory treatment under our approved PGA procedures.

 

                                                                                              
                               Location of Loss  
     Amount of Loss Recognized      Amount of Loss Deferred      Recognized through  
In thousands    on Derivative Instruments      Under PGA Procedures      PGA Procedures  
         Twelve Months Ended              Twelve Months Ended             
     October 31           October 31              
          2013                   2012                2013                   2012              

Gas purchase options

   $         6,303           $         8        $         6,303           $         8          Cost of Gas    

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

 

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Credit and Counterparty Risk

We are exposed to credit risk as a result of transactions for the purchase and sale of products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $13.4 million, or approximately 17% of our gross trade accounts receivable at October 31, 2013. 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 believe, based on our credit policies as of October 31, 2013, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.

 

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Risk Management

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

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under an Enterprise Risk Management program. In addition, we have an Energy Price Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.

8. Commitments and Contingent Liabilities

Leases

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

Operating lease payments for the years ended October 31, 2013, 2012 and 2011 are as follows.

 

In thousands         2013                2012                2011       

Operating lease payments (1)

   $ 4,729       $ 3,712       $ 4,496   

 

(1)  

Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

 

In thousands

      

2014

   $ 4,543   

2015

     4,592   

2016

     4,491   

2017

     4,297   

2018

     4,225   

Thereafter

     31,496   
  

 

 

 

  Total

   $         53,644   
  

 

 

 

Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide

 

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service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for pipeline and storage capacity contracts are up to twenty-two years. The time periods for gas supply contracts are up to one year. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

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

As of October 31, 2013, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

 

         Pipeline and                     Telecommunications                    
         Storage                     and Information                    
In thousands             Capacity                    Gas Supply                Technology                Other                    Total           

2014

     $ 170,430         $ 6,356         $ 11,045         $ 24,951        $ 212,782   

2015

     157,407                4,676         -         162,083   

2016

     150,544                 760         -         151,304   

2017

     145,494                         -         145,494   

2018

     142,983                         -         142,983   

Thereafter

     781,549                         -         781,549   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

  Total

     $     1,548,407         $     6,356         $     16,481         $     24,951        $     1,596,195   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Legal

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

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $2.1 million in letters of credit that were issued and outstanding at October 31, 2013. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.

 

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In 1997, we entered into a settlement with a third-party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy Corporation (DEC), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

There are four other MGP sites located in Reidsville and Hickory, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and for which we have an investigation and remediation liability. In fiscal year 2012, we performed soil remediation work at our Reidsville site. In July 2012, the North Carolina Department of Environment and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which included installing five monitoring wells in September 2012. The NCDENR is no longer requiring the groundwater remedial action plan. We filed land use restrictions on the property with the NCDENR in the fourth quarter of our fiscal year 2013. Upon NCDENR’s completed review, we will file land use restrictions with the Register of Deeds for Reidsville, North Carolina. We have incurred $.6 million of remediation costs at the Reidsville site through October 31, 2013.

As part of a voluntary agreement with the NCDENR, we conducted and completed soil remediation for the Hickory, North Carolina MGP site in 2010. A Phase II groundwater investigation was conducted in 2011. A groundwater remedial action plan was submitted and approved by NCDENR in 2012. We continue to conduct quarterly groundwater monitoring at this site in accordance with our site remediation plan. NCDENR has approved land use restrictions on this site. Once we obtain the property owner’s signature, we will then file land use restrictions with the Register of Deeds for Hickory, North Carolina. We have incurred $1.5 million of remediation costs at this site through October 31, 2013.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been completed, and a final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. We have incurred $1.5 million of remediation costs at this site through October 31, 2013.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the

 

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site for this issue. In September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. On April 11, 2012, we entered into a no admit/no deny ACO that imposed a fine of $40,000, unpaid annual fees totaling $18,000 and investigative and administrative costs of $1,860. As part of the ACO, we are required to develop a site assessment plan to determine the extent of the groundwater contamination related to the sieve burial, a groundwater remediation strategy and a groundwater and surface water site-wide monitoring program. A site assessment plan was accepted by the NCDENR, and we began groundwater sampling in July 2012. We performed an initial round of sampling in November and December 2012 which was inconclusive as to migration, and thus additional groundwater monitoring wells were installed during March 2013 to aid in determining the extent of the groundwater contamination. The groundwater sampling results were submitted to the NCDENR in October 2013, and based on their response, we may be required to submit additional plan(s) to remediate and/or monitor the groundwater.

The Huntersville LNG facility was originally coated with lead-based paint. To avoid lead-based paint exposure or ground contamination, removal of lead-based paint from the site was initiated in spring 2010. The last phase of the lead-based paint removal began in July 2012 on the LNG tank, and the remediation of rafters in a nearby building began in the fourth quarter of our fiscal year 2013 with completion anticipated for both projects by the end of fiscal 2014. We have incurred $4.6 million of remediation costs through October 31, 2013 for all issues at the Huntersville LNG plant site.

Our Nashville LNG facility was also originally coated with lead-based paint. We completed the remediation of the facility in May 2012 and incurred $.5 million of remediation costs.

We have transitioned away from owning and maintaining our own petroleum underground storage tanks (USTs) with the exception of our Charlotte, North Carolina resource center which continues to operate two USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina resource centers had their tanks removed, and we do not anticipate significant environmental remediation with respect to those removals. The South Carolina Department of Health and Environmental Control (SCDHEC) requested that we conduct an initial groundwater assessment at our Greenville, South Carolina site to determine its current groundwater quality condition. This assessment was conducted in August 2012, and in November 2012, we received a determination letter from the SCDHEC that no further groundwater remediation would be required at the site for this issue.

In July 2005, we were notified by the NCDENR that we were named as a potentially responsible party for alleged environmental issues associated with a propane UST site in Clemmons, North Carolina. We owned and operated this site from March 1986 until June 1988 in connection with a non-utility venture. There have been at least four owners of the site. We contend that we contractually transferred any and all clean-up costs to the new owner of the site when we sold this venture in June 1988. However, the owners that purchased the property contend that we only transferred the clean-up costs associated with the gasoline pumps and not the USTs. It is unclear of the outcome of this case and how many of the former owners may ultimately be responsible for this site. Based on the uncertainty of the ultimate liability, we established an immaterial non-regulated environmental liability for one-fourth of the estimated cost to remediate the site.

 

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One of our resource centers has coatings containing asbestos on some of their pipelines. We have educated our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline, which generally occur only in small increments.

For all the matters discussed above, as of October 31, 2013, our estimated undiscounted environmental liability totaled $1.3 million, and consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.1 million for the groundwater remediation at the Huntersville LNG site, and $.1 million for the LNG facilities and USTs not yet remediated. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

As of October 31, 2013, our regulatory assets for unamortized environmental costs in our three-state territory totaled $9.4 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding approves recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013, pursuant to the annual rate stabilization order dated October 2013. For further information on regulatory matters, see Note 2 to the consolidated financial statements.

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

9. Employee Benefit Plans

Under accounting guidance, we are required to recognize all obligations related to defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Our plans’ assets are required to be accounted for at fair value.

Pension Benefits

We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an

 

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eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.

The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.

Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:

 

  Achieve full funding over the longer term, and
  Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.

We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.

The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

 

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The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds, asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.

Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2013, we contributed $.7 million to the MPP plan.

OPEB Plan

We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.

OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

 

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Supplemental Executive Retirement Plans

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.

We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.

We have a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded monthly through a rabbi trust with a bank as the trustee. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.

The funding to the DCR plan accounts for the years ended October 31, 2013 and 2012, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2013 and 2012 are presented below.

 

In thousands         2013                2012       

Funding

   $ 434       $ 422   

Liability:

     

  Current

     199         160   

  Noncurrent

     3,328         2,412   

We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance

 

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policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.

 

In thousands         2013                2012                2011       

Term life policies of certain officers at the vice president level and above

   $ 27       $ 43       $ 56   

Officers and director-level employees

     28         25         24   

 

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Actuarial Plan Information

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2013 and 2012, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2013 and 2012 are presented below.

 

          Qualified Pension                Nonqualified Pension                Other Benefits       
In thousands           2013                    2012                    2013                    2012                    2013                    2012         

Accumulated benefit obligation at year end

     $ 230,175         $     245,361        $ 4,736         $ 5,569             N/A                N/A      
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Change in projected benefit obligation:

                 

  Obligation at beginning of year

     $ 293,327         $ 236,632         $ 5,569         $ 5,219         $ 34,830         $ 31,900   

  Service cost

     12,005         9,573                 39         1,327         1,387   

  Interest cost

     9,946         10,640         157         203         1,130         1,347   

  Actuarial (gain) loss

     (24,859)         54,852         (540)         629         (1,094)         2,630   

  Participant contributions

                                     641         788   

  Administrative expenses

     (534)         (420)                                   

  Benefit payments

     (17,482)         (17,950)         (450)         (521)         (3,156)         (3,222)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

  Obligation at end of year

         272,403         293,327         4,736         5,569         33,678         34,830   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Change in fair value of plan assets:

                 

  Fair value at beginning of year

     272,337         259,511                         23,663         22,045   

  Actual return on plan assets

     26,340         31,196                         2,848         1,972   

  Employer contributions

     20,000                 450         521         1,965         2,080   

  Participant contributions

                                     641         788   

  Administrative expenses

     (534)         (420)                                   

  Benefit payments

     (17,482)         (17,950)         (450)         (521)         (3,156)         (3,222)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

  Fair value at end of year

     300,661         272,337                         25,961         23,663   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Funded status at year end - (under) over

     $ 28,258         $ (20,990)         $ (4,736)         $ (5,569)         $ (7,717)         $ (11,167)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

  Noncurrent assets

     $ 28,258         $         $         $         $         $   

  Current liabilities

                     (445)         (502)                   

  Noncurrent liabilities

             (20,990)         (4,291)         (5,067)         (7,717)         (11,167)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

  Net amount recognized

     $ 28,258         $ (20,990)       $ (4,736)         $ (5,569)         $ (7,717)         $ (11,167)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred

                 

  Regulatory Account:

                 

    Unrecognized transition obligation

     $         $         $         $         $         $ (667)   

    Unrecognized prior service (cost) credit

     17,243         19,441         (196)         (277)                   

    Unrecognized actuarial loss

     (96,338)         (137,633)         (820)         (1,521)         (354)         (2,633)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

    Regulatory asset

     (79,095)         (118,192)         (1,016)         (1,798)         (354)         (3,300)   

    Cumulative employer contributions in excess of cost

     107,353         97,202         (3,720)         (3,771)         (7,363)         (7,867)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

    Net amount recognized

     $ 28,258         $ (20,990)         $     (4,736)         $     (5,569)         $     (7,717)         $     (11,167)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCIL as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.

 

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Net periodic benefit cost for the years ended October 31, 2013, 2012 and 2011 includes the following components.

 

      

Qualified Pension

    

Nonqualified Pension

    

Other Benefits

 

In thousands

  

2013

    

2012

    

2011

    

2013

    

2012

    

2011

    

2013

    

2012

    

2011

 

Service cost

     $ 12,005         $ 9,573         $ 8,508         $         $ 39         $ 45         $ 1,327         $ 1,387         $ 1,398   

Interest cost

     9,946         10,640         11,024         157         203             209         1,130         1,347         1,495   

Expected return on plan assets

         (21,105)             (20,289)             (20,608)                                 (1,663)             (1,551)         (1,534)   

Amortization of transition obligation

                                                     667         667         667   

Amortization of prior service cost (credit)

     (2,198)         (2,198)         (2,198)         81         81         20                           

Amortization of net loss

     11,202         5,966         3,547         161         49         41                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic benefit cost

     9,850         3,692         273         399         372         315         1,461         1,850         2,026   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Other changes in plan assets and benefit obligation recognized through regulatory asset or liability:

                          

Prior service cost

                                             290                           

Net loss (gain)

     (30,094)         43,945         17,539             (540)             629         130         (2,278)         2,209         415   

Amounts recognized as a component of net periodic benefit cost:

                          

Transition obligation

                                                     (667)         (667)         (667)   

Amortization of net loss

     (11,202)         (5,966)         (3,547)         (161)         (49)         (41)                           

Prior service (cost) credit

     2,198         2,198         2,198         (81)         (81)         (20)                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total recognized in regulatory asset (liability)

     (39,098)         40,177         16,190         (782)         499         359         (2,945)         1,542         (252)   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total recognized in net periodic benefit cost and regulatory asset (liability)

     $ (29,248)         $ 43,869         $ 16,463         $ (383)         $ 871         $ 674         $     (1,484)         $ 3,392         $     1,774   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The 2014 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.

 

In thousands

   Qualified Pension     Nonqualified Pension      Other Benefits  

Amortization of unrecognized prior service cost (credit)

   $ (2,198   $ 81      $ -   

Amortization of unrecognized actuarial loss

     7,138       47        -   

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s Investors Service’s or Standard & Poor’s Ratings Services that have a yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31, 2013, the benchmark by plan was as follows.

 

Pension plan

     4.55

NCNG SERP

     3.89

Directors’ SERP

     4.09

Piedmont SERP

     3.31

OPEB

     4.44

 

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Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.

We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.

The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2013 and 2012 are presented below.

 

      

Qualified Pension

    

Nonqualified Pension

    

Other Benefits

 
      

2013

    

2012

    

2013

    

2012

    

2013

    

2012

 

Discount rate

     4.55%         3.51%         3.98%         2.95%         4.44%         3.34%   

Rate of compensation increase

     3.72%         3.76%         N/A         N/A         N/A         N/A   

 

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The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2013, 2012 and 2011 are presented below.

 

      

Qualified Pension

   

Nonqualified Pension

 
      

2013

   

2012

   

2011

   

2013

   

2012

   

2011

 

Discount rate

     3.51     4.67     5.47     2.95     4.10     4.37

Expected long-term rate of return on plan assets

     8.00     8.00     8.00     N/A        N/A        N/A   

Rate of compensation increase

     3.76     3.78     3.87     N/A        N/A        N/A   
    

Other Benefits

       
    

2013

   

2012

   

2011

   

Discount rate

     3.34     4.36     4.85  

Expected long-term rate of return on plan assets

     8.00     8.00     8.00  

Rate of compensation increase

     N/A        N/A        N/A     

We anticipate that we will contribute the following amounts to our plans in 2014.

 

In thousands

      

Qualified pension plan *

   $     20,000  

Nonqualified pension plans

     444  

MPP plan

     885  

OPEB plan

     1,500  

* Funded in November 2013.

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

 

     Qualified      Nonqualified      Other  

In thousands

  

Pension

    

Pension

    

Benefits

 

2014

   $ 25,918      $ 444      $ 2,140  

2015

     16,918        458        2,262  

2016

     15,169        434        2,322  

2017

     16,154        410        2,417  

2018

     18,672        383        2,507  

2019 - 2023

         106,226            1,890            13,640  

 

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The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2013 and 2012 are presented below.

 

    

2013

   

2012

 

Health care cost trend rate assumed for next year

     7.40     7.50

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

     5.00     5.00

Year that the rate reaches the ultimate trend rate

     2027        2027   

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.

 

In thousands

  

1% Increase

    

1% Decrease

 

Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2013

   $ 21      $ (27

Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2013

     690        (699

Fair Value Measurements

Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.

Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.

Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have been valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.

U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.

Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.

Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.

High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.

Derivatives – The Level 1 assets were valued using a compilation of observable market information on an active market. The Level 2 assets were valued using broker quotes on a non-active market.

 

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Large cap core index – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).

Large cap value and small cap value – These are Level 1 assets valued at the market price of the active market on which the individual security is traded.

Large cap growth and global REIT (and for 2012, international value) – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed equity funds.

Common trust funds – International growth and international value – These are Level 2 assets held in common trust funds in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently there are no restrictions on redemptions for the funds.

Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.

Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 5% but is still being funded through capital calls; $7.4 million of the original $12 million subscription remains unfunded. Until a 5% allocation can be achieved, the balance of the 5% allocation is invested in a low-cost equity index fund that tracks the S&P 500 Index. Our investment is in various funds that invests in North American companies; allocate capital to private equity funds; invest in venture capital partnerships; and private equity partnerships in emerging markets.

Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.

 

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As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.

 

       Redemption        

Redemptions

Notice

Investment

  

Frequency

  

Other Redemption Restrictions

  

Period

Common trust fund -
International growth

   Monthly   

None

   30 days

Common trust fund -
International value

   Daily   

None

   5 days

Hedge fund of funds

   Quarterly   

Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2013.

   65 days

Private equity fund of funds

   Limited   

Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.

   (1)

Commodities fund of funds

   Monthly   

Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.

   35 days

(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.

The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2013 and 2012 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

 

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       Qualified Pension Plan as of October 31, 2013  
      

    Quoted Prices    
in Active

Markets

    

Significant

Other

Observable

Inputs

    

Significant

Unobservable  

Inputs

    

Total

Carrying  

     % of    

In thousands

   (Level 1)      (Level 2)      (Level 3)      Value      Total     

Cash and cash equivalents

     $ 5,566          $ 156          $ -           $ 5,722          2%     
              

 

 

 

Fixed Income Securities:

                 38%     
              

 

 

 

U.S. treasuries

     -           24,078          -           24,078          8%     

Long duration bonds

     -           34,041          -           34,041          11%     

Corporate bonds

     -           42,701          -           42,701          14%     

High yield bonds

     14,680          -           -           14,680          5%     

Collateralized mortgage obligations

     -           1,098          -           1,098          -%     

Municipals

     -           -           -           -           -%     

Derivatives

     6          (17)          -           (11)          -%     
              

 

 

 

Equity Securities:

                 43%     
              

 

 

 

Large cap core index

     12,023          -           -           12,023          4%     

Large cap value

     16,908          -           -           16,908          6%     

Large cap growth

     17,823          -           -           17,823          6%     

Small cap value

     30,831          -           -           30,831          10%     

Common trust fund - International value

     -           24,460          -           24,460          8%     

Common trust fund - International growth

     -           27,270          -           27,270          9%     
              

 

 

 

Real Estate:

                 5%     
              

 

 

 

Global REIT

     15,042          -           -           15,042          5%     
              

 

 

 

Other Investments:

                 12%     
              

 

 

 

Hedge fund of funds

     -           18,571          -           18,571          6%     

Private equity fund of funds

     -           -           4,659          4,659          2%     

Commodities fund of funds

     -           10,765          -           10,765          4%     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets at fair value

     $     112,879          $     183,123          $       4,659          $     300,661              100%     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Percent of fair value hierarchy

     37%          61%          2%          100%      
  

 

 

    

 

 

    

 

 

    

 

 

    

 

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       Qualified Pension Plan as of October 31, 2012  
       Quoted Prices
in Active
Markets
     Significant
Other
Observable
Inputs
     Significant
Unobservable
Inputs
     Total
Carrying
     % of  

In thousands

   (Level 1)      (Level 2)      (Level 3)      Value      Total  

Cash and cash equivalents

     $ 5,346         $        $        $ 5,346         2%   
              

 

 

 

Fixed Income Securities:

                 45%   
              

 

 

 

U.S. treasuries

            17,544                17,544         6%   

Long duration bonds

            63,565                63,565         23%   

Corporate bonds

            26,368                26,368         10%   

High yield bonds

     13,777                       13,777         5%   

Collateralized mortgage obligations

            1,513                1,513         1%   

Municipals

            345                345         -%   

Derivatives

     (3)         (86)                (89)         -%   
              

 

 

 

Equity Securities:

                 36%   
              

 

 

 

Large cap core index

     10,260                       10,260         4%   

Large cap value

     10,427                       10,427         4%   

Large cap growth

     15,252                       15,252         6%   

Small cap value

     26,335                       26,335         10%   

International value

     14,376                       14,376         5%   

Common trust fund - International growth

            18,678                18,678         7%   
              

 

 

 

Real Estate:

                 6%   
              

 

 

 

Global REIT

     16,252                       16,252         6%   
              

 

 

 

Other Investments:

                 11%   
              

 

 

 

Hedge fund of funds

            16,995                16,995         6%   

Private equity fund of funds

                   3,522         3,522         1%   

Commodities fund of funds

            11,871                11,871         4%   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets at fair value

     $     112,022         $     156,793         $       3,522         $     272,337             100%   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Percent of fair value hierarchy

     41%         58%         1%         100%      
  

 

 

    

 

 

    

 

 

    

 

 

    

In 2012, we transferred amounts from Level 3 to Level 2 for our investments in the hedge fund of funds and the commodities fund of funds because inputs became more observable. The international value fund that was classified as a Level 1 asset as of October 31, 2012 was sold, and the proceeds were invested in the common trust fund – international value during fiscal year 2013. The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

 

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       Hedge Fund      Private
Equity Fund
     Commodities         

In thousands

   of Funds      of Funds      Fund of Funds      Total  

Balance, October 31, 2011

     $     6,207           $     1,925           $     8,472           $     16,604     

Actual return on plan assets:

           

Relating to assets still held at the reporting date

     -           13           -            13     

Relating to assets sold during the period

     -            145           -            145     

Purchases, sales and settlements (net)

     -            1,439           -            1,439     

Transfer in/out of Level 3

     (6,207)           -            (8,472)           (14,679)     
  

 

 

    

 

 

    

 

 

    

 

 

 

Balance, October 31, 2012

     -            3,522           -            3,522     

Actual return on plan assets:

           

Relating to assets still held at the reporting date

     -            116           -            116     

Relating to assets sold during the period

     -            61           -            61     

Purchases, sales and settlements (net)

     -            960           -            960     

Transfer in/out of Level 3

     -            -            -            -      
  

 

 

    

 

 

    

 

 

    

 

 

 

Balance, October 31, 2013

     $ -            $ 4,659           $ -            $ 4,659     
  

 

 

    

 

 

    

 

 

    

 

 

 

During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.

There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.

Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.

Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.

U.S. treasuries – These are Level 1 assets in an actively managed mutual fund measured at NAV.

Corporate bonds/Other fixed income securities – These are Level 1 assets valued at the quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to a high yield bond fund.

Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV as invested in mutual funds that invest by a specific style.

Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.

 

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International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.

Global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.

The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2013 and 2012 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

 

     Other Benefits as of October 31, 2013  
       Quoted Prices
in Active
Markets
     Significant
Other
Observable
Inputs
     Significant
Unobservable
Inputs
     Total Carrying      % of  

In thousands

  

(Level 1)

    

(Level 2)

    

(Level 3)

    

Value

    

Total

 

Cash and cash equivalents

     $ 982         $        $        $ 982         4%   
              

 

 

 

Fixed Income Securities:

                 46%   
              

 

 

 

U.S. treasuries

     2,582                       2,582         10%   

Corporate bonds / Other fixed income securities

     9,232                       9,232         36%   
              

 

 

 

Equity Securities:

                 45%   
              

 

 

 

Large cap value

     1,327                       1,327         5%   

Large cap growth

     1,352                       1,352         5%   

Small cap value

     1,331                       1,331         5%   

Small cap growth

     1,313                       1,313         5%   

Large cap index

     2,384                       2,384         9%   

International blend

     4,206                       4,206         16%   
              

 

 

 

Real Estate:

                 5%   
              

 

 

 

Global REIT

     1,252                       1,252         5%   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets at fair value

     $         25,961         $        $        $         25,961           100%   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Percent of fair value hierarchy

     100%                 -%                 -%         100%      
  

 

 

    

 

 

    

 

 

    

 

 

    

 

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     Other Benefits as of October 31, 2012  
       Quoted Prices
in Active
Markets
     Significant
Other
Observable
Inputs
     Significant
Unobservable
Inputs
     Total
Carrying
     % of  

In thousands

  

(Level 1)

    

(Level 2)

    

(Level 3)

    

Value

    

Total

 

Cash and cash equivalents

     $ 926         $        $        $ 926         4%   
              

 

 

 

Fixed Income Securities:

                 46%   
              

 

 

 

U.S. treasuries

     2,345                       2,345         10%   

Corporate bonds / Other fixed income securities

     8,474                       8,474         36%   
              

 

 

 

Equity Securities:

                 45%   
              

 

 

 

Large cap value

     1,221                       1,221         5%   

Large cap growth

     1,149                       1,149         5%   

Small cap value

     1,177                       1,177         5%   

Small cap growth

     1,155                       1,155         5%   

Large cap index

     2,148                       2,148         9%   

International blend

     3,907                       3,907         16%   
              

 

 

 

Real Estate:

                 5%   
              

 

 

 

Global REIT

     1,161                       1,161         5%   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets at fair value

     $     23,663         $       -         $        $       23,663             100%   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Percent of fair value hierarchy

     100%         -%         -%         100%      
  

 

 

    

 

 

    

 

 

    

 

 

    

401(k) Plan

We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.

Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2013, 2012 and 2011, we made matching contributions to participant accounts as follows.

 

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In thousands

  

2013

    

2012

    

2011

 

401(k) matching contributions

   $     5,688      $     5,400      $     5,203  

As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statement of Stockholders’ Equity as an increase in retained earnings.

10. Employee Share-Based Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2013, 2012 and 2011, we recorded compensation expense, and as of October 31, 2013 and 2012, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

We have granted three series of awards under approved incentive compensation plans, each with a three-year performance period (ending October 31, 2013, October 31, 2014 and October 31, 2015). For each of these performance periods, awards will be based on achievement relative to a target annual compounded increase in basic EPS and the achievement of total shareholder returns relative to a group of peer 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, with each measure being weighted at 50%. The plan with the performance period ending October 31, 2015 (2015 plan) has an additional performance measure of actual average return on equity compared to the weighted average return on equity allowed by our regulatory commissions. The weighting of the units awarded under the 2015 plan is based on EPS at 37.5%, total shareholder return at 37.5 % and return on equity at 25% of the total units awarded.

In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award will vest for participants who have met the retention requirements at the end of a three-year period ending in December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2013, 2012 and 2011, we recorded compensation expense, and as of October 31, 2013 and 2012, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

 

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Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vest on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2013 and 2012, we recorded compensation expense, and as of October 31, 2013 and 2012, we accrued a liability for this award based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in the Consolidated Statements of Stockholders’ Equity.

The compensation expense related to the incentive compensation plans for the years ended October 31, 2013, 2012 and 2011, and the amounts recorded as liabilities as of October 31, 2013 and 2012 are presented below.

 

In thousands    2013      2012      2011  

Compensation expense

   $ 4,526      $ 5,730      $     2,604  

Tax benefit

     1,538        2,080        673  

Liability

         11,098            10,631     

Based on current accrual assumptions as of October 31, 2013, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.

 

In thousands    2014      2015      2016      2017  

Amount of payout

   $     4,071      $     4,290      $     2,290      $     446  

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

 

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11. Income Taxes

The components of income tax expense for the years ended October 31, 2013, 2012 and 2011 are presented below.

 

      2013     2012     2011  

In thousands

  Federal     State     Federal     State     Federal     State  

Charged (Credited) to operating income:

           

Current

    $ (3,032)        $ 919        $ (29,062)        $ 1,857        $ (11,403)        $ 4,209   

Deferred

    67,885        11,829        86,496        10,144        64,806        6,597   

Tax Credits:

           

Utilization

                            184         

Amortization

    (267)              (334)              (325)         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    64,586        12,748        57,100        12,001        53,262        10,806   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Charged (Credited) to other income (expense):

           

Current

    6,049        984        5,636        1,027        3,263        (36)   

Deferred

    2,225        (646)        2,214        239        4,167        824   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    8,274        338        7,850        1,266        7,430        788   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    $     72,860        $     13,086      $     64,950        $     13,267        $     60,692        $     11,594   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

   

2012

   

2011

 

Federal taxes at 35%

     $     77,127       $     69,322       $     65,049  

State income taxes, net of federal benefit

     8,506       8,624       7,536  

Amortization of investment tax credits

     (267     (334     (325

Other, net

     580       605       26  
  

 

 

   

 

 

   

 

 

 

Total

     $ 85,946       $ 78,217       $ 72,286  
  

 

 

   

 

 

   

 

 

 

As of October 31, 2013 and 2012, deferred income taxes consisted of the following temporary differences.

 

In thousands

  

2013

    

2012

 

Deferred tax assets:

     

Benefit of loss carryforwards

   $ 66,087       $ 3,092   

Employee benefits and compensation

     13,834         22,286   

Revenue requirement

     19,062         10,148   

Utility plant

     10,386         11,285   

Other

     12,796         9,173   
  

 

 

    

 

 

 

Total deferred tax assets

     122,165         55,984   

Valuation allowance

     (505)         (505)   
  

 

 

    

 

 

 

Total deferred tax assets, net

     121,660         55,479   
  

 

 

    

 

 

 

Deferred tax liabilities:

     

Utility plant

     652,822         523,232   

Revenues and cost of gas

     21,257         26,816   

Equity method investments

     38,710         34,092   

Deferred costs

     59,221         73,744   

Other

     18,324         8,348   
  

 

 

    

 

 

 

Total deferred tax liabilities

     790,334         666,232   
  

 

 

    

 

 

 

Net deferred income tax liabilities

   $ 668,674       $ 610,753   
  

 

 

    

 

 

 

 

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As of October 31, 2013 and 2012, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 2013, we have a federal NOL carryforward of $178.1 million, which expires in 2033. We also have $5.9 million of federal NOL carryforwards as of October 31, 2013 and 2012 that expire in 2021 through 2025 and are subject to an annual limitation of $.3 million.

As of October 31, 2013 and 2012, we have state NOL carryforwards of $6.4 million and $6.8 million, respectively, that expire from 2020 through 2028. We may use the carryforwards to offset taxable income.

We have federal charitable contribution carryforwards as of October 31, 2013 and 2012 of $4.2 million and $2.3 million, respectively, that expire from 2016 through 2018.

We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2009, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2009.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

Balance at beginning of year

     $       505         $       505         $       1,324   

Credited to income tax expense

                   (819)   
  

 

 

    

 

 

    

 

 

 

Balance at end of year

     $ 505         $ 505         $ 505   
  

 

 

    

 

 

    

 

 

 

There were no unrecognized tax benefits for the years ended October 31, 2013 and 2012.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduces the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provides for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax balances at October 31, 2013 by approximately $25 million for temporary differences expected to reverse at a lower rate than under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our non-utility activities segment, with the balance of approximately $24 million recorded in deferred income taxes in “Regulatory Liabilities” in Note 1 to the consolidated financial statements, reflecting a future benefit to our customers; our state commissions will determine the recovery period of this regulatory liability in future proceedings.

12. Equity Method Investments

The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility

 

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activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

As of October 31, 2013, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

Cardinal Pipeline Company, L.L.C.

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.

To provide natural gas delivery service to Duke Energy Progress, Inc. (DEP), now a subsidiary of DEC, for a power generation facility at their Wayne County, North Carolina site, we executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement on Cardinal to serve DEP. Cardinal invested in a compressor station and expanded meter stations in order to increase the capacity of its system for us and another customer. We made capital contributions totaling $9.8 million related to this system expansion from January 2011 through June 2012. Cardinal’s expansion service for the project and our natural gas delivery service for DEP’s Wayne County site were placed into service on June 1, 2012.

The charges we incur as transportation costs from Cardinal are passed through to DEP under the terms of our natural gas delivery service agreement with DEP. Cardinal issued $45 million of long-term debt on June 22, 2012, and we received a distribution of $5.4 million in June 2012 as a partial return of our capital contributions.

Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2013, 2012 and 2011, these transportation costs and the amounts we owed Cardinal as of October 31, 2013 and 2012 are as follows.

 

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In thousands

  

2013

    

2012

    

2011

 

Transportation costs

   $         8,775      $         6,613      $         4,104  

Trade accounts payable

     755        855     

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2013 and 2012, and for the twelve months ended September 30, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

Current assets

   $ 15,179      $ 9,179     

Noncurrent assets

         116,414            120,437     

Current liabilities

     2,637        1,786     

Noncurrent liabilities

     45,273        45,702     

Revenues

     17,649        16,165      $     13,633  

Gross profit

     17,649        16,165        13,633  

Income before income taxes

     9,361        10,433        6,473  

Pine Needle LNG Company, L.L.C.

Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company, owns an interstate LNG storage facility in North Carolina and is regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. In June 2013, we entered into an agreement with Hess Corporation (Hess) to acquire their 5% membership interest in Pine Needle. Effective July 1, 2013, we acquired Hess’ 5% membership interest for $2.9 million. With the purchase of this additional 5% membership interest, our membership interest in Pine Needle increased from 40% to 45%. As of October 31, 2013, the other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc. and SCANA Corporation.

Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.

We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2013, 2012 and 2011, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2013 and 2012 are as follows.

 

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In thousands

  

2013

    

2012

    

2011

 

Gas storage costs

   $         11,098      $         10,410      $         10,677  

Trade accounts payable

     940        914     

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2013 and 2012, and for the twelve months ended September 30, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

Current assets

   $ 9,225      $ 11,937     

Noncurrent assets

           74,710              77,463     

Current liabilities

     3,531        4,278     

Noncurrent liabilities

     35,391        35,851     

Revenues

     16,810        16,390      $       17,666  

Gross profit

     16,810        16,390        17,666  

Income before income taxes

     5,804        5,832        5,763  

SouthStar Energy Services LLC

We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL). SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States, including Illinois, Ohio, New York, Maryland, North Carolina, South Carolina and Tennessee, with most of its business being conducted in the unregulated retail gas market in Georgia. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.

SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.

These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Our share of movements in the

 

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market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2013, 2012 and 2011, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2013 and 2012 are as follows.

 

In thousands

  

2013

    

2012

    

2011

 

Operating revenues

   $     3,291      $     2,442      $     4,961  

Trade accounts receivable

     441        473     

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2013 and 2012, and for the twelve months ended September 30, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

Current assets

   $ 194,793      $ 152,422     

Noncurrent assets

     136,753        9,803     

Current liabilities

     76,304        42,197     

Noncurrent liabilities

     53        1     

Revenues

           639,426              585,291      $       733,987  

Gross profit

     174,993        161,122        176,010  

Income before income taxes

     103,146        94,631        103,704  

Hardy Storage Company, LLC

We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.

We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2013, 2012 and 2011, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2013 and 2012 are as follows.

 

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In thousands

  

2013

    

2012

    

2011

 

Gas storage costs

   $     9,702      $     9,702      $     9,702  

Trade accounts payable

     808        808     

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2013 and 2012, and for the twelve months ended October 31, 2013, 2012 and 2011 is presented below.

 

In thousands

  

2013

    

2012

    

2011

 

Current assets

   $ 7,641      $ 10,302     

Noncurrent assets

         161,282            164,374     

Current liabilities

     12,378        14,534     

Noncurrent liabilities

     87,184        95,061     

Revenues

     24,375        24,359      $       24,378  

Gross profit

     24,375        24,359        24,378  

Income before income taxes

     10,582        9,939        9,657  

Constitution Pipeline Company, LLC

We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. In May 2013, through one of its subsidiaries, WGL Holdings, Inc. became a member of the joint venture along with existing members The Williams Companies, Inc. and Cabot Oil & Gas Corporation. A subsidiary of The Williams Companies is the operator of the project. 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. As of October 31, 2013, our fiscal year contributions 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. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2013, and for the twelve months ended September 30, 2013 is presented below.

 

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In thousands    2013       

(1)

 

Current assets

   $   10,944  

Noncurrent assets

   62,438  

Current liabilities

   7,960  

Noncurrent liabilities

   -  

Revenues

   -  

Gross profit

   -  

Income before income taxes

   3,459  

 

(1)  

Presented is the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012.

13. Variable Interest Entities

Under accounting guidance, a variable interest entity (VIE) is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As of October 31, 2013, we have determined that we are not the primary beneficiary, as defined by the authoritative guidance related to consolidations, in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2013 and 2012, our investment balances are as follows.

 

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     October 31,      October 31,  

In thousands

   2013      2012  

Cardinal

   $ 18,207       $ 17,969   

Pine Needle

     20,270         19,239   

SouthStar

     38,372         18,118   

Hardy Storage

     34,681         32,541   

Constitution

     16,939           
  

 

 

    

 

 

 

Total equity method investments in non-utility activities

   $     128,469       $     87,867   
  

 

 

    

 

 

 

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

14. Business Segments

We have two reportable business segments, regulated utility and non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home warranty programs, with activities conducted by the parent company. 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.

Operations of the regulated utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. 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.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

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

 

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Operations by segment for the years ended October 31, 2013, 2012 and 2011, and as of October 31, 2013, 2012 and 2011 are presented below.

 

       Regulated      Non-Utility        

In thousands

  

Utility

     Activities    

Total

 

2013

       

Revenues from external customers

   $     1,278,229      $ -     $     1,278,229  

Margin

     621,490        -        621,490  

Operations and maintenance expenses

     253,120        181       253,301  

Depreciation

     112,207        18       112,225  

Income from equity method investments

     -         26,056       26,056  

Interest expense

     24,938        -        24,938  

Operating income (loss) before income taxes

     221,528        (352     221,176  

Income before income taxes

     194,659        25,704       220,363  

Total assets

     4,053,591          128,832       4,182,423  

Equity method investments in non-utility activities

     -         128,469       128,469  

Construction expenditures

     599,999        -        599,999  
       Regulated      Non-Utility        

In thousands

  

Utility

    

Activities

   

Total

 

2012

       

Revenues from external customers

   $ 1,122,780      $ -     $ 1,122,780  

Margin

     575,446        -        575,446  

Operations and maintenance expenses

     242,599        102       242,701  

Depreciation

     103,192        18       103,210  

Income from equity method investments

     -         23,904       23,904  

Interest expense

     20,097        -        20,097  

Operating income (loss) before income taxes

     194,824        (264     194,560  

Income before income taxes

     174,424        23,640       198,064  

Total assets

     3,475,640        88,247       3,563,887  

Equity method investments in non-utility activities

     -         87,867       87,867  

Construction expenditures

     529,576        -        529,576  
       Regulated      Non-Utility        

In thousands

  

Utility

    

Activities

   

Total

 

2011

       

Revenues from external customers

   $ 1,433,905      $ -     $ 1,433,905  

Margin

     573,639        -        573,639  

Operations and maintenance expenses

     225,351        109       225,460  

Depreciation

     102,829        28       102,857  

Income from equity method investments

     -         24,027       24,027  

Interest expense

     43,992        -        43,992  

Operating income (loss) before income taxes

     207,079        (120     206,959  

Income before income taxes

     161,925        23,929       185,854  

Total assets

     2,968,574        85,519       3,054,093  

Equity method investments in non-utility activities

     -         85,121       85,121  

Construction expenditures

     243,641        -        243,641  

Reconciliations to the consolidated financial statements for the years ended October 31, 2013, 2012 and 2011, and as of October 31, 2013 and 2012 are as follows.

 

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In thousands

  

2013

    

2012

    

2011

 

Operating Income:

        

Segment operating income before income taxes

     $ 221,176         $ 194,560         $ 206,959   

Utility income taxes

     (77,334)         (69,101)         (64,068)   

Non-utility activities operating loss before income taxes

     352         264         120   
  

 

 

    

 

 

    

 

 

 

Total

     $ 144,194         $ 125,723         $ 143,011   
  

 

 

    

 

 

    

 

 

 

Net Income:

        

Income before income taxes for reportable segments

     $ 220,363         $ 198,064         $ 185,854   

Income taxes

     (85,946)         (78,217)         (72,286)   
  

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

 

In thousands

  

2013

    

2012

        
        

Consolidated Assets:

        

Total assets for reportable segments

     $   4,182,423         $   3,563,887      

Eliminations/Adjustments

     186,186         206,052      
  

 

 

    

 

 

    

Total

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

 

 

    

 

 

    

15. Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters, stockholders’ equity and environmental matters, see Note 2, Note 6 and Note 8, respectively, to the consolidated financial statements.

16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)

 

       Operating             Operating
Income
   

Net

Income

   

Earnings (Loss)

Per Share of

Common Stock

 
      

Revenues

    

Margin

    

(Loss)

   

(Loss)

   

Basic

   

Diluted

 

Fiscal Year 2013

              

January 31

   $     515,875      $     231,623      $       86,213     $       85,923     $           1.19     $           1.18  

April 30

     399,411        183,856        51,504       55,790       0.74       0.74  

July 31

     162,943        97,000        591       (2,293     (0.03 )     (0.03 )

October 31

     200,000        109,011        5,886       (5,003     (0.07 )     (0.07 )

Fiscal Year 2012

              

January 31

   $ 471,840      $ 220,237      $ 79,819     $ 76,227     $ 1.06     $ 1.05  

April 30

     308,432        171,951        48,782       50,192       0.70       0.70  

July 31

     161,123        86,460        (2,513     (4,613     (0.06 )     (0.06 )

October 31

     181,385        96,798        (365     (1,959     (0.03 )     (0.03 )

 

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The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

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

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the fourth quarter of fiscal 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

December 23, 2013

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined in Rules 13a-15(f) under the Securities Exchange Act of 1934 is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written Code of Ethics and Business Conduct adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.

Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.

We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control—Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, 2013, our internal control over financial reporting was effective.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of October 31, 2013.

 

Piedmont Natural Gas Company, Inc.
  /s/ Thomas E. Skains
 

Thomas E. Skains

Chairman, President and Chief Executive Officer

  /s/ Karl W. Newlin
 

Karl W. Newlin

Senior Vice President and Chief Financial Officer

  /s/ Jose M. Simon
 

Jose M. Simon

Vice President and Controller

 

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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 internal control over financial reporting of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) 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. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992)  issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended October 31, 2013 of the Company and our report dated December 23, 2013 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, 2013

 

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Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information concerning our executive officers and directors is set forth in the sections entitled “Board of Directors” and “Executive Officers” in our Proxy Statement for the 2014 Annual Meeting of Shareholders (2014 Proxy Statement), which sections are incorporated in this annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our 2014 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning our Audit Committee and our Audit Committee financial experts is set forth in the section entitled “Committees of the Board” in our 2014 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

We have adopted a Code of Ethics and Business Conduct that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, which serves as the code of ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions under Item 406(b) of Regulation S-K. The Code of Ethics and Business Conduct is available on the “For Investors-Corporate Governance” section of our website at www.piedmontng.com . If we amend or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct that apply to the principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) of Regulation S-K, we will disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.

Item 11. Executive Compensation

Information for this item is set forth in the sections entitled “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our 2014 Proxy Statement, which sections are incorporated in this annual report on Form 10-K by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information for this item is set forth in the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our 2014 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

 

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Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our 2014 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information for this item is set forth in the section entitled “Director Independence and Related Person Transactions” in our 2014 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Item 14. Principal Accounting Fees and Services

Information for this item is set forth in “Proposal 2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year 2014” in our 2014 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

 

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PART IV

Item 15. Exhibits, Financial Statement Schedules

 

(a)

   1.      Financial Statements

The following consolidated financial statements for the year ended October 31, 2013, are included in Item 8 of this report as follows:

Consolidated Balance Sheets – October 31, 2013 and 2012

Consolidated Statements of Comprehensive Income – Years Ended
October 31, 2013, 2012 and 2011

Consolidated Statements of Cash Flows – Years Ended
October 31, 2013, 2012 and 2011

Consolidated Statements of Stockholders’ Equity – Years Ended
October 31, 2013, 2012 and 2011

Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

(a)

   2.      Supplemental Consolidated Financial Statement Schedules

None

 

Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

(a)

   3.      Exhibits
        Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
        The exhibits numbered 10.1 through 10.20 are management contracts or compensatory plans or arrangements.
   3.1      Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009 (incorporated by reference to Exhibit 3.1, Form 10-Q for the quarter ended July 31, 2009).
   3.2      Bylaws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (incorporated by reference to Exhibit 3.1, Form 8-K dated September 13, 2011).
   4.1      Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).

 

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   4.2      Amendment to September 1992 Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007).
   4.3      Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (incorporated by reference to Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).
   4.4      Medium-Term Note, Series A, dated as of October 6, 1993 (incorporated by reference to Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
   4.5      First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.2, Form S-3 Registration Statement No. 33-59369).
   4.6      Medium-Term Note, Series A, dated as of September 19, 1994 (incorporated by reference to Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
   4.7      Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 33-59369).
   4.8      Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (incorporated by reference to Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).
   4.9      Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (incorporated by reference to Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).
   4.10      Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).
   4.11      Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (incorporated by reference to Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).
   4.12      Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.3, Form S-3 Registration Statement No. 333-106268).
   4.13      Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.1, Form 8-K, dated December 23, 2003).

 

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   4.14      Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.2, Form 8-K, dated December 23, 2003).
   4.15      Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (incorporated by reference to Exhibit 4.1, Form 8-K dated June 20, 2006).
   4.16      Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007).
   4.17      Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10, Form 8-K, dated May 12, 2011).
   4.18      Form of 2.92% Series A Senior Notes due June 6, 2016 (incorporated by reference to Exhibit 4.1, Form 8-K dated May 12, 2011).
   4.19      Form of 4.24% Series B Senior Notes due June 6, 2021 (incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011).
   4.20      Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386).
   4.21      Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011).
   4.22      Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1, Form 8-K dated March 29, 2012).
   4.23      Form of 3.47% Series A Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.1, Form 8-K dated March 29, 2012).
   4.24      Form of 3.57% Series B Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.2, Form 8-K dated March 29, 2012).

 

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   4.25      Corporate Commercial Paper Master Note dated March 1, 2012 between U.S. Bank National Association as Paying Agent and Piedmont Natural Gas Company, Inc. as Issuer (incorporated by reference to Exhibit 4.1, Form 10-Q for the quarter ended April 30, 2012).
   4.26      Fifth Supplemental Indenture, dated August 1, 2013, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated August 1, 2013)
   4.27      Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013).
        Compensatory Contracts:
   10.1      Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (incorporated by reference to Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999).
   10.2      Severance Agreement with Thomas E. Skains, dated September 4, 2007 (substantially identical agreements have been entered into as of the same date with Franklin H. Yoho, Kevin M. O’Hara and Jane R. Lewis-Raymond) (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007).
   10.3      Schedule of Severance Agreements with Executives (incorporated by reference to Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007).
   10.4      Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (incorporated by reference to Appendix A, Form DEF14A dated January 14, 2011).
   10.5      Form of Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011).
   10.6      Resolution of Board of Directors, June 7, 2013, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2013).
   10.7      Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009).

 

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   10.8      Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2009).
   10.9      Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (incorporated by reference to Exhibit 4.1, Form 8-K dated April 3, 2009).
   10.10      Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2009).
   10.11      Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010).
   10.12      Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011 (incorporated by reference to Exhibit 10.19, Form 10-K for the fiscal year ended October 31, 2011).
   10.13      Form of 2013 Retention Award Agreement, dated as of December 15, 2010 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2011).
   10.14      Instrument of Amendment for Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan dated as of January 23, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2012).
   10.15      2011 Retention Award Agreement dated December 15, 2011 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2012).
   10.16      Employment Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2012).
   10.17      Severance Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2012).

 

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   10.18      Amended and Restated Employment Agreement dated May 25, 2012 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho) (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2012).
   10.19      Schedule of Amended and Restated Employment Agreements with Executives (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2012).
   10.20      Amendment to the Piedmont Natural Gas Company Employee Stock Purchase Plan dated September 18, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.21, Form 10-K for the fiscal year ended October 31, 2012).
        Other Contracts:
   10.21      Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004).
   10.22      First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2006).
   10.23      Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006).
   10.24      Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 2006).
   10.25      Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company (incorporated by reference to Exhibit 10.1, Form 8-K dated November 16, 2004).

 

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   10.26      Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (incorporated by reference to Exhibit 10.3, Form 8-K dated November 16, 2004).
   10.27      Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009).
   10.28      Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.1, Form 8-K dated August 4, 2009).
   10.29      Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.2, Form 8-K dated August 4, 2009).
   10.30      Form of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and Dealers party thereto (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2012).
   10.31      Amended and Restated Credit Agreement dated as of October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender. (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2012).
   10.32      Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC dated April 9, 2012, by and among Williams Partners Operating LLC and Cabot Pipeline Holdings LLC (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2013).
   10.33      First Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of November 9, 2012, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, and Piedmont Constitution Pipeline Company, LLC (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2013).

 

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   10.34      Confirmation of Forward Sale Transaction dated January 29, 2013, between the Company and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 4, 2013).
   10.35      Underwriting Agreement dated January 29, 2013, among Piedmont Natural Gas Company, Inc., Morgan Stanley & Co. LLC, J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, individually and acting as representatives of each of the other underwriters named in Schedule II thereto, and Morgan Stanley & Co. LLC, as forward counterparty (incorporated by reference to Exhibit 1.1, Form 8-K filed February 4, 2013).
   10.36      Confirmation of Forward Sale Transaction dated February 19, 2013, between Piedmont Natural Gas Company, Inc., and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 25, 2013).
   10.37      Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1, Form 8-K filed September 4, 2013).
   10.38      Underwriting Agreement dated July 29, 2013, among the Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated, U.S. Bancorp Investments, Inc., individually and acting as representatives of each of the other underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1, Form 8-K filed August 1, 2013).
   10.39      Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company
   12      Computation of Ratio of Earnings to Fixed Charges.
   21      List of Subsidiaries.
   23.1      Consent of Independent Registered Public Accounting Firm.
   31.1      Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
   31.2      Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

 

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   32.1      Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
   32.2      Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.
   101.INS      XBRL Instance Document
   101.SCH      XBRL Taxonomy Extension Schema
   101.CAL      XBRL Taxonomy Calculation Linkbase
   101.DEF      XBRL Taxonomy Definition Linkbase
   101.LAB      XBRL Taxonomy Extension Label Linkbase
   101.PRE      XBRL Taxonomy Extension Presentation Linkbase

Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2013 and 2012; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2013, 2012 and 2011; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2013, 2012 and 2011; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2013, 2012 and 2011; and Notes to Consolidated Financial Statements.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Piedmont Natural Gas Company, Inc.
  (Registrant)
By:   /s/ Thomas E. Skains
  Thomas E. Skains
  Chairman of the Board, President
  and Chief Executive Officer
Date:   December 23, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

         Signature                    Title
/s/ Thomas E. Skains     Chairman of the Board, President and
Thomas E. Skains   Chief Executive Officer
  (Principal Executive Officer)
Date: December 23, 2013  
/s/ Karl W. Newlin       Senior Vice President and
Karl W. Newlin   Chief Financial Officer
  (Principal Financial Officer)
Date: December 23, 2013  
/s/ Jose M. Simon       Vice President and Controller
Jose M. Simon   (Principal Accounting Officer)
Date: December 23, 2013  

 

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       Signature      Title

/s/ E. James Burton

     Director
E. James Burton     

/s/ Malcolm E. Everett III

     Director
Malcolm E. Everett III     

/s/ John W. Harris

     Director
John W. Harris     

/s/ Aubrey B. Harwell, Jr.

     Director
Aubrey B. Harwell, Jr.     

/s/ Frank B. Holding, Jr.

     Director
Frank B. Holding, Jr.     

/s/ Frankie T. Jones, Sr.

     Director
Frankie T. Jones, Sr.     

/s/ Vicki McElreath

     Director
Vicki McElreath     

/s/ Minor M. Shaw

     Director
Minor M. Shaw     

/s/ Muriel W. Sheubrooks

     Director
Muriel W. Sheubrooks     

/s/ David E. Shi

     Director
David E. Shi     

/s/ Phillip D. Wright

     Director
Phillip D. Wright     

 

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Piedmont Natural Gas Company, Inc.

Form 10-K

For the Fiscal Year Ended October 31, 2013

Exhibits

 

10.39    Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company
12    Computation of Ratio of Earnings to Fixed Charges
21    List of Subsidiaries
23.1    Consent of Independent Registered Public Accounting Firm
31.1    Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2    Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer

Exhibit 10.39

 

 

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

SOUTHSTAR ENERGY SERVICES LLC

(A Delaware Limited Liability Company)

(Member Managed)


SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

SOUTHSTAR ENERGY SERVICES LLC

This Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, a limited liability company organized pursuant to the Delaware Limited Liability Company Act (the “ Company ”), is entered into as of September 1, 2013 (the “ Effective Date ”), by and between Georgia Natural Gas Company, a Georgia corporation (“ GNGC ”), and Piedmont Energy Company, a North Carolina corporation (“ Piedmont ”) (referred to jointly herein as “ Current Members ”).

WITNESSETH

WHEREAS, the Current Members had previously entered into and amended an amended and restated limited liability company agreement relating to the formation and operation of the Company, which agreement and related Operating Policy and all schedules, exhibits and amendments thereto, the Current Members intend to be superceded by and terminated pursuant to the terms hereof;

WHEREAS, GNGC and Piedmont desire to maintain the Company as a limited liability company pursuant to the Delaware Limited Liability Company Act, for the purpose of selling on a non-regulated basis natural gas to target retail customers, providing non-regulated products and services related to such sales, and engaging in all other activities permitted by law and agreed to by the Members pursuant to the terms of this Company Agreement;

NOW THEREFORE, in consideration of the mutual agreements, promises and undertakings hereinafter set forth, the Members agree as follows:

ARTICLE I

Definitions

The following terms, as used herein, shall have the following meanings:

Acquisition shall have the meaning set forth in Section 7.1(d) .

Act means the Delaware Limited Liability Company Act and all amendments to the Act, as in effect from time to time.

Additional Member means a Person other than a Current Member who has acquired a Company Interest from the Company or from another Member in accordance with Article XII of this Company Agreement pursuant to an Admission Agreement.

 

[Signature Page to Second Amended and Restated Limited Liability Company Agreement]


Admission Agreement means the agreement between an Additional Member and the Company described in Section 9.1(b) substantially in the form set forth as Exhibit E.

Affected Member shall have the meaning set forth in Section 12.5(a) .

Affiliate means, with respect to any Person, any entity that a Person directly or indirectly, including through subsidiaries or intermediaries, Controls, is Controlled by, or is under common Control with such Person; including, in the case of a Member, such Person’s parent, and each entity that is Controlled by such Member’s parent.

AGLR means AGL Resources Inc., a Georgia corporation.

Allocable Share means, as to any Member, the percentage by which such Member shall share in the distribution of any Company Income, which percentage may change in proportion to which a change in the Member’s Capital Account may bear to the concurrent change in the Capital Account of the other Member(s). As of the date hereof, each Member’s Allocable Share is listed on Exhibit D .

Appraiser shall have the meaning set forth in Section 12.4(b) .

Assessment Notice shall have the meaning set forth in Section 7.1(d) .

Assumed Payment Date shall have the meaning set forth in Section 16.1(b) .

Auction shall have the meaning set forth in Section 13.2(c) .

Auction Procedures shall have the meaning set forth in Section 13.2(c) .

Auctioneer shall have the meaning set forth in Section 13.2(c) .

Bankruptcy means, with respect to a Person: (i) the commencement against such Person of proceedings for any relief under any bankruptcy or insolvency law, or any law relating to the relief of debtors, readjustment of indebtedness, reorganization, arrangement, composition, or extension of debts, provided such proceeding shall not have been dismissed, nullified, stayed, or otherwise rendered ineffective (but only so long as such ineffectiveness shall continue in force) within ninety (90) days after the commencement of such proceedings; (ii) the commencement by such Person of proceedings for any relief under any bankruptcy or insolvency law, or any law relating to the relief of debtors, readjustment of indebtedness, reorganization, arrangement, composition, or extension of debts; (iii) a decree or order of a court having jurisdiction in the premises for the appointment of a receiver, liquidator, or trustee or assignee in bankruptcy or insolvency of such Person or of a substantial part of such Person’s property, or for the winding up or liquidation of its affairs, which decree or order remains in force undischarged and unstayed for a period of ninety (90) days; or (iv) a general assignment by such Person for the benefit of creditors or the admission by such Person in writing of its inability to pay its debts generally as they become due.

 

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Business Plan means the plan by which the Members agree to conduct the business of the Company, which plan may be adopted and amended by the Members from time to time pursuant to Section 8.1(a)(2) .

C&I Customer means a non-residential customer of natural gas that, per applicable utility tariffs, may obtain natural gas supplies other than from a utility by using such customer’s own or a third party’s transportation options.

C&I Option Notice shall have the meaning set forth in Section 7.4(d) .

Capital Account means the account maintained for a Member determined in accordance with Section 9.4 .

Capital Contribution means the value of Property contributed, from time to time, to the Company by any one Member, or provided that such value, in the case of Property other than cash, shall be the fair market value of such Property as reasonably determined by the Member contributing such Property and approved by Unanimous Vote of the Executive Committee or by the Dispute Resolution Procedures provided in Article XVI hereof.

Certificate of Formation means the certificate of formation of the Company as filed with the Delaware Secretary of State’s Office.

Change in Control means: (a) with respect to Piedmont, the acquisition by any single Person or group of Affiliates, of Control of PNG; or (b) with respect to GNGC, the acquisition by any single Person or group of Affiliates, of Control of AGLR.

CNG shall have the meaning set forth in Section 7.1(b) .

Code means the Internal Revenue Code of 1986, as amended from time to time, or any successor thereto; any reference to a section of the Code or the Regulations shall mean such section or any successor thereto as in effect at the time or times in question.

Company shall have the meaning set forth in the preamble.

Company Agreement means this Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, including all amendments adopted in accordance with this Company Agreement and the Act and together with all Exhibits and Schedules hereto.

Company Income means profit and loss of the Company for any Fiscal Year as determined in accordance with generally accepted accounting principles consistently applied.

Company Interest means as to any Member, the percentage by which such Member shall share in distributions of the Company’s assets upon any liquidation of the Company’s Property, which percentage may change in proportion to the amount by which such Member’s Capital Account then bears to the total of the Capital Accounts of all Members. The Company Interests of each of the Members as of the date hereof is set forth on Exhibit D .

 

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Company Property means all Property owned of record or beneficially by the Company.

Company Sale shall have the meaning set forth in Section 13.2(b) .

Compensation shall have the meaning set forth in Section 10.3(b) .

Competing Assets shall have the meaning set forth in Section 7.1(d) .

Confidential Information shall have the meaning set forth in Section 15.9 .

Control means the possession, directly or indirectly, through one or more intermediaries, of (i) in the case of a corporation, more than fifty percent (50%) of the outstanding voting securities of the corporation; (ii) in the case of a limited liability company, partnership, limited partnership or venture, the right to more than fifty percent (50%) of the distributions from such entity (including liquidating distributions); and (iii) in the case of any other entity, more than fifty percent (50%) of the economic or beneficial interest in such entity.

Current Members shall have the meaning set forth in the preamble.

Delinquent Member shall have the meaning set forth in Section 9.3 .

Disposition (Dispose) means any sale, assignment, transfer, exchange, mortgage, pledge, grant, hypothecation, or other transfer, absolute or as security or encumbrance (including dispositions by operation of law).

Dispute shall have the meaning set forth in Section 16.1(a) .

Dispute Appraiser shall have the meaning set forth in Section 16.2 .

Dispute Resolution Procedures shall have the meaning set forth in Section 16.1(a) .

Disputed Asset shall have the meaning set forth in Section 16.1(a) .

Dissolution Event shall have the meaning set forth in Section 13.1 .

Effective Date shall have the meaning set forth in the recitals .

Executive Committee shall have the meaning set forth in Section 8.1(a) .

Executive Committee Representative or Representative shall have the meaning set forth in Section 8.2(a) .

Expiration Date shall have the meaning set forth in Section 7.4(a) .

 

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Fair Market Amount shall have the meaning set forth in Section 16.1(b) .

Fiscal Year shall have the meaning set forth in Section 4.4 .

Grandfathered Assets shall have the meaning set forth in Section 7.1(c) .

GNGC shall have the meaning set forth in the preamble.

Liquidating Trustee means the Member or such other Person as all Members agree (or, in the absence of such agreement, the Executive Committee), charged with carrying out the winding up of the Company.

LNG shall have the meaning set forth in Section 7.1(b) .

Matching Contribution shall have the meaning set forth in Section 7.1(d) .

Majority Vote means approval by greater than fifty percent (50%) of the votes cast by the voting Representatives on the Executive Committee, subject to the provisions of Sections 8.2 and 8.6 hereof.

Market Value means, with respect to a Company Interest of a Member: (i) the Company’s value as an on-going enterprise as determined by a discounted cash flow analysis (or as otherwise agreed by the Members in writing) multiplied by (ii) the percentage of the respective Member’s Company Interest as of the date of such Disposition or any other applicable date indicated by this Company Agreement.

Member means any Current Member or any Additional Member.

Negotiated Dissolution shall have the meaning set forth in Section 13.2(b) .

Net Taxable Income and Net Tax Losses mean the Company’s taxable income or loss determined in accordance with Code Section 703(a) for each of its Fiscal Years (for this purpose, all items of income, gain, loss or deduction required to be stated separately pursuant to Code Section 703(a)(l) will be included in taxable income or loss) with the following adjustments: (i) such Net Taxable Income and Net Tax Losses will be computed as if items of tax-exempt income and nondeductible, non-capital expenditures (under Code Section 705(a)(l)(B) and 705(a)(2)(B)) were included in the computation of taxable income or loss; (ii) that any items specially allocated pursuant to Article VI hereof shall not be taken into account in computing Net Taxable Income or Net Tax Losses; (iii) if any Member contributes Property to the Company with an initial book value to the Company different from its adjusted basis for federal income tax purposes to the Company, or if Company Property is revalued in accordance with Treasury Regulations Section 1.704-1 (b)(2)(iv)(f) or as otherwise required by the Regulations, Net Taxable Income and Net Tax Losses will be computed as if the initial adjusted basis for federal income tax purposes to the Company of such contributed or revalued Property equaled its initial book value to the Company as of the date of contribution or revaluation; and (iv) credits or debits to Capital Accounts due to

 

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a revaluation of Company assets in accordance with Treasury Regulations Section 1 .704-l(b)(2)(iv)(f), or due to a distribution of non-cash assets, will be taken into account as gain or loss from the disposition of such assets for purposes of computing Net Taxable Income and Net Tax Losses.

NGV shall have the meaning set forth in Section 7.1(b) .

Non-Affected Member shall have the meaning set forth in Section 12.5(a) .

Non-Competing Customer shall have the meaning set forth in Section 7.1(b) .

Officer shall have the meaning set forth in Section 8.9(a) .

Operating Budget shall have the meaning set forth in Section 8.l (a)(7) .

Operating Policy means that policy attached hereto as Exhibit F and adopted hereby, as may be amended by the Members from time to time.

Option Business shall have the meaning set forth in Section 7.4(a) .

Option Closing shall have the meaning set forth in Section 7.4(a) .

Option Notice shall have the meaning set forth in Section 12.5(b) .

Option Purchase Price shall have the meaning set forth in Section 7.4(b) .

Original Purchaser shall have the meaning set forth in Section 12.4 .

Person means an individual, trust, governmental authority, estate, or any incorporated or unincorporated company, corporation, limited liability company, joint venture, partnership or other organization.

Piedmont shall have the meaning set forth in the preamble.

Piedmont C&I Option shall have the meaning set forth in Section 7.4(a) .

PNG means Piedmont Natural Gas Company, Inc., a North Carolina corporation.

Principal Office shall have the meaning set forth in Section 2.7 .

Proceeding means any administrative or judicial adversary proceeding or hearing, civil, criminal or investigative, the result of which may be that a court, arbitrator, mediator or governmental agency may enter a judgment, order, decree, or other determination which, if not appealed and reversed, would be binding.

Proper Amount shall have the meaning set forth in Section 16.4 .

 

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Property means any property, real or personal, tangible or intangible, including cash, any equity (or debt) interests in other Persons, and any legal or equitable interest in such property.

Quorum shall have the meaning set forth in Section 8.6 .

Regulations means, except where the context indicates otherwise, the permanent and temporary regulations of the United States Department of the Treasury under the Code, including any amendments thereto.

Replacement Purchaser shall have the meaning set forth in Section 12.4(a) .

Representative or Executive Committee Representative shall have the meaning set forth in Section 8.2(a) .

Retail Territory means the states of Georgia, Illinois (but only with respect to non-C&I Customers), North Carolina, South Carolina, and Tennessee or such other area designated by the Executive Committee.

Selling Member shall have the meaning set forth in Section 12.4 .

Services Agreement means that certain agreement between the Company and AGL Services Company, or its successors and assigns, dated the date hereof, a form of which is attached hereto as Exhibit A .

Subsidiaries means Nicor Solutions, L.L.C., a Delaware limited liability company; Prairie Point Energy, L.L.C, a Delaware limited liability company; and such other entities as may become subsidiaries of the Company in accordance with the provisions of this Company Agreement and as approved by a Unanimous Vote.

Target Customer means retail residential, and C&I Customers of natural gas in the Retail Territory.

Taxable Year means the Fiscal Year, unless changed by the Executive Committee.

Tax Advantaged Distribution shall have the meaning set forth in Section 13.2(b) .

Tax Matters Member shall have the meaning set forth in Section 11.3 .

Trade Name shall have the meaning set forth in Section 13.6(a) .

Unanimous Vote means the approval by one hundred percent (100%) of the votes cast by the Representatives on the Executive Committee.

Value Maximization Principle shall have the meaning set forth in Section 13.2(c) .

 

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Withdrawing Member shall have the meaning set forth in Section 12.6.

ARTICLE II

Formation

2.1       Organization .  The Current Members agree to jointly operate a Delaware limited liability company pursuant to the provisions of the Act. The Current Members intend that the Company not be deemed a partnership (including a limited partnership) or joint venture, and that no Member be deemed a partner or joint venturer of any other Member, for any purpose other than federal and state tax purposes, and this Company Agreement may not be construed to suggest otherwise.

2.2       Termination of Prior Agreements .     The Current Members agree that this Company Agreement hereby terminates, supercedes and restates: (a) the prior Amended and Restated Limited Liability Company Agreement of the Company, dated January 1, 2004 as it may have been amended and (b) the Company’s Operating Policy, dated January 1, 2004, as it may have been amended.

2.3       Agreement .  For and in consideration of the mutual covenants herein contained and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Members hereby agree to the terms and conditions of this Company Agreement, as it may from time to time be amended according to its terms. It is the express intention of the Members that this Company Agreement, as it may be amended from time to time in accordance with its terms, except to the extent a provision of this Company Agreement expressly incorporates federal income tax rules by reference to sections of the Code or Regulations or is expressly prohibited or ineffective under the Act, shall govern with respect to the subject matter hereof, even when inconsistent with, or different than, the provisions of the Act or any other law or rule. To the extent any provision of this Company Agreement is prohibited or ineffective under the Act, this Company Agreement shall be considered amended to the smallest degree possible in order to make this Company Agreement effective under the Act. In the event the Act is subsequently amended or interpreted in such a way to make any provision of this Company Agreement that was formerly invalid valid, such provision shall be considered to be valid from the effective date of such interpretation or amendment.

2.4       Name .  The name of the Company is “SouthStar Energy Services LLC”.

2.5        Effective Date .  This Company Agreement shall be deemed effective as of the Effective Date.

2.6       Term .  The Company commenced its existence upon the filing of its Certificate of Formation and shall continue in existence until it is dissolved and terminated by the affirmative action of the Members.

2.7       Registered Agent, Registered Office and Principal Office .  The registered office of the Company required by the Act to be maintained in the State of Delaware shall be the office of the initial registered agent named in the Delaware Certificate or such other office (which need not be a place of business of the Company) as the Executive Committee may designate in the manner provided by Law. The registered agent of the Company in the State of Delaware shall be the initial registered agent named in the Delaware Certificate or such other Person or Persons as

 

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the Executive Committee may designate in the manner provided by Law. The principal office (the “ Principal Office ”) of the Company in the United States shall be at such place as the Executive Committee may designate, which need not be in the State of Delaware, and the Company shall maintain records there or such other place as the Executive Committee shall designate and shall keep the street address of such Principal Office at the registered office of the Company in the State of Delaware. The Company may have such other offices as the Executive Committee may designate.

2.8       Governmental Applications .  The Members agree to cooperate and exercise due diligence in securing any necessary regulatory approvals and such other matters as may be necessary or appropriate for purposes of effectuating the business of the Company. Notwithstanding the foregoing, in the event any Member is a regulated entity, as defined below, or has an Affiliate that is a regulated entity, nothing in this Section 2.8 shall be construed to obligate that Member to seek, or join in, any regulatory approval if that Member reasonably concludes that such action may have a material adverse impact on that Member or any Affiliate, or to accept any issued approval if such issued approval contains conditions not requested by such Member and reasonably unacceptable to such Member. For purposes of this Section 2.8 , a regulated entity is one whose ongoing business is subject to review, approval or oversight by a federal or state regulatory body or agency.

ARTICLE III

Nature of Business

The Company is empowered to, either directly or through its Subsidiaries, (a) engage in the purchase, transportation and sale of natural gas on a non-regulated basis for Target Customers of such products located in the Retail Territory; (b) provide risk management instruments associated with the products and services set forth in subpart (a) of this Article III to Target Customers located in the Retail Territory in accordance with the Operating Policy and this Company Agreement; (c) provide non-regulated products and services related to the efficient use of natural gas to Target Customers located in the Retail Territory; (d) engage in all other activities permitted by law if approved by the Executive Committee; and (e) engage in any and all activities incidental to the foregoing, including the sale of the Company’s under-utilized gas transportation and gas storage assets (and commodities attendant to such assets) pursuant to the risk management guidelines of the Operating Policy, regardless of whether the sale or use of such assets is to the Target Customers or within the Retail Territory; provided however, that the Company must have initially acquired such assets for service to the Target Customers in the Retail Territory. The Company and its Subsidiaries are empowered to take any and all action necessary, appropriate, or convenient for the accomplishment of its purposes, and for the benefit of the Company and its Property, including, but not limited to:

(a) entering into and performing contracts of any kind;

(b) acquiring, selling, conveying, pledging, constructing, operating, maintaining, owning, transferring, renting, or leasing any Property;

(c) applying for and obtaining governmental authorizations and approvals; and

(d) bringing and defending actions at law or equity.

 

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ARTICLE IV

Accounting, Records and Reports

4.1       Records to be Maintained .  The Company shall maintain the following accurate and complete records at the Principal Office or at such other locations as may be provided by the Members:

(a) a current list of the full name and last known business address of each Member;

(b) a copy of the Certificate of Formation and all amendments thereto;

(c) copies of each of the Company’s federal, state and local tax returns and reports, as filed, for the last seven (7) taxable periods;

(d) copies of this Company Agreement, including all amendments thereto;

(e) Company financial statements for the last seven (7) Fiscal Years;

(f) books and records of the Company; and

(g) minutes of the Executive Committee.

4.2       Accounting .  Books and records of the Company shall be maintained on an accrual accounting basis, and the Company’s net profit or net loss shall be determined on the basis of the Fiscal Year and in accordance with generally accepted accounting principles consistently applied.

4.3       Financial Reports .  The Executive Committee shall cause the following financial statements to be prepared, in each case in accordance with generally accepted accounting principles consistently applied on a consolidated basis, and shall cause to be delivered to each Person who was a Member during the applicable period described below:

(a) a balance sheet and statement of income, statement of cash flow and Member’s capital account as of the end of or for, as the case may be, each month, each within thirty (30) days after the end of each month;

(b) (i) a balance sheet as of the end of each fiscal quarter of the Company; (ii) an income statement for such quarters and year-to-date; (iii) a statement of each Member’s Capital Account as of the end of such quarters; and (iv) a statement of cash flows for such quarter and year-to-date (including sufficient information to permit the Members to calculate their tax accruals), each within thirty (30) days after the end of such quarters; and

(c) (i) a balance sheet as of the end of each Fiscal Year of the Company; (ii) an income statement for such fiscal years; (iii) a statement of each Member’s Capital Account as of the end of such fiscal years; (iv) such federal, state and local income tax returns and such other accounting tax information and schedules as shall be necessary for the preparation by each Member of its income tax return for such fiscal years; and (v) a statement of cash flows for such fiscal years, each within ninety (90) days after the end of such fiscal years.

4.4       Fiscal Year .  The fiscal year of the Company (the “ Fiscal Year ”) shall end on December 31 of each calendar year unless otherwise required by the Code.

 

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4.5       Accounts .  The Company shall maintain a record of each Member’s Capital Account in accordance with Section 9.4 .

4.6       Access to Records and Audit Reports .  Each Member or its authorized representative shall have unrestricted, but reasonable, access at the Company’s Principal Office and other appropriate locations, during ordinary business hours, to all properties, books, records, contracts, personnel, vendor agreements, accounts and information regarding the Company and its Subsidiaries for such review and audit as the examining Member deems appropriate in its sole discretion reasonably exercised. A Member’s review and audit rights shall extend to goods and services furnished by a Member or its Affiliate to the Company and such furnishing Member shall exercise best efforts to provide materials reasonably required by the examining Member in order to perform its review and audit. All reviews and audits by a Member pursuant to this Section 4.6 shall be at the expense of the Member conducting such review or audit.

4.7       Other Notices .  The Company shall notify each Member in writing of any of the following immediately upon learning of the occurrence thereof, describing the same and, if applicable, the steps being taken by the Company with respect thereto:

(a) the occurrence of the default by the Company or its Subsidiaries under any material note, indenture, loan agreement, mortgage, lease, deed or other material similar agreement to which the Company or its Subsidiaries are a party or by which they are bound;

(b) the institution of any litigation, arbitration proceeding or other Proceeding affecting the Company or its Subsidiaries, whether or not considered to be covered by insurance, if the damages being sought in such litigation exceed $100,000 or, if not specified in such litigation, could reasonably be expected to exceed $100,000;

(c) the entry of any judgment or decree against the Company or its Subsidiaries, if the amount of such judgment exceeds $100,000; and

(d) the occurrence of a material adverse change in the business, operations, assets, condition (financial or otherwise) or prospects of the Company or its Subsidiaries resulting in an actual or potential liability or loss to the Company or its Subsidiaries in excess of $250,000.

ARTICLE V

Representations and Warranties of Members

Each Member hereby represents and warrants to the Company and each other Member that:

(a) if such Member is an organization, that it is duly organized, validly existing, and in good standing under the law of its state of incorporation or organization and that it has full organizational power to execute and agree to this Company Agreement and to perform its obligations under this Company Agreement;

(b) except as provided in Section 12.3 , such Member is acquiring its Company Interest for such Members own account as an investment and without an intent to distribute the interest;

 

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(c) such Member acknowledges that such Company Interests have not been registered under the Securities Act of 1933 or any state securities laws and may not be resold or transferred by the Member without appropriate registration or the availability of an exemption from such requirements;

(d) such Member, by itself or together with its advisors, is experienced in making investments comparable to its investment in the Company and is capable of judging for itself the risks inherent in such investment;

(e) such Member has the financial capacity to hold its investment in the Company for an indefinite period of time and to meet its obligations to make Capital Contributions under this Company Agreement, and acknowledges that the disposition of such investment is restricted both pursuant to federal and state securities laws and pursuant to the terms of this Company Agreement;

(f) such Member acknowledges that it has received access to all information that it deems necessary in order to make its decision to invest in the Company;

(g) this Company Agreement has been duly executed and delivered by it and constitutes its valid and binding obligation, enforceable in accordance with its terms;

(h) neither the execution and delivery of this Company Agreement nor the consummation of the transactions contemplated hereby nor compliance by it with any provisions hereof (1) conflicts with, or results in a breach or contravention of, or in a default or the creation of any lien under, any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license, agreement, or other instrument or obligation to which it is a party or by which it or its properties are bound, or (2) violates any law, order, writ, injunction or decree applicable to it or any of its properties;

(i) no consent, approval or other action by any court, governmental authority or third party is required in connection with its execution, delivery and performance of this Company Agreement;

(j) the name and address of each such Member is as reflected on Exhibit C attached hereto;

(k) as to Piedmont, there are no lawsuits or contested administrative Proceedings against Piedmont that would have a material adverse effect on Piedmont’s ability to perform its obligations as a Member under this Company Agreement;

(l) as to GNGC, there are no lawsuits or contested administrative Proceedings against GNGC that would have a material adverse effect on GNGC’s ability to perform its obligations as a Member under this Company Agreement.

ARTICLE VI

Rights and Duties of Members

6.1       Member Requirements . A Member must remain a Member during the term of the Company and may dispose of all or any portion of its Company Interest only in strict accordance with the terms and conditions of this Company Agreement (including, without limitation, Article XII ).

 

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Any attempted Disposition of all or any portion of its Company Interest, other than in strict accordance with this Company Agreement, shall be, and is hereby declared, null and void ab initio . The Members agree that breach of the provisions of this Section 6.1 may cause irreparable injury to the Company for which monetary damages (or other remedy at law) are inadequate in view of (i) the complexities and uncertainties in measuring the actual damages that would be sustained by reason of the failure of a Member to comply with such provisions and (ii) the uniqueness of the Company business and the relationship among the Members. Accordingly, the Members agree that the provisions of this Section 6.1 may be enforced by specific performance.

6.2      [Intentionally Left Blank]

6.3      [Intentionally Left Blank]

6.4       Unauthorized Expenses or Contracts .  A Member may not, without the prior approval of the Executive Committee, cause the Company or its Subsidiaries to enter into or make any contract, security agreement, financing statement, note or similar instrument, mortgage or guaranty, incur any obligation, or expend any money, except and unless an expenditure is required by the terms of a contract or instrument theretofore duly entered into by the Company or its Subsidiaries and authorized in accordance with this Company Agreement. Should a Member breach this Section 6.4 , such Member will indemnify, defend and hold the Company and the other Members harmless from all liabilities, costs, and damages resulting from such breach.

6.5       Authority of Members to Bind the Company .  The Members hereby agree that no individual Member or Members can bind the Company or its Subsidiaries unless such Member or Members are acting with the express written authority of the Executive Committee or as otherwise authorized in accordance with this Company Agreement.

6.6       Limitation of Liability of Members .  Except as provided for in Section 6.4 , no Member shall be liable for the debts, obligations or liabilities of the Company or its Subsidiaries, including under a judgment, decree or order of court, except as may be otherwise expressly agreed to in writing by such Member directly to the applicable third Person.

6.7       Contracts to Limit Members’ Liabilities .  Unless approved by the Executive Committee, no contract, lease, sublease, note, deed or other agreement or instrument shall be executed and delivered by or on behalf of the Company or its Subsidiaries if there is contained therein any provision whatsoever that states or suggests that the claims of any party thereto and other beneficiaries thereunder are not limited solely to the assets of the Company or its Subsidiaries, and any contract, lease, sublease, note, deed or other agreement or instrument containing any such provision shall be null and void ab initio and shall not constitute a valid obligation of the Company or its Subsidiaries.

6.8        Liability of Members for Certain Acts or Omissions .  Any act or omission by a Member when acting as an authorized representative of the Company or its Subsidiaries and within the scope of such authorization, the effect of which may cause or result in loss or damage to the Company or its Subsidiaries, shall not subject the Member to any liability to the Company or its Subsidiaries or any other Member so long as such act or omission was not done fraudulently or in bad faith or as a result of willful and wanton misconduct or gross negligence. Nothing in this Section 6.8 shall limit the liability of a Member for any loss or damages to the Company or its Subsidiaries resulting from (a) the failure of such Member to perform any

 

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obligation of such Member under this Company Agreement or (b) any act or omission to act of the Member under any contractual arrangement with the Company or its Subsidiaries, which limitations will be governed pursuant to the terms of any such contractual arrangement.

6.9       Indemnification .

(a) The Company, to the fullest extent permitted by the Act, shall defend, indemnify and hold harmless any Member, Executive Committee Representative (or alternate), or Company officer, employee or agent, who was or is a party to, or is threatened to be made a party to, or is involved in, any threatened, pending or completed Proceeding, by a third party (including any action by or in the right of the Company) by reason of any acts, omissions or alleged acts or omissions by such Member, Executive Committee Representative (or alternate), or Company officer, employee or agent undertaken on behalf of the Company or its Subsidiaries and with the authorization of the Company, against and from losses, damages, claims and expenses for which such Member, Executive Committee Representative (or alternate), or Company officer, employee or agent has not otherwise been reimbursed (including (i) reasonable attorneys’ fees, judgments, and fines in all cases and (ii) amounts paid in settlement if agreed to by the Executive Committee) actually and reasonably incurred in connection with such Proceeding, so long as such act or omission was not done fraudulently or in bad faith or as a result of willful and wanton misconduct or gross negligence or, with respect to any criminal Proceeding, such Person had no reasonable cause to believe his conduct was unlawful.

(b) Subject to limitations and conditions as provided in this Article VI , each Person who was or is a party to, or is threatened to be made a party to, or is involved in, any threatened, pending or completed Proceeding by reason of the fact that such Person is or was serving at the request of the Company or its Subsidiaries as a member, officer, employee, or agent of another foreign or domestic limited liability company, corporation, partnership, joint venture, sole proprietorship, or other enterprise, shall be defended, indemnified and held harmless by the Company to the fullest extent permitted by the Act, against and from losses, damages, claims and expenses for which such Person has not otherwise been reimbursed (including (i) reasonable attorneys’ fees, judgments, and fines in all cases and (ii) amounts paid in settlement if agreed to by the Executive Committee) actually and reasonably incurred in connection with such Proceeding, so long as the acts or omissions or alleged acts or omissions forming the basis for such Proceeding were not done fraudulently or in bad faith or as a result of willful and wanton misconduct or gross negligence or, with respect to any criminal Proceeding, such Person had no reasonable cause to believe his conduct was unlawful.

(c) Indemnification under this Article VI shall continue as to a Person who has ceased to serve in the capacity that initially entitled such Person to indemnity under this Company Agreement. The rights granted pursuant to this Article VI shall be deemed contract rights, and no amendment, modification or repeal of this Article VI shall have the effect of limiting or denying any such rights with respect to actions taken or Proceedings arising prior to any such amendment, modification or repeal. It is expressly acknowledged that the indemnification provided in this Article VI could involve indemnification for negligence but cannot involve indemnification for any act or omission done fraudulently or in bad faith or as a result of willful and wanton misconduct or gross negligence or, with respect to any criminal Proceeding, if such Person had reasonable cause to believe his conduct was unlawful.

(d) The right to indemnification conferred in this Article VI shall not be exclusive of any other right which a Member or other Person indemnified pursuant to this Section 6.9 may have or hereafter acquire under any law, any provision of the Certification of Formation, this Company Agreement, any agreement, any vote of Members or otherwise.

 

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6.10      Credit Support .  Subject to the execution and effectiveness of the Indemnification Agreement among the Members, dated and executed the date hereof and in the form attached hereto as Exhibit G, GNGC, acting alone or through its Affiliates, agrees to exercise commercially reasonable efforts to provide credit support on acceptable terms, and in an amount not to exceed a ceiling established by the Executive Committee, to the extent required to support the Company’s and its Subsidiaries’ commercial operations. Such credit support shall be in a form and in amounts acceptable to the Executive Committee and to the GNGC Affiliate providing the credit support, and may include, without limitation, comfort letters, a guaranty of the Company’s performance or a letter of credit. In the event the Company must post a letter of credit as a result in a reduction of the credit rating of AGLR, the Company shall pay one hundred percent (100%) of the cost of obtaining the letter of credit.

6.11       Insurance .  To the extent not inconsistent with the Act and other laws and public policies of the State of Delaware, the Company and its Subsidiaries will purchase and maintain its policies of insurance, either through a Member or otherwise, of such types and in such amounts and containing such terms and conditions as is customary for a company that is similarly situated to the Company; provided, however, that unless the Executive Committee determines otherwise, the Company shall not be required to obtain any insurance for the benefit of any Member or any Representative acting in their capacity as a Member or Representative

6.12      Services Obligation .  Each of the Members agrees to provide the services of certain personnel (who shall be considered agents of the Company or its Subsidiaries, as appropriate, in performing such services) to the Company and its Subsidiaries in the manner established by the Executive Committee and as further set forth in the Operating Policy or the Services Agreement.

ARTICLE VII

Competition and Conflicts of Interest

7.1       Company Opportunity and Non-Competition.

(a) The assets and Property of the Company and its Subsidiaries shall at all times be dedicated exclusively to the benefit of the Company. Subject to the foregoing and except as otherwise set forth herein, any Member or Affiliate of any Member may participate in other business activities, whether or not any such activities are competitive with the business of the Company or its Subsidiaries. No Officer, Executive Committee Representative or employee of the Company, so long as such individuals remain in such capacity, shall participate in business in competition with the business of the Company or its Subsidiaries unless such activity is undertaken exclusively as Officer, employee or agent of a Member or Affiliate of a Member. No transaction with the Company or its Subsidiaries shall be voidable solely because a Member has a direct or indirect interest in

 

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the transaction if either (i) the transaction is arms-length and fair to the Company or its Subsidiaries or (ii) the disinterested Members (knowing the material facts of the transaction and the Member’s interest) or their Representatives on the Executive Committee specifically authorize, approve, or ratify the transaction.

(b) Notwithstanding the foregoing and except as provided in paragraph (d) of this Section and Section 7.4(f) , in the absence of the approval of the Executive Committee, no Member or Affiliate (resulting from a Change in Control or otherwise) of any Member shall (i) engage in the purchase, transportation and sale of natural gas on a non-regulated basis to Target Customers of such products located in the Retail Territory (except for the purchase, transportation, supply, sale (and sales activities), marketing, storage and/or infrastructure development of liquefied natural gas (“ LNG ”), compressed natural gas (“ CNG ”) and/or natural gas vehicle (“ NGV ”) facilities and/or filling stations); provided, however, that with respect to this Section 7.1(b) , Target Customers shall not include those industrial customers of either Member, as of the effective date of the Company Agreement, with whom such Member has a national account relationship that originated outside of the Retail Territory, but which customer might have ancillary business within the Retail Territory (a “ Non-Competing Customer ”), which customers the Current Members have agreed (or may agree after the date hereof) shall be excepted from the provisions; or (ii) sell or otherwise permit any non-Affiliate to use any trade name, trademark or service mark licensed to the Company or its Subsidiaries by such Member in connection with a non-Affiliate’s purchase, transportation and sale of natural gas in the Retail Territory. Nor shall anything in this Section restrict, or be construed to apply to, sales, services (including the transportation of natural gas) or the sale of products of the type provided at the time of execution of this Company Agreement, or mandated directly or indirectly by a regulatory body, including, but not limited to, the imputation of revenues, expenses or rate base, the effect of which is to create a penalty, economic or otherwise, for the failure to provide such sales, services or products, by PNG in its certificated service territory, or Atlanta Gas Light Company, Chattanooga Gas Company, Pivotal Utility Holdings, Inc. (d/b/a Elizabethtown Gas, Elkton Gas, and Florida City Gas), Virginia Natural Gas, Inc., and Northern Illinois Gas Company in their respective certificated service territories, or such other natural gas distribution companies designated by the Executive Committee by Unanimous Vote.

(c) Further, the Members acknowledge and agree that each Members’ assets, businesses, interests in joint ventures, partnerships and other entities existing as of the date hereof (“ Grandfathered Assets ”), and the ownership and operation of such Grandfathered Assets, shall not, subject to the terms of this Section 7.1(c) be deemed in violation of the provisions of Section 7.1(b) . The Members further acknowledge and agree that the provisions of Section 7.1(b) are not intended to prohibit the good-faith business activities of a Member after the date hereof that involve assets and interests similar in nature to the Grandfathered Assets, so long as such activities are not engaged in for the purpose of, and/or such activities do not have the principal effect of, circumventing the provisions of Section 7.1(b) . In this regard, the Members hereby affirm and agree that notwithstanding the language set forth in this paragraph, each of the Members is committed to conducting its business in compliance with the provisions of Section 7.1(b) , is committed to the success of the Company and its Subsidiaries with respect to Target Customers in the Retail Territory, and will otherwise avail itself of the language set forth in this paragraph in good faith consistent with such acknowledgments and affirmations.

 

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(d) No Member or Affiliate shall acquire, directly or indirectly, a Person, which Person’s primary business is the purchase, transportation and sale of natural gas on a non-regulated basis for Target Customers located in the Retail Territory. In the event a Member or Affiliate acquires, directly or indirectly, a Person, which has as an on-going ancillary business that is engaged in the purchase, transportation and sale of natural gas on a non-regulated basis for Target Customers located in the Retail Territory with the exception of any business such Person may have with any Non-Competing Customer (an “ Acquisition ”) whether through the ownership of assets, a division, a subsidiary, or otherwise (such assets being referred to herein as the “ Competing Assets ”), the acquiring Member or Affiliate shall either:

(1) consummate the sale of such Competing Assets to a third party or affirmatively discontinue such ancillary business within one hundred and eighty (180) days of the date of such Acquisition; or

(2) contribute such Competing Assets to the Company, thereby increasing the amount of such Member’s Capital Account at the then current fair market value of the Competing Assets as proposed in good faith by the contributing Member and as agreed to by a Unanimous Vote. The contributing Member shall provide the non-contributing Members notice (an “ Assessment Notice ”) of its intent to make such contribution, which notice shall contain (i) information and details relating to the Competing Assets; (ii) the contributing Member’s determination of the fair market value for the assets; and (iii) the basis for such determination.

The non-contributing Member may elect to (i) make a capital contribution (a “ Matching Contribution ”) to the Company, which contribution shall be equal to the amount necessary to maintain such Member’s Company Interest in the same proportion to the contributing Member’s Company Interest prior to taking into account the effect of either contribution or (ii) not make any capital contribution, in which case such Member’s Company Interest and Allocable Share shall be diluted in proportion to the contributing Member’s adjusted Membership Interest and Allocable Share. The non-contributing Member shall give the contributing Member notice of its intent to make a Matching Contribution and the amount of such Matching Contribution within thirty (30) days of its receipt of the Assessment Notice. The consummation of such a Matching Contribution shall be conditioned upon the contribution of the Competing Assets to the Company.

Each Member’s Company Interest and Allocable Share shall be adjusted to reflect the proportionate change to their Capital Accounts as such change bears to concurrent change in the other Members’ Capital Accounts (if any) after taking into effect the contribution(s) contemplated hereby. In the event any non-contributing Member disagrees on the appropriate fair market value for the Competing Assets, the non-contributing Member shall give notice of such disagreement within thirty (30) days of such Member’s receipt of the Assessment Notice (or concurrent with such non-contributing Member’s notice regarding its Matching Contribution), at which point, either Member shall submit the issue to the Dispute Resolution Procedures as provided in Article XVI hereof.

 

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The exercise of either Member’s right to contribute Competing Assets or a Matching Contribution in accordance with this Section shall be irrevocable.

Notwithstanding the foregoing or any provision to the contrary in this Company Agreement, this Section 7.1(d) shall not apply to, or prevent, any Member or its Affiliates, whether through acquisitions (directly or indirectly) or otherwise, engaging in the purchase, transportation, supply, sale (and sales activities), marketing, storage and/or infrastructure development of LNG, CNG and/or NGV facilities and/or filling stations.

7.2       Survival of Non-Competition Provisions .  The provisions of Section 7.1 shall remain in effect with respect to each Member and its Affiliates or former Member and its Affiliates of the Company until the passage of twelve (12) months from the date upon which any such Member becomes a Withdrawing Member pursuant to a sale of one hundred percent (100%) of its Company Interest pursuant to this Company Agreement; provided however, that from and after the date that is six (6) months following such date a Member becomes a Withdrawing Member, the provisions of Section 7.1 shall have no effect with respect to Affiliates of the Withdrawing Member to the extent such Affiliates result from a Change in Control transaction of such Withdrawing Member announced and consummated subsequent to the date such Member sold one hundred percent (100%) of its Company Interest.

7.3       Competition between Members .  Except as specifically provided in this Article VII , nothing shall limit or restrict the ability of Members or their Affiliates to compete with each other.

7.4       Piedmont Option to Purchase C&I Customer Retail Business.

(a)  Piedmont will have the one-time right and option (the “ Piedmont C&I Option ”), to be exercised no later than July 31, 2018 (the “ Expiration Date ”), to purchase from the Company the Company’s C&I Customer retail business in the states of North Carolina, South Carolina and Tennessee (excluding C&I Customers located in Marion County, Hamilton County and Bradley County, Tennessee) (the “ Option Business ”); provided that the closing of Piedmont’s purchase of the Option Business (the “ Option Closing ”) must occur on or prior to the Expiration Date. As of the Effective Date, the Option Business includes one full-time employee whom, upon Piedmont’s exercise of the Piedmont C&I Option, Piedmont would be permitted to employ, if it so chooses.

(b)  Pursuant to the Piedmont C&I Option, Piedmont shall have the right and option to purchase the Option Business at a price equal to the product of (x) five (5) and (y) the earnings before interest and taxes (EBIT) of the Option Business for the twelve (12) month period ending on the last day of the last full calendar month preceding the date of the Option Notice (the “ Option Purchase Price ”). Piedmont shall deliver to the Company at the Option Closing payment in immediately available funds in an amount equal to the Option Purchase Price. Disputes between the Members regarding the amount of the Option Purchase Price shall be handled in accordance with Article XVI .

 

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(c)  No later than ten (10) business days prior to the Option Closing, Piedmont will provide the Company with a transition services schedule that will allow for working capital settlements within the Company. No later than five (5) business days prior to the Option Closing, the Company will provide Piedmont a schedule of projected volumes for all hedged positions of C&I Customers as of the proposed Option Closing. At the Option Closing, Piedmont will, in its discretion, assume or purchase from the Company as part of the Option Business swap positions representing hedged volumes related to fixed price sales to C&I Customers in respect of the Option Business, with the price for each C&I Customer swap calculated by the weighted average cost of the fixed price and weighted average cost of the basis price for all hedged volumes. Piedmont and the Company shall cooperate in notifying customers of Piedmont’s purchase of the Option Business prior to the Option Closing.

(d)   To exercise the Piedmont C&I Option, Piedmont must deliver to the Executive Committee, no later than sixty (60) days before the Expiration Date, written notice of Piedmont’s intent to exercise the Piedmont C&I Option (the “ C&I Option Notice ”). The C&I Option Notice must set forth (i) the date on which Piedmont proposes to conduct the Option Closing, which must occur on or prior to the Expiration Date (ii) Piedmont’s calculation of the Option Purchase Price and all components thereof; and (iii) a description of any regulatory or other approvals Piedmont believes are necessary or appropriate to consummate the Option Closing.

(e)  From and after the time of the Option Closing, (i) the Company will cease use of any service marks, copyrights, trademarks, or trade names owned or licensed by Piedmont that are associated solely with the Option Business and (ii) to the fullest extent that the intellectual property licensed to the Company under the Service Mark License Agreement dated July 1, 1998 between PNG, on behalf of Piedmont, and the Company is associated with the Option Business, the Company agrees to terminate such license.

(f)  If the Option Closing occurs, for the period beginning on the Option Closing date and ending on July 31, 2018, neither the Company nor any of its Subsidiaries will engage in the purchase, transportation, sale and/or marketing of natural gas on a non-regulated basis to C&I Customers in the states of North Carolina, South Carolina and Tennessee (excluding C&I Customers located in Marion County, Hamilton County or Bradley County, Tennessee), except for the purchase, transportation, supply, sale (and sales activities), marketing, storage and/or infrastructure development of LNG, CNG, and/or NGV facilities and/or filling stations. Furthermore, if the Option Closing occurs, for the period beginning on August 1, 2018, for purposes of Section 7.1(b) hereof, “Target Customers” shall not include C&I Customers in the states of North Carolina, South Carolina and Tennessee (excluding C&I Customers located in Marion County, Hamilton County or Bradley County, Tennessee).

 

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ARTICLE VIII

Management

8.1       Management by Members and the Executive Committee .

(a)  Except as described below in this Article VIII , the management of the Company is fully vested in the Members, acting exclusively in their membership capacities or otherwise through the Executive Committee as established hereby. To facilitate the orderly and efficient management of the Company, the Members shall act (a) collectively as a “committee of the whole” (the “ Executive Committee ”), (b) through the delegation of responsibility and authority to the Officers pursuant to Section 8.9 and (c) through the delegation from time to time of certain responsibility and authority to particular Members pursuant to Section 8.11 . No Member has the right, power or authority to act for or on behalf of the Company or its Subsidiaries, to do any act that would be binding on the Company or its Subsidiaries, or to incur any expenditures on behalf of the Company or its Subsidiaries, except in accordance with the immediately preceding sentence or as otherwise specifically provided herein. Decisions or actions taken in accordance with the provisions of this Company Agreement shall constitute decisions or actions by the Company and shall be binding on each Member, Representative, Officer and employee of the Company. Except as otherwise provided in this Company Agreement, the Property, business and affairs of the Company shall be under the direction of the Executive Committee and the Officers acting pursuant to Section 8.9 . Except for matters requiring the action of the Members under the terms of this Company Agreement, the Executive Committee shall have the power to take any action that the Members may take under law, subject to any restrictions set forth in this Company Agreement.

The approval by a Unanimous Vote shall be required before any of the following acts involving the Company may be taken:

1.  approving and adopting or amending any written policy between the Members and the Company contemplated in this Company Agreement, including the Operating Policy;

2.   approving and adopting the Company’s written Business Plan, and amending or modifying any provision of the Business Plan;

3.    entering into, amending, modifying, or terminating a material agreement or contract with a term in excess of the term set forth in the Operating Policy or involving aggregate consideration (including assumed actual and contingent liabilities) or receipts, or delivery or receipt of goods or services having a value, in excess of the amount set forth in the Operating Policy, over the term of the agreement;

4.      entering into, amending, modifying, or terminating any contract or commitment to acquire or transfer any asset or Property, the fair market value or aggregate consideration (including assumed actual and contingent liabilities) of which exceeds the amount set forth in the Operating Policy;

5.  filing any claim or lawsuit against any Person where the amount claimed is in excess of the amount set forth in the Operating Policy, or settling any claim or lawsuit where the fair market value of the settlement amount is in excess of such amount;

6.     except as permitted pursuant to Section 8.1(f), borrowing any principal amount in excess of the amount set forth in the Operating Policy, incurring any future borrowing liability whatsoever in excess of such amount, lending or

 

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guaranteeing any material amount of third party indebtedness (including, without limitation, under any contract or arrangement referred to in this Section 8.1 ) it being understood that such limitation shall not be a limitation on the amount or type of trade payables that may be incurred in the ordinary course of business consistent in all respects with past practices by the Company;

7.    approving or modifying any Fiscal Year capital budget or operating budget (the “ Operating Budget ”) and contributions to the operating fund for each Fiscal Year, which shall not be exceeded without the express consent of a Unanimous Vote;

8.     the indemnification of any Officer, employee, agent or any other Person except as specifically provided herein;

9.  executing or otherwise entering into, or amending, modifying, or terminating, any employment agreement with the President or a Vice President or similarly compensated person or Officer, the election or removal of the President, any Vice President or Officer, or the hiring or firing of other similarly compensated person with or without cause;

10.    setting or amending all components of compensation (and any Company compensation plan), including base salary, annual performance plans, short term incentive plans, long term incentive plans and participation in any equity plans (or equivalent) offered by any Member entity of the President, Vice Presidents, and Officers (but excluding any employee expense reimbursement plans);

11.  revaluing any property or asset outside of the normal course of business;

12.    taking any action in the Company’s capacity as a shareholder, partner or member of any Person to the extent such action would require a Unanimous Vote if taken under this Company Agreement;

13.  except as permitted pursuant to Section 8.1(f) or the Operating Policy, taking action that will result in any material Company Property being burdened by a material lien or other encumbrance, it being understood that such limitation shall not be a limitation on the Company’s ability to incur trade payables in the ordinary course of business consistent in all respects with past practices by the Company;

14.      except as otherwise required by Section 10.1 , hereof approving the distribution of Company Property to Members;

15.    except as contemplated in the Operating Policy, executing or otherwise entering into, or amending, modifying, or terminating (other than in accordance with, or pursuant to, the terms of such agreement), any agreement with a Member, an Officer or employee of the Company or its Subsidiaries, an Affiliate of a Member, or a person related by blood or marriage to an Officer or employee of the Company or its Subsidiaries, involving aggregate consideration (including assumed actual and contingent liabilities) or fair market value or actual or contingent liability in excess of $10,000;

16.  the admission of an Additional Member;

 

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17.  transferring all or substantially all of the assets of the Company;

18.    dissolving the Company to the extent that Section 12.4 and Article XIII of this Company Agreement requires a Unanimous Vote to dissolve the Company;

19.    the filing of a petition as debtor in a United States Bankruptcy Court or taking any material affirmative act that would result in the Company’s Bankruptcy;

20.    merging or consolidating the Company with or into any other Person;

21.    a change in the name of the Company;

22.    entering into any modification or amendment of this Company Agreement;

23.    [intentionally left blank];

24.    extension of the term of the Company;

25.    hiring of outside attorneys (except in instances where (i) the President of the Company reasonably concludes that the delay associated with Executive Committee approval of the hiring of outside legal counsel could have a material adverse impact on the Company, or (ii) the President of the Company reasonably believes that the total legal fees associated with the matter requiring outside legal counsel will not exceed $100,000, in which cases the President shall be authorized to hire outside counsel), auditors and financial consultants; and

26.    approving significant regulatory filings and material public announcements of the Company or its Subsidiaries (which shall in no event include advertising undertaken in the ordinary course of business and consistent with the Operating Policy) or to the extent any regulatory filings or public announcements may relate principally to such Member or its Affiliates or business.

(b) Any other action required or permitted to be taken by the act of the Executive Committee under this Company Agreement and not specifically identified as a Unanimous Vote matter may, upon prior notice thereof to the Members, be taken by a Majority Vote of the Executive Committee.

(c) If the matter being voted on does not receive the requisite vote, the matter shall be deemed to be denied; furthermore, unless otherwise provided herein, if the matter being voted on provides for more than two (2) alternatives and no alternative receives the requisite vote, no alternative shall be selected.

(d) Prior to the admission of a new Member, the Executive Committee shall review and revise this Agreement (including but not limited to this Section 8.1 ) and make such changes in the approval procedure as the Executive Committee agrees are required to govern the operation of the Company after the admission of the new Member; and, further, the provisions of Article XII hereof which make reference to “per capita” shall all automatically be deemed to references to “pro rata” (unless the Current Members shall otherwise agree).

(e) The Executive Committee may create subcommittees and delegate to such subcommittees the authority and responsibility to act on behalf of the Executive Committee, including the consent to, and action upon, those items listed under Section 8.1(a) above as requiring the Unanimous Vote of the Executive Committee, and may rescind any such delegations, as it may deem appropriate.

 

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(f) Notwithstanding the provisions of Section 8.1(a) above, the Company may, upon the affirmative vote of the holders of a majority of the Company Interests, solicit and incur commercially reasonable levels of secured or unsecured debt in excess of the restrictions imposed by the Operating Policy in conjunction with the pursuit of the business of the Company and its Subsidiaries, provided that such debt is non-recourse in nature with respect to the Members.

8.2      Composition, Term and Duties.

(a)  The Executive Committee shall be comprised of three (3) representatives for each Member (such Member’s “ Executive Committee Representative ” or “ Representative ”). All Representatives shall be entitled to receive notices and agendas of upcoming Executive Committee meetings, attend all Executive Committee meetings and participate in all discussions, and receive minutes from previous Executive Committee meetings. With the approval of the other Members, a Member may bring support staff to Executive Committee meetings. Such staff shall be subject to confidentiality requirements deemed appropriate by the Executive Committee. The Representatives selected by each Member shall cast their votes as a single voting block. Each voting block shall be entitled to cast the following number of votes on matters requiring the approval of the Executive Committee: each voting block shall have one vote, or fractional part thereof, for each percentage point, or fractional part thereof, of Company Interest credited to the Member.

(b)  Each Representative shall be entitled to hold office until death, resignation or removal. A Member may replace a Representative appointed by such Member in the event of a vacancy. Any Representative may be removed at any time, with or without cause, by the Member entitled to appoint such Representative, but not otherwise. Any Representative on the Executive Committee may appoint a proxy (including another Representative, the Chairman, or the Secretary of such meeting) to attend meetings and vote (including, without limitation, voting on any matter before the Executive Committee). Without limiting the generality of the foregoing, in determining if a quorum is present, all Representatives in attendance by means of a proxy shall be included in the count of a quorum.

8.3      Annual and Regular Meetings . The Executive Committee shall hold an annual meeting, and may hold regular meetings, at such time and place as agreed by the Members but in any event the Executive Committee shall, unless the Executive Committee otherwise agrees, hold quarterly meetings at sites selected by the Executive Committee during each year.

8.4        Special Meetings . Special meetings of the Executive Committee may be called by the Chairman, the Executive Committee or any Member, upon no less than ten (10) days prior written notice to all Representatives on the Executive Committee.

8.5       Notice of Meetings . Notice of special, annual and regular meetings must be given in writing to each Representative on the Executive Committee at least ten (10) days in advance of such meeting and shall specifically state the purpose of the meeting. Notice of such meeting may be waived by a Representative.

 

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8.6       Quorum and Manner of Acting . The presence of at least one (1) Representative of each Member shall constitute a quorum (“ Quorum ”). No action may be taken at a meeting of the Executive Committee in the absence of a Quorum. In the event all Representatives of a Member receive notice of an annual, regular or special meeting in accordance with this Agreement and do not participate in such meeting either in person or by proxy, such Representatives shall be deemed to have attended such meeting and voted as a block not to take action submitted to the Executive Committee for approval at such meeting. In the event a Member or all Representatives of a Member abstain from voting (without granting a proxy with respect to such vote) on a matter presented to the Executive Committee for approval, such abstention shall be noted in the Company’s records and the votes of such Member or Representative shall be disregarded for purposes of determining whether or not the matter before the Executive Committee receives approval via a Unanimous Vote or Majority Vote. In other words, with respect to any Unanimous Vote matter, if one Member abstains from casting its votes, that abstention shall be noted and, notwithstanding such abstention, the affirmative vote of each of the other Members for the matter in question shall constitute a Unanimous Vote approval for purposes hereof. As further example, and with respect to a Majority Vote matter, if all of the Representatives of a Member abstain from casting their votes, that abstention shall be noted and, notwithstanding such abstention, the affirmative vote of a Member or Members holding a majority of the votes, determined without regard to the votes held by Representatives of the abstaining Member, shall constitute approval via Majority Vote for purposes hereof. Any action the Executive Committee may take may be taken without a meeting by unanimous written consent of all the Representatives. For purposes of the immediately preceding sentence, the signature of only one (1) Representative of a Member shall be deemed to constitute written consent of all of that Member’s Representatives. Meetings of the Executive Committee may take place by telephone or any means where any persons attending can hear and speak to each other.

8.7       No Compensation .  No Representative on the Executive Committee shall be entitled to compensation for his/her services, or any reimbursement of expenses incurred, as a Representative on the Executive Committee.

8.8       Disclaimer of Duties; Indemnification .      EXCEPT AS OTHERWISE PROVIDED UNDER SECTION 7.1 AND SUCH DUTIES TO THE COMPANY AS ARE IMPOSED BY APPLICABLE LAW, EACH REPRESENTATIVE SHALL REPRESENT, AND OWE DUTIES TO, ONLY THE MEMBER THAT DESIGNATED SUCH REPRESENTATIVE (THE NATURE AND EXTENT OF SUCH DUTIES BEING AN INTERNAL CORPORATE AFFAIR OF SUCH MEMBER), AND NOT TO THE COMPANY, ANY OTHER MEMBER OR REPRESENTATIVE, OR ANY OFFICER OR EMPLOYEE OF THE COMPANY.

8.9       Officers and Other Agents

(a) Generally . The Company shall have agents, referred to as “Officers” of the Company. An Officer shall not (i) be entitled to serve as a Representative and a Representative shall not be entitled to serve as an Officer or (ii) after being elected as an Officer of the Company, subsequently become or otherwise be elected or appointed as an officer (or similarly compensated person) of a Member, unless expressly approved by Unanimous Vote. Officers shall be agents (whose authority is limited pursuant to the following sentence) of the Company, shall be appointed in the manner specified below, and shall have the titles and authority specified in this Section 8.9 . Each Officer shall have only the

 

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authority specified below, and shall, subject to the general control of the Executive Committee, be responsible for the day-to-day operations and direction of the affairs and business of the Company.

(b)   Officers .    The elected Officers shall be the President and, as appointed by the Executive Committee from time to time in accordance with subsection (c) below, Vice Presidents. For purposes of this Company Agreement, the Secretary of the Company shall not be deemed to be an Officer of the Company.

(c)   Election and Term of Office .   The President and Vice Presidents, if any, shall be elected annually upon the Unanimous Vote at the annual meeting. If a new President or Vice President is not elected at an annual meeting of the Executive Committee, the incumbent Officer shall continue to serve until such Officer is removed, and a replacement elected, all upon a Unanimous Vote at the following annual meeting of the Executive Committee. Notwithstanding the foregoing, any Officer may be removed by the Executive Committee, with or without cause, upon a Unanimous Vote. Vacancies in any office shall be filled by Unanimous Vote.

(d)   Chairman of the Executive Committee .  A Chairman shall preside at meetings of the Executive Committee, and shall exercise such powers and perform such duties as may be assigned to him/her by this Company Agreement or the Executive Committee. The Chairman will be a Representative selected at the annual meeting and shall serve for a term of one (1) year, and the office of Chairman shall rotate annually among the Members.

(e)   President .  The President, subject to the general control of the Executive Committee, shall (i) be responsible for the day-to-day operation and direction of the affairs of the Company, and its employees and agents, (ii) supervise generally the affairs of the Company, and, (iii) subject to the limitations imposed by this Company Agreement, any employment agreement, any employee plan, or any resolution of the Executive Committee, have full authority to execute all documents and to take all actions that the Company may legally take. Except for such meetings or portions thereof during which the Executive Committee shall declare itself to be in “executive session,” the President shall attend all meetings of the Executive Committee (but as President shall not be entitled to vote on matters before the Executive Committee) and exercise such other powers and perform such other duties as may be assigned to him/her by this Company Agreement or the Executive Committee, including such duties and powers stated in any employment agreement.

(f)   Vice Presidents .  In the absence of the President, the Vice Presidents designated by the Executive Committee shall, except as hereinafter provided, have all of the powers and duties conferred upon the President. Each of the Vice Presidents shall, subject to the limitations imposed by this Company Agreement, the Operating Policy, any employment agreement, any employee plan, or any resolution of the Executive Committee, have the same power as the President to sign certificates, contracts and other instruments of the Company. Any Vice President shall perform such other duties and may exercise such other powers as may from time to time be assigned to him/her by this Company Agreement, the Executive Committee, the Chairman, or the President.

 

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(g) Secretary and Assistant Secretaries .  The Secretary shall attend and record or cause to be recorded in books provided for that purpose the minutes of the meetings or actions of the Members and the meetings or actions of the Executive Committee or any subcommittees thereof, shall see that all notices are duly given in accordance with the provisions of this Company Agreement and as required by law, shall be custodian of all records (other than financial), shall see that the books, reports, statements, certificates and all other documents and records required by law are properly kept and filed, and, in general, shall perform all duties incident to the office of Secretary.

(h) Powers of Attorney .  The Executive Committee may grant powers of attorney or other authority as appropriate to establish and evidence the authority of the Officers.

(i) Borrowed Employees .  Subject to approval by the Company’s President, the Company may borrow a Member’s employees on a full or part time basis, or a Member’s Affiliate’s employees, with that Member or Affiliate’s consent, from time to time on a temporary basis for purposes associated with the Company’s business. Out-of-pocket expenses and reasonable salaries and benefits associated with such borrowed employees shall be addressed in the Operating Policy. The Members acknowledge and agree that part-time borrowed employees may continue to perform services for the lending Member or its Affiliates.

(j) Leased Employees.   The Company may lease a Member’s employees on a full or part time basis, or a Member’s Affiliate’s employees, with that Member or Affiliate’s consent, from time to time on a temporary basis for purposes associated with the business of the Company or its Subsidiaries. Out-of-pocket expenses and reasonable salaries and benefits associated with such leased employees shall be addressed in an agreement between the loaning Member or Affiliate and the Company or its Subsidiaries. The Members acknowledge and agree that part-time leased employees may continue to perform services for the lending Member or its Affiliates.

(k) Employee Transfers .  With the prior approval of the affected Member, the Company and its Subsidiaries, with Executive Committee approval if required by Section 8.1(a)(15) or if not, approval by the Company’s President, shall be entitled to hire employees of any Member (including its Affiliates) to fill vacancies within the Company or its Subsidiaries. With the prior approval of the Executive Committee, a Member (including its Affiliates) shall be entitled to hire employees of the Company or its Subsidiaries to fill vacancies with such Member; provided however, that no such approval shall be necessary to allow GNGC or an Affiliate thereof to hire any personnel acting as a service personnel under the terms of the Services Agreement. The granting of credit for past service with the prior employer for purposes of the hired employee’s compensation and benefit plans shall be at the discretion of the new employer.

8.10      Expenses .  The Company shall pay only those expenses incurred by the Officers and employees that are directly attributable to the business of the Company and its Subsidiaries.

8.11      Delegation to Particular Member .  The Executive Committee by Unanimous Vote, may delegate to one (1) or more Members, in writing, such authority and duties as the Executive Committee may deem advisable, including its authority under Section 8.1 hereof. Decisions or actions taken by any such Member in accordance with the provisions of this Agreement shall constitute decisions or actions by the Company and shall be binding on each

 

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Member, Representative, Officer and employee of the Company. Any delegation pursuant to this Section 8.11 may be revoked at any time by the Executive Committee. With respect to duties discharged hereunder by a Member (a) such Member may discharge such duties through the personnel of an Affiliate of such Member and (b) unless the Members otherwise agree, the Company shall compensate such Member (or its Affiliate, as applicable) for the performance of such duties as set forth in the Operating Policy.

ARTICLE IX

Contributions and Capital Accounts

9.1       Capital Contributions .

(a) As of the Effective Date, the Current Members agree hereby that each and the other has made capital contributions to the Company in consideration for such Member’s Company Interest and the Company Interest of each Current Member in proportion with the other and the balance of each Member’s Capital Account is reflected on Exhibit D hereto, as may be amended from time to time.

(b) Any Additional Member shall make the Capital Contribution described in such Additional Member’s Admission Agreement. The amount of the Additional Member’s initial Capital Contributions, the time for making such contributions, and any changes in the other Members’ Capital Accounts, Allocable Shares and Company Interests that result, shall be set forth in such Additional Member’s Admission Agreement.

9.2      Additional Capital Contributions .  As and when the Executive Committee determines that the Company needs cash from time to time, each Member agrees that it shall make Capital Contributions to the Company in an amount in accordance with its respective Company Interest for the purposes determined by a Unanimous Vote authorizing such Capital Contributions in accordance with Section 8.1 . The Capital Accounts of the contributing Members shall be adjusted pro rata to reflect the amount of such contribution in proportion with the other Members.

9.3       Failure to Contribute .    If a Member (a “ Delinquent Member ”) does not contribute within three (3) days of the date required all or any portion of a Capital Contribution that Member is required to make as provided in this Company Agreement, the remaining Members in proportion to their Allocable Shares or in such other percentages as they may agree may make the Capital Contribution that the Delinquent Member failed to make and the Allocable Shares of the Members, including the Delinquent Member, shall be adjusted to reflect the Delinquent Member’s failure to make the Capital Contribution and the resulting increase in the Capital Accounts of the remaining Members and appropriate adjustments in the Members’ Company Interests.

9.4       Capital Accounts, Allocations, and Distributions Attributable to Transferred Interest .   A consolidated Capital Account is and shall be maintained for each Member. Each Member’s Capital Account shall be increased by (a) the amount of any Capital Contributions made by such Member to the Company (net of liabilities secured by such contributed Property that the Company is considered to assume or take subject to under Section 752 of the Code), and (b) allocations to that Member of Company Net Taxable Income and Net Tax Losses (or items thereof), including income and gain exempt from tax and income and gain described in Treasury Regulation Section l.704-l(b)(2)(iv)(g), but excluding income and gain described in Treasury

 

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Regulation Section 1.704-1(b)(4)(i), and shall be decreased by (c) the amount of money distributed to that Member by the Company, (d) the fair market value of Property distributed to that Member by the Company (net of liabilities secured by such distributed property that such Member is considered to assume or take subject to under Section 752 of the Code), (e) allocations to that Member of expenditures of the Company described (or treated as described) in Section 705(a)(2)(B) of the Code, and (f) allocations of Company loss and deduction (or items thereof), including loss and deduction described in Treasury Regulation Section 1.704-1(b)(2)(iv)(g), but excluding items described in (e) above and loss or deduction described in Treasury Regulation Section 1.704-1(b)(4)(i) or 1.704-1(b)(4)(iii). The Members’ Capital Accounts shall also be maintained and adjusted as permitted by the provisions of Treasury Regulation Section 1.704-1(b)(2)(iv)(f) and as required by the other provisions of Treasury Regulation Sections 1.704-1(b)(2)(iv) and 1.704-1(b)(4), including adjustments to reflect the allocations to the Members of depreciation, depletion, amortization, and gain or loss as computed for book purposes rather than the allocation of the corresponding items as computed for tax purposes, as required by Treasury Regulation Section 1.704-1(b)(2)(iv)(g). Thus, the Members’ Capital Accounts shall be increased or decreased to reflect a revaluation of the Company’s Property on its books based on the fair market value of the Company’s Property on the date of adjustment immediately prior to (A) the contribution of money or other Property to the Company by an Additional Member or Current Member as consideration for a Member’s Allocable Share, (B) the distribution of money or other property by the Company to a Member as consideration for a Member’s Allocable Share, or (C) the liquidation of the Company. Upon the Disposition of all or a portion of a Member’s Allocable Share, the Capital Account of the disposing Member that is attributable to such Allocable Share shall carry over to the assignee of such Allocable Share in accordance with the provisions of Treasury Regulation Section 1.704-1 (b)(2)(iv)(l).

9.5      Withdrawal of Capital .  Except as otherwise provided herein, no Member shall be entitled to withdraw all or any portion of its Capital Contributions or receive interest on its contributed capital or Capital Account.

ARTICLE X

Allocations and Distributions

10.1      Allocations of Company Income . As of the end of each Fiscal Year (or any other, shorter period selected by the Executive Committee), the Company Income shall be determined in accordance with Section 4.2 . No later than ninety (90) days after the end of the Fiscal Year, the Company shall make an annual distribution to its Members equal to no less than one hundred percent (100%) of its Company Income for the immediately preceding Fiscal Year, unless otherwise determined by a unanimous vote of the Members. The distribution shall be allocated among the Members in accordance with the Members’ Allocable Shares as of the end of the Fiscal Year for which the Company Income has been calculated; provided however, that the allocation of any cash distribution between the Current Members shall be adjusted as necessary to maintain the Current Members’ Company Interest as reflected in the Capital Accounts of each Member in proportion with the other as of the end of the prior Fiscal Year, which adjustment may include a distribution of cash to maintain such proportions in the event of the Company’s loss of earnings for any Fiscal Year.

 

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10.2      General Tax Allocations .  As of the end of each Fiscal Year, Net Taxable Income and Net Tax Losses shall be allocated among the Members according to their respective Allocable Shares.

10.3      Special Allocations .  At the end of each Fiscal Year and notwithstanding any provision of Section 10.2 , the following special allocations shall be made both for Capital Account and for federal income tax purposes unless otherwise provided:

(a)  In accordance with the ordering rules of Treasury Regulation Section 1.704-2(j), items of gross income and realized gain first shall be allocated in an amount and in a manner that complies with the “chargeback” requirement of Treasury Regulation Section 1.704-2(i)(4), the “qualified income offset” requirement of Treasury Regulation Section 1.704-1(b)(2)(ii)(d), and the “minimum gain chargeback” requirement of Treasury Regulation Section 1.704-2(f). Further, any “partner non-recourse deductions” within the meaning of Treasury Regulation Section 1.704-2(i)(2) attributable to “partner non-recourse debt” shall be allocated to the Member who bears the “economic risk of loss” for such debt in accordance with Treasury Regulation Section 1.704-2(i). Any losses in excess of the losses allowable to the Members pursuant to the Treasury Regulations promulgated under Code Section 704(b) shall first be allocated to the extent allowable hereunder to Members who are not precluded from receiving such allocations by the preceding provisions of this subparagraph (a), if any, and shall thereafter be allocated as provided in Section 10.2 .

(b)  If a taxing authority ignores the characterization of any amounts paid to a Member (or an Affiliate thereof) as salaries, management fees, commissions, interest or other compensation for services (“ Compensation ”), and refuses to treat such payments as either guaranteed payments within the meaning of Code Section 707(c) or payments made to such Member other than in such Member’s capacity as a “partner” within the meaning of Code Section 707(a), and such taxing authority ultimately treats such amounts paid to a Member (or an affiliate thereto) as a distribution to such Member for federal income tax purposes which reduces such Member’s Capital Account, then the Compensation shall be treated as an allocation of an item of income or gain of the Company to the recipient Member so that, consistent with the intent of the Members, the Compensation shall not be treated as a distribution which reduces the recipient Member’s Capital Account. Accordingly, such Member shall be allocated the first available items of Company income and gain (including in a succeeding year) in an amount equal to the Compensation.

(c) If the Company owns (x) any Property contributed by a Member that had a fair market value different from its adjusted basis for federal income tax purposes on the date of the contribution, or (y) any Property that has been revalued pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(f), then for federal income tax purposes only and not for Capital Account purposes, any income, gain, loss or deduction with respect to such Property shall be allocated among the Members in accordance with Code Section 704(c) and the Treasury Regulations thereunder. Pursuant to the “traditional method” of making Code Section 704(c) allocations described in Treasury Regulation Section 1.704-3(b).

 

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ARTICLE XI

Taxes

11.1      Tax Elections .  The Company has filed an election under Section 754 of the Code and the Treasury Regulations thereunder to adjust the basis of the Company assets under Section 734(b) or 743(b) of the Code, and shall cause the Company to file a corresponding election under the applicable sections of state and local law.

11.2      Tax Returns.   The Executive Committee shall cause federal, state and local tax returns for the Company to be prepared and filed with the appropriate authorities in a timely manner. In compliance with applicable regulations, the Company shall cause to be delivered to each Person who was a Member at any time during such Fiscal Year all information concerning the Company necessary for the preparation of such Person’s tax returns, including a statement showing such Person’s share of taxable gain or taxable loss (or items thereof) for such year for federal, state and local tax purposes.

11.3      Tax Matters Member .

(a)  GNGC, or an Affiliate of GNGC, is hereby appointed the “Tax Matters Partner” (herein sometimes referred to as the “ Tax Matters Member ”) of the Company for all purposes pursuant to Sections 6221 and 6231 of the Code. The Tax Matters Member, or its designee, shall (i) furnish to each Member a copy of each notice or other communication received from the Internal Revenue Service or applicable state authority (except such notices or communications as are sent directly to each such Member), (ii) keep each Member informed of any administrative or judicial Proceeding, as required by Section 6223(g) of the Code, (iii) allow each Member an opportunity to participate in all administrative and judicial Proceedings involving the tax matters of the Company, and (iv) advise and consult with each Member as to proposed adjustments to the federal or state income tax returns of the Company. At least fifteen (15) days prior to the filing of the Company’s U.S. Partnership Tax Return, a draft of such return shall be circulated to each other Member for its review. The Tax Matters Member shall circulate to each other Member a draft of any state income tax return promptly after it is available, and, in any event, at least fifteen (15) days prior to the filing of any such return. Prior to the filing of any other federal, state or local tax return, the Tax Matters Member shall cause a draft of such tax return to be circulated to each other Member for its review promptly after it is available. The Company shall not be obligated to pay any fees or other compensation to the Tax Matters Member in its capacity as such, provided that the Company shall reimburse the Tax Matters Member for any and all out-of-pocket costs and expenses (including reasonable attorneys’ and other professional fees) incurred by it in its capacity as Tax Matters Member. The Company shall indemnify, defend and hold the Tax Matters Member harmless from and against any loss, liability, damage, cost or expense (including reasonable attorneys’ fees) sustained or incurred as a result of any act or decision concerning Company tax matters and within the scope of such Member’s responsibility as Tax Matters Member, so long as such act or decision was not done fraudulently or in bad faith or as a result of willful and wanton misconduct or gross negligence or, with respect to any criminal Proceeding against the Tax Matters Member, such Member had no reasonable cause to believe its conduct was unlawful. The Tax Matters Member shall consult with each other Member concerning the cost of legal services. The Tax Matters Member may resign upon thirty (30) days written notice to the Company. Notwithstanding the foregoing, the Tax Matters Member is not authorized to take any action with regard to the foregoing matters which would be binding on either the Company or the Member without the approval of the Executive Committee.

 

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(b) If a Member objects to the tax treatment of an item on any income tax return, such Member shall promptly inform the Tax Matters Member of its objection and the grounds upon which the objection is based. If the Tax Matters Member, after due consideration of a Member’s objection, is of the view that the tax treatment of the item in question on the return as originally submitted is reasonable, then the Tax Matters Member shall cause the Company to file the return reporting the item in question in the manner originally submitted.

11.4      Tax Controversies .  The Members shall comply with the responsibilities outlined in this Section and in Sections 6222 through 6231 and 6050K of the Code (including any Treasury Regulations promulgated thereunder) and in doing so shall incur no liability to any other Member. The Tax Matters Member shall not agree to any extension of the statute of limitations for making assessments of tax on behalf of the other Members without first obtaining the written consent of the other Members. The Tax Matters Member shall not bind the other Member to a settlement agreement in respect of taxes without obtaining the written consent of the other Members. Any Member who enters into a settlement agreement with the Secretary of the Treasury with respect to any “partnership items”, as defined in Section 6231(a)(3) of the Code, shall notify the other Members of such settlement agreement and its terms within ninety (90) days from the date of settlement. The Tax Matters Member shall not, in its capacity as Tax Matters Member, file a petition under Code Sections 6226, 6228 or any other Code Sections with respect to any Company item, or other tax matters involving the Company, without the consent of the other Members. The Company shall retain its records with respect to each Fiscal Year until the expiration of ninety (90) days after the period within which additional federal or state income tax may be assessed for such year. The provisions of this Section will survive the termination of the Company and the transfer of any Member’s Company Interest and will remain binding on the Members for a period of time necessary to resolve any and all matters regarding the federal and, if applicable, state income taxation of the Company.

ARTICLE XII

Disposition of Company Interests

12.1      Right of Disposition .  Each Member agrees not to Dispose of its Company Interest, in whole or in part, or to withdraw from the Company, except as provided in this Article XII . In connection with any Disposition, each Member party to such Disposition (including any Additional Member admitted as a Member as a result of such Disposition) shall provide to the Company the information required to revise Exhibit B and Exhibit C only as to such Members, and Exhibit D shall be so revised and distributed to all Members. Nothing in this Article XII shall be construed to limit a Member’s ability to transfer its entire Company Interest to an entity that is wholly owned, directly or indirectly, by such Member or is wholly owned, directly or indirectly, by the entity that owns one hundred percent (100%) of such Member. Such a transfer to a wholly-owned Person will be recognized by the Company upon receipt of written notice from the transferor Member.

 

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12.2      Dispositions not in Compliance with this Article Void .  Any attempted Disposition of a Company Interest, or any part thereof, not in compliance with this Article XII is null and void ab initio .

12.3      Disposition Between Members .

(a) Except as provided in this Section 12.3 , unless the Executive Committee provides otherwise by Unanimous Vote, a Member shall not be permitted to Dispose of less than one hundred percent (100%) of its Company Interest. In the event a Member desires to Dispose of all of its Company Interest, it shall first offer such Company Interest to the remaining Members at Market Value. In the case of a Disposition of all of the Company Interest of a Member (whether occurring pursuant to this Section 12.3 or otherwise), the other Members, if they first decline to purchase such Company Interest being disposed of, may designate a third party or parties to purchase all or part of such Company Interest at no less than Market Value and continue the business of the Company without dissolution. Should the remaining Members elect not to purchase such Company Interest or to designate a third-party purchaser or the Members are unable to agree upon the terms upon which a sale shall take place, the Member desiring to Dispose of its Company Interest shall be entitled to attempt to sell to a third party in accordance with Section 12.4 .

(b)   [Intentionally Left Blank]

12.4      Third Party Disposition Procedures . A Member (the “ Selling Member ”) may sell all of its Company Interest to any bona fide third party purchaser permitted to be a member of a limited liability company under the Act, for cash or other consideration, provided that (i) such Member first complies in good faith with the provisions of Section 12.3(a) , (ii) the Selling Member allows the remaining Members to match the bona fide third party offer, and (iii) each Member approves the sale of such Company Interest to such third party purchaser and of such third party becoming an Additional Member, which approval may be granted by such Members at their sole discretion reasonably exercised. No such third party purchaser may become an Additional Member without execution of an Admission Agreement. To satisfy clause (ii) above, the Selling Member shall present a written offer to the remaining Members, through the Executive Committee, stating the name of the proposed third party purchaser (the “ Original Purchaser ”) and all the terms and conditions of the proposed offer, including sales price. The non-selling Members, for a period of sixty (60) days from receipt of such written offer, shall have the right to elect to accept such written offer on the same terms and conditions applicable to the Original Purchaser. In the event that (A) the remaining Members do not elect to purchase the Company Interest from the Selling Member, (B) the remaining Members do not approve the sale of such Company Interest to the Original Purchaser, and (C) the Selling Member elects to continue its attempt to sell such Company Interest, the following procedure shall apply:

(a) The Selling Member may present a bona fide written offer from a different third party purchaser (the “ Replacement Purchaser ”) to the remaining Members in accordance with this Section 12.4 , provided that the Replacement Purchaser offer must be presented to the remaining Members on or before 5:00 p.m. Eastern Time on the fifth business day following the Selling Member’s receipt of notice that the sale of its Company Interest to the Original Purchaser was not approved. The remaining Members shall have the right for a period of sixty (60) days from receipt of such written offer to elect to accept such written offer on the same terms and conditions applicable to such Replacement Purchaser.

 

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(b)  In the event that (I) (X) the Selling Member does not present a written offer from a Replacement Purchaser, (Y) the remaining Members do not elect to purchase the Selling Member’s Company Interest or (Z) a sale of the Selling Member’s Company Interest to the Replacement Purchaser is not approved and (II) the Selling Member elects to continue its attempt to sell its Company Interest, the Selling Member and the remaining Members will engage an independent third party appraiser (“ Appraiser ”) to determine the Market Value of the Selling Member’s Company Interest. In the event the Members do not agree on the Market Value set by the Appraiser of the Selling Member’s Company Interest, either Member may elect to resolve the dispute in accordance with Article XVI hereof.

(c)  Upon failure of the Disposition procedures outlined in Sections 12.4(a) and (b) , the remaining Members shall have the option to either: (i) purchase the Selling Member’s Company Interest for a purchase price equal to such remaining Members’ per capita share of the lesser of (x) the fair Market Value determined by the Appraiser or (y) the lowest third party written offer previously presented to the remaining Members by the Selling Member or (ii) dissolve the Company. Unless the remaining Members elect to purchase the Selling Member’s Company Interest pursuant to Section 12.4(c)(i) or the Selling Member elects to discontinue the sale of its Company Interest pursuant to Section 12.4(d), the Members hereby unanimously and expressly agree in advance to dissolve the Company pursuant to Section 12.4(c)(ii) .

(d)  A Selling Member that (i) elects to sell its Company Interest pursuant to this Section 12.4 and presents a third party offer shall be entitled to discontinue its effort to sell its Company Interest at any time. However, in the event of discontinuance of its attempt to sell its Company Interest, such Member shall not be entitled to attempt to sell its Company Interest again pursuant to this Section 12.4 during a period of one hundred eighty (180) days beginning on the day it elects in writing to the other Members to discontinue its attempt to sell its Company Interest.

12.5 Changes In Control .

(a)  In the event a Member experiences a Change in Control (an “ Affected Member ”), each of the other Members (each a “ Non-Affected Membe r”) shall have the following options:

(1) if the Affected Member is GNGC, Piedmont shall have the option to (A) acknowledge the Change in Control and remain a Member or (B) cause GNGC to purchase Piedmont’s entire Company Interest, each in accordance with the procedure provided in this Section 12.5 ; or

(2) if the Affected Member is Piedmont, GNGC shall have the option to either: (A) acknowledge the Change in Control and remain a Member or (B) purchase Piedmont’s entire Company Interest; provided that (C) Piedmont shall also have the right to cause GNGC to purchase Piedmont’s entire Company Interest, all in accordance with the procedure provided in this Section 12.5 .

 

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(b) Each Non-Affected Member may exercise its options independently of the other Non-Affected Members, if any. The Affected Member shall give signed written notice of the proposed Change of Control transaction to the Non-Affected Members no later than contemporaneously with public announcement of the Change in Control, and in no event less than thirty (30) days prior to consummation of such Change in Control. The Non-Affected Member (or the Affected Member in the event of Piedmont’s option pursuant to paragraph 2(C) above) shall give the other Members (or the acquirer of the Affected Member, as applicable) signed written notice (the “ Option Notice ”) of the option it has chosen pursuant to Section 12.5(a) within forty-five (45) days of the date of notice of the Change of Control. If the Non-Affected Members (or the Affected Member in the event of Piedmont’s option pursuant to paragraph 2(C) above) have chosen option (B)  in paragraph (1)  above, or options (B)  or (C)  in paragraph (2)  above, each as applicable, the Option Notice must contain the sale/purchase price for the Member’s entire Company Interest, which purchase price shall be equal to the Market Value of such Company Interest determined as of the date of the announcement of any such Change in Control. If there is a disagreement regarding the Market Value proposed as the purchase/sale price for the respective Company Interest, any Member, within twenty (20) days from its receipt of the Option Notice, may initiate the Dispute Resolution Procedures provided in Article XVI hereof to determine the appropriate Market Value for the respective Company Interest. Any sale of the Member’s Company Interest shall be made pursuant to a Conveyance and Assignment Agreement substantially in the form of Exhibit H hereto.

Any election by a Non-Affected Member made pursuant to this Section 12.5 (signed and written as specified above) is irrevocable.

(c)  The consummation of any agreement or exercise of right to sell or purchase a Member’s Company Interest shall be subject to the consummation of the Change in Control. In the event that a disposition pursuant to this Section 12.5 is terminated because the Change in Control was not consummated, the Affected Member shall bear (and refund and reimburse the Company and the other Members as appropriate) one hundred percent (100%) of all third party costs (including fees for consultants, accountants, attorneys and other experts) incurred by Company and the Members in connection with the terminated disposition.

(d)  In the event the Non-Affected Member elects to consent to the Change in Control, the Affected Member, or any successor Person created as a result of the Change in Control, shall retain its Company Interest.

12.6      Withdrawal from Company .  Upon a transfer of a Member’s entire Company Interest in accordance with this Article XII , such Member (the “ Withdrawing Member ”) shall be deemed to have withdrawn as a Member and shall have no further rights or obligations as a Member under this Company Agreement, except those obligations set forth under Section 7.2 , Section 15.9 and Section 12.7 . Nothing in this Section 12.6 shall alter a Member’s obligations set forth in Section 6.1 . Other than as set forth herein, no Member shall be entitled to withdraw from the Company.

12.7      Transition Costs .  In the event of a transfer of a Member’s entire Company Interest in accordance with this Article XII , and the Company’s use of service marks and trade names licensed by the Withdrawing Member or an Affiliate to the Company ceases upon the

 

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Member’s withdrawal from the Company, the Withdrawing Member shall reimburse the Company for all direct costs reasonably incurred by the Company in connection with its discontinuance of use of the service marks and trade names, including, for example, costs incurred in connection with the changing of signs and Company stationary and revising existing advertisements.

ARTICLE XIII

Dissolution and Winding Up

13.1      Dissolution . The Company shall be dissolved and its affairs wound up upon the first to occur of the following events (“ Dissolution Event ”):

(a) the unanimous written consent of all of the Members;

(b) an event which makes it unlawful for the Company business to be continued;

(c) the sale or disposition of all or substantially all of the Company’s assets and properties; or

(d) the entry of a decree of judicial dissolution under Section 18-802 of the Act.

13.2      Effect of Dissolution .

(a) Upon dissolution, the Company shall cease carrying on as distinguished from winding up the Company business; however, the Company is not terminated, but continues until the winding up of the affairs of the Company is completed and the certificate of cancellation has been issued by the Secretary of the State of Delaware. The Liquidating Trustee shall in an orderly manner wind up the affairs of the Company and make an accounting of the Capital Account of each Member and of the Company assets, liabilities and operations from the date of the last previous accounting to the date of such dissolution.

(b) In the event of dissolution, the Members shall in good faith, and for a period of no less than thirty (30) days, attempt to negotiate and agree upon a method of dissolution of the Company in an effort to minimize the losses or other adverse effects normally attendant to such an event (the “ Negotiated Dissolution ”). In such efforts, and without limiting any other appropriate considerations, the Members acknowledge and agree that they shall consider the costs and benefits (tax-related and otherwise) of no fewer than the following two alternatives:

(1) selling the Company (or its assets) in whole, thereby converting the Company (or its assets) to cash for the purposes of winding up the Company and distributing the remaining cash to the Members (a “ Company Sale ”); or

(2) distributing the Company’s assets to the Members in such a manner as the Members may agree, and in so doing, cause such distributions to be tax-free, or tax favorable, under 1R Section 731, and other applicable law (a “ Tax Advantaged Distribution ”). In connection with a Tax Advantaged Distribution, the Members shall consider distributing the Company’s assets to the Members on such basis as is appropriate, including on a state-by-state basis, relative to the principal service territory of the Members’ Affiliates (e.g. North Carolina with respect to Piedmont and Georgia and Illinois with respect to GNGC).

 

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(c) If the Members are unable to agree upon an Negotiated Dissolution, the Members shall engage an investment bank agreeable to each Member (or, in the absence of such agreement, each Member shall select an investment bank and the banks so selected shall agree upon a third party bank) to serve as Liquidating Trustee hereunder (such investment bank being referred to herein as the “ Auctioneer ”). The Auctioneer shall be obligated to auction the Company in an “open” auction (the “ Auction ”) in compliance with the principles and procedures set forth below (the “ Auction Procedures ”). Consistent with the Auction Procedures, the Auctioneer shall be instructed to maximize and seek the highest value of the distributions that ultimately will be made to the Members upon completion of the dissolution (the “ Value Maximization Principle ”). In attempting to achieve the Value Maximization Principle, the Auctioneer may, in its prudent professional judgment, auction the Company in its totality or, alternatively, auction the Company’s constituent components on a state-by-state (or territory-by-territory) basis.

(d) To the extent a Member or any Affiliate of a Member desires to participate, directly or indirectly, as a bidder in the Auction, notice of such intent shall be given to each Member as well as to each participant in the Auction. Proper notice of such participation shall be a condition to a Member’s (or Affiliate’s) participation in the Auction. The Auctioneer shall be charged with taking such steps as it deems appropriate to ensure that all bidders are bona fide bidders with the financial resources (or financing) available to consummate the acquisition. Except as provided in Section 13.2(f) , the consideration offered in all bids considered by the Auctioneer shall be cash or cash equivalents payable in immediately available funds, and such bids shall offer a firm purchase price which is not contingent on “earn-out” or related concepts.

(e) The Auction shall be structured as a “sequential” auction with each bidder given an opportunity, and a finite period of time (e.g., 6 hours) to exceed the then-current highest bid. When any participant makes a bid in the Auction, the amount and identity of such bidder shall be made known by the Auctioneer to each other participant. Once a bid is made, it shall be irrevocable unless and until a higher bid is thereafter made. All participants will always be given the opportunity to make a higher bid and notice that (with respect to each bid that may be accepted by the Auctioneer), unless a higher bid is tendered within a finite period of time, the Company will be sold at the then-current highest bid.

(f) If a Member is a successful bidder, it may, at its option, elect to (i) pay the purchase price amount offered in the successful bid to the Company in cash or cash equivalents or (ii) receive the assets for which it has successfully bid as an in-kind distribution from the Company pursuant to Section 13.3 hereof.

13.3      Distribution of Assets on Dissolution .  Upon the winding up of the Company, the Company Property shall be distributed:

(a) to creditors, including Members who are creditors (other than by reason of the operation and effect of Section 18-601 or Section 18-604 of the Act) to the extent otherwise permitted by law, in satisfaction of the Company’s liabilities; and then

 

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(b)  to the establishment of any reserves which the Liquidating Trustee may deem reasonably necessary for any contingent or unforeseen liabilities or obligations of the Company arising out of or in connection with the Company. Such reserves may be paid over by the Liquidating Trustee to an agent, as escrowed, to be held by him for the purpose of disbursing such reserves in payment of any of the aforementioned contingencies, and, at the expiration of such period as the Liquidating Trustee shall deem advisable, for distributing the balance thereafter remaining in the manner hereinafter provided; and then

(c)  to Members in satisfaction of liabilities for distributions; and then

(d)  to Members to the extent of and in proportion with their respective positive Capital Account balances; and then

(e)  the remainder, if any, to the Members in proportion to their respective Company Interests as in effect at the moment of the Dissolution Event.

Distributions under this Section 13.3 shall be in cash or in-kind as determined by the provisions set forth in this Article XIII . All of the Members shall endeavor to facilitate Tax Advantaged Distributions to each of the other Members.

13.4      Winding Up and Certificate of Cancellation . The winding up of the Company shall be completed when all debts, liabilities, and obligations of the Company have been paid and discharged or reasonably adequate provision therefore has been made, and all of the remaining property and assets of the Company have been distributed to the Members. Upon the completion of winding up of the Company, a certificate of cancellation shall be delivered by the Liquidating Trustee to the Secretary of the State of Delaware for filing. The certificate of cancellation shall set forth the information required by the Act.

13.5      Termination . A reasonable time shall be allowed for the orderly liquidation of the assets of the Company and the discharge of liabilities to creditors so as to enable the Liquidating Trustee to minimize the normal losses attendant upon a liquidation. Each of the Members shall be furnished, by the Liquidating Trustee, with a statement setting forth the assets and liabilities of the Company as of the date of complete liquidation. Upon compliance with the distribution plan set forth in Section 13.3 (including payment over to the agent-escrowee if there are sufficient funds therefore), the Company shall terminate.

13.6      Use of Company Identity .

(a)  In the event of the dissolution of the Company, any Member shall be entitled to purchase from the Company and its Subsidiaries the exclusive rights to all trade names, trademarks or service marks owned by the Company or its Subsidiaries, as well as all related logos, addresses, telephone numbers and similar forms of identification (such items referred to collectively as the “ Trade Name ”) in accordance with the following procedure. In the event only one (1) Member desires to purchase the Trade Name, the Members shall attempt to negotiate acceptable terms and conditions. If the Members are unable to reach agreement, the Members shall initiate the dispute resolution process detailed in Article XVI . The proceeds of the purchase of the Trade Name shall be distributed in accordance with Section 13.3 .

(b) In all other cases relating to dissolution, unless the Members agree otherwise in a signed written agreement approved by the Executive Committee, no Member or Affiliate

 

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shall use the Trade Name or Company trademarks, trade names, service marks (or any deceptively similar trademarks, trade names or service marks), telephone numbers or addresses owned by the Company or its Subsidiaries, for twenty-four (24) months after the dissolution of the Company.

ARTICLE XIV

Amendment

14.1      Amendment .  This Company Agreement may be amended or modified from tune to time only by a written instrument (including, without limitation, any Admission Agreement) unanimously adopted by the Members. No Member shall have any vested rights in this Company Agreement which may not be modified through an amendment to this Company Agreement.

ARTICLE XV

Miscellaneous Provisions

15.1      Entire Agreement .  This Company Agreement, along with the exhibits attached hereto, as may be amended from time to time, represents the entire agreement with respect to the subject matter hereof among all the Members and between the Members and the Company.

15.2      Successors and Assigns .  Subject to the provisions on Disposition set forth herein, this Company Agreement shall bind and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

15.3      Governing Law .  THIS COMPANY AGREEMENT SHALL BE GOVERNED BY AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF DELAWARE. WITH RESPECT TO ANY PROCEEDING RELATING TO THIS COMPANY AGREEMENT, EACH MEMBER IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF DELAWARE AND THE UNITED STATES DISTRICT COURT LOCATED IN THE STATE OF DELAWARE, AND WAIVES ANY OBJECTION WHICH IT MAY HAVE TO THE LAYING OF VENUE OF ANY PROCEEDING BROUGHT IN ANY SUCH COURT AND WAIVES ANY CLAIM THAT SUCH PROCEEDING HAS BEEN BROUGHT IN AN INCONVENIENT FORUM.

15.4      Notices . All notices required or permitted to be given or made under this Company Agreement shall be given or made in writing. Such notices shall be delivered by hand delivery, by facsimile or similar electronic means (including e-mail followed immediately by original), by nationally recognized overnight courier, or by certified or registered mail, return receipt requested, addressed as set forth in Exhibit B or any amendment thereto. Any party may change its address for the purpose of this Section 15.4 by notice to the other(s) given in the manner set forth above.

15.5      Right of Creditors and Third Parties under Company Agreement . This Company Agreement is entered into among the Company and the Members for the exclusive benefit of the Company, its Members, and their successors and permitted assignees. This Company Agreement is expressly not intended for the benefit of any creditor of the Company or any other Person (other than any Person with a right to indemnification under Section 6.9 ). Except and only to the extent provided by applicable statute, no such creditor or third party shall have any rights under this Company Agreement or any agreement between the Company and any Member with respect to any Capital Contribution or otherwise.

 

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15.6      No Action for Partition .  No Member shall have any right to maintain any action for partition with respect to the Property of the Company.

15.7      Title to Company Property .  Title to Company Property shall be held in the name of the Company or its nominee.

15.8      Company Funds . Company funds shall be deposited in one (1) or more accounts with a bank or banks located within the United States and approved by the Executive Committee. Pending use in the business of the Company or distribution to the Members, the funds of the Company may, in the discretion of the Executive Committee, be deposited in a bank account or accounts, or invested in such interest-bearing taxable or nontaxable investments, including without limitation, checking and savings accounts, certificates of deposit and time or demand deposits in commercial banks, U.S. government securities, securities guaranteed by U.S. government agencies, bankers’ acceptances, Eurodollar deposits and notes, both fixed rate and floating securities issued by money market mutual funds, savings and loan association deposits, deposits in members of the Federal Home Loan Bank System, or commercial paper, rated A-i or better by Standard & Poor’s Corporation or Prime-i or better by the Moody’s Commercial Paper Division of Moody’s Investor Services, Inc., or the successor to either of them, provided that the Executive Committee shall not cause the Company to make any such deposits or investments that have a remaining maturity of more than one (1) year or that would require registration of the Company under the Investment Company Act of 1940. Such funds shall not be commingled with funds of any other Person.

15.9      Confidentiality .  Except as hereinafter provided, the Company, its Subsidiaries, and each Member (a) shall treat as confidential and not disclose to any unauthorized third party (including a Member’s employees or Affiliates who have no need to know) any confidential information obtained either directly or indirectly from any other Member pursuant to this Company Agreement, or confidential information developed or acquired on behalf of the Company or its Subsidiaries by the Executive Committee or the Company’s Officers or employees (collectively “ Confidential Information ”), and (b) shall not use any such Confidential Information for any purpose other than in connection with the activities of the Company or its Subsidiaries pursuant to this Company Agreement. The limitations in this Section 15.9 shall not apply to the extent Confidential Information: (i) was already in the possession of the receiving Member, or its Affiliate, at the time it obtained such Confidential Information; (ii) was or is published or otherwise is or becomes generally available to the public through no fault of such receiving Member, or its Affiliate; (iii) was or is lawfully made available to such Member or its Affiliate without restriction by any Person which is not bound by an obligation of confidentiality or use with respect to the information; (iv) was or is independently developed by such Member or its Affiliate; or (v) is required to be disclosed by operation of law or regulation, required in any Proceeding, requested by a regulatory body (including any securities and commodities exchanges) and the disclosing Member deems it advisable, in its discretion, to comply with the request, or is deemed advisable to be disclosed in the good faith judgment of the disclosing Member in any Proceeding. In the event disclosure is required or requested, the disclosing Member shall exercise all reasonable efforts to disclose such Confidential Information pursuant to a confidentiality agreement or protective order. The Members and the Executive Committee shall establish and enforce reasonable procedures for the protection of Confidential Information

 

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and shall restrict disclosure of such Confidential Information to those of the Company’s employees, Officers, agents, and Affiliates of each Member and the Company (including its Subsidiaries) who need to know such Confidential Information in connection with their functions and the purposes of the Company and its Subsidiaries as set forth herein. Each Member and the Executive Committee shall take such reasonable and prudent steps and precautionary measures as may be required to ensure compliance with this Section 15.9 by such of their or the Company’s employees, Officers, agents, Affiliates and other Persons as shall be given access to such Confidential Information and shall be responsible for compliance by its employees, officers, agents and Affiliates. Nothing in this Section 15.9 shall be construed to prohibit a Member’s disclosure to its attorneys, auditors, or other consultants, provided such attorneys, auditors or other consultants are advised of this Section 15.9 and agree to be bound thereby.

15.10      Transaction Costs . Each Member shall bear and pay its own transaction costs relating to the negotiation and execution of this Company Agreement.

15.11     Severability . If any provision of this Company Agreement is determined to be invalid, illegal or otherwise unenforceable for any reason by a court of competent jurisdiction, the remaining terms and conditions of this Company Agreement shall remain in full force and effect to the fullest extent permitted by law. In such an event, the Members agree to make a good faith effort to renegotiate the affected provisions.

ARTICLE XVI

DISPUTE RESOLUTION PROCEDURES

16.1      Process

(a)  In the event of any dispute or controversy arising under the Company Agreement (“ Dispute ”) as to the “fair market value” of any Property or asset, the Market Value of a Company Interest or Property of any Member or the Company, or the Option Purchase Price (the “ Disputed Asset ”) or other value, such Dispute shall be resolved pursuant to the terms hereof (the “ Dispute Resolution Procedures ”). Such process shall be initiated by written notice from one (1) Member involved in the Dispute to the other Members.

(b)  Within ten (10) business days of notice of initiation of the Dispute Resolution Procedures, each disputing Member shall simultaneously disclose to the other in writing the amount in dollars representing the amount it believes is the appropriate value of the Disputed Asset (the “ Fair Market Amount ”) as established by the terms hereof or any other agreement between the parties, if any. Except in the case of the Option Purchase Price, each Member shall determine its Fair Market Amount on the assumption that it would be paid or pay the other Member, the Company or any third party, as applicable, in cash on the first day of the first calendar month which is at least ten (10) days after the date that such Fair Market Amounts are simultaneously exchanged (such assumed date of payment being hereinafter called the “ Assumed Payment Date ”). During the fifteen (15) days following the exchange of Fair Market Amounts as aforesaid, the Members shall attempt to resolve the difference between their respective Fair Market Amounts so as to avoid the delay and expense of the arbitration procedure hereinafter set forth.

 

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16.2   If the Members are unable to agree to a settlement within the aforesaid fifteen- (15) day period, then copies of both Fair Market Amounts, exactly as originally exchanged by the parties, with no improvement, adjustment or amendment whatsoever, shall be placed in one (1) sealed envelope to be held by an appointed independent third party for ultimate submission to an unaffiliated accounting firm, investment banking firm or other valuation expert (the “ Dispute Appraiser ”) selected in accordance with the procedure set forth in Section 16.3 .

16.3   At the option of any Member involved in the Dispute, the Dispute may be submitted for resolution to a Dispute Appraiser. The Members shall have ten (10) business days upon the exercise of this option to mutually agree on the identity of the Dispute Appraiser for the Dispute. If the Dispute Appraiser initially selected declines to accept such engagement, the Members shall agree on another third party as the Dispute Appraiser. If the Members are unable to agree upon a Dispute Appraiser to so act within ten (10) business days, either Member may elect that the CPR Institute for Dispute Resolution make such a selection.

16.4         The Dispute Appraiser shall be instructed to independently determine the appropriate value of the Disputed Asset (the “ Proper Amount ”) on the assumption that such Proper Amount was paid or contributed in cash on the Assumed Payment Date. The Proper Amount shall be determined by the Dispute Appraiser based on his or her findings of facts and conclusions of law applicable to the Dispute without any knowledge of the Fair Market Amounts, which amounts each Member agrees to keep confidential. Neither Member shall, prior to the Dispute Appraiser’s determination of the Proper Amount, directly or indirectly disclose to the Dispute Appraiser, in its submissions to the Dispute Appraiser or otherwise, its or the other Member’s Fair Market Amount (although each Member may submit to the Dispute Appraiser evidence and other support for the amount which such Member claims to be the Proper Amount so long as it does not disclose to the Dispute Appraiser the extent to which such claimed Proper Amount differs from its or the other Member’s Fair Market Amount). Each Member agrees that it shall, and shall cause the Company to, make available to the Dispute Appraiser all relevant books and records relating to the Disputed Asset and all other information requested by the Dispute Appraiser.

16.5      The Dispute Appraiser shall notify the parties in writing of its determination of the Proper Amount within thirty (30) days or such later practicable date of the receipt of the Dispute. Promptly thereafter, the Members shall deliver to the Dispute Appraiser the Fair Market Amounts determined by each of them and authorize the Dispute Appraiser to review the Fair Market Amount of each Member. The Dispute Appraiser will promptly thereafter deliver to each Member its written report containing (a) the Dispute Appraiser’s determination of which of the two (2) Fair Market Amounts is closer to the Proper Amount, which closer Fair Market Amount shall be the awarded amount, and (b) a certification that the Dispute Appraiser did not, before determining the Proper Amount, obtain from either Member or any other source, directly or indirectly, knowledge of either Member’s Fair Market Amount. The Members hereby agree that the Dispute Appraiser’s conclusion shall be conclusive and binding on the Members. Any purchase, sale, contribution or other action related to or conditioned upon the resolution of the Dispute shall be consummated within five (5) business days of the Dispute Appraiser’s decision or such later date as the Members may mutually agree and shall be based upon the awarded amount selected by the Dispute Appraiser.

 

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16.6      The fees of the Dispute Appraiser and the other costs and expenses, including attorneys’ and other similar expenses, of the arbitration proceeding shall be borne by the Member which submitted the Fair Market Amount which differs the most from the Proper Amount determined by the Dispute Appraiser.

IN WITNESS WHEREOF, the Current Members have caused their authorized officers to sign this Company Agreement as of the date first written above.

 

PIEDMONT ENERGY COMPANY

By: /s/ Karl W. Newlin

Name:  Karl W. Newlin

Title: Senior Vice President

GEORGIA NATURAL GAS COMPANY

By: /s/ Andrew W. Evans

Name:  Andrew W. Evans

Title:  Executive Vice President and Chief Financial Officer

 

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EXHIBIT A

 

 

FIRST AMENDED AND RESTATED

SERVICES AGREEMENT

BETWEEN

AGL SERVICES COMPANY

(PROVIDER)

AND

SOUTHSTAR ENERGY SERVICES LLC

(CUSTOMER)

 

Dated as of September 1, 2013


FIRST AMENDED AND RESTATED SERVICES AGREEMENT

This FIRST AMENDED AND RESTATED SERVICES AGREEMENT (“ Agreement ”) is made and entered into and is effective as of September 1, 2013, by and between SouthStar Energy Services LLC (“ SouthStar ”), a Delaware Limited Liability Company, and AGL Services Company (“ AGLSC ”), a corporation organized under the laws of the State of Georgia, both SouthStar and AGLSC sometimes referred to herein collectively as “ Parties ” or singularly as “ Party .”

WHEREAS, SouthStar and its members (“ Members ”), Georgia Natural Gas Company (“ GNGC ”) and Piedmont Energy Company (“ Piedmont ”) desire, and AGLSC has agreed to provide, certain administrative, management and support services (“ Services ”) to and on behalf of SouthStar;

WHEREAS, this Agreement amends, restates, supercedes and terminates that certain Services Agreement dated March 31, 2004 previously entered into between SouthStar and AGLSC;

WHEREAS, pursuant to this Agreement, and in accordance with Schedule A , SouthStar is expected to incur costs in connection with AGLSC’s performance of such Services;

WHEREAS, in connection with Services provided hereunder, AGLSC is unconditionally obligated at the end of the Term hereof to discontinue all or a portion of the Services, which are subject to this Agreement;

WHEREAS, AGLSC acknowledges that it is paramount in its role as service provider on behalf of SouthStar, that, during the Term hereof, it take no action nor omit to take any action, the result of which would impair or adversely affect SouthStar’s ability to conduct its retail marketing business;

NOW, THEREFORE, in consideration of the mutual agreements, covenants, and conditions herein contained, SouthStar and AGLSC hereby agree as follows:

ARTICLE 1. DEFINITIONS

As used in this Agreement, the following terms shall have the following meanings:

Affiliate ” means, with respect to any Person (hereinafter defined), any other Person that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with such Person. The term “ control ” (including the correlative terms, “controlled by” and “under common control with”) as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through ownership of voting securities, by contract or otherwise.

AGLSC ” shall have the meaning assigned to such term in the preamble.

Agreement ” shall have the meaning assigned to such term in the preamble.

 

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Assumed Liabilities ” means any liabilities or obligations arising under or pursuant to the Services identified in Article 3 below that either (a) arise or are attributable to acts or omissions occurring during the Term or (b) arise as a result of any breach of AGLSC of this Agreement.

Business Day ” means a day on which the majority of the Federal Reserve member banks in New York City are open for business.

Confidential Information ” means trade secrets, patentable or non-patentable inventions and ideas, know-how, formulae, processes, designs, sketches, plans, drawings, specifications, reports, projections, plant and equipment expansion plans, lists of employees and suppliers, monetizing techniques and strategies, commodity and derivative hedging and trading strategies and techniques, financial statements and other financial data, pricing information, cost and expense information, product development, strategic and marketing plans and all other information, data and experience of any kind whatsoever, whether technical, marketing or financial, regarding the business, facilities and operations of SouthStar and its Affiliates or of AGLSC and its Affiliates, as the case may be, whether oral, written or electronic. “Confidential Information” also shall be deemed to include all notes, analyses, compilations, studies, interpretations and other documents or electronic recording, which reflect Confidential Information furnished pursuant to the terms of this Agreement, or any transaction contemplated hereby or thereby. The term “Confidential Information” shall not include information which a recipient can demonstrate (a) is or becomes generally available to the public other than as a result of disclosure by the recipient; (b) was within the recipient’s possession prior to it being furnished by or on behalf of the other Party, provided that the source of such information was not known by the recipient to be bound by a confidentiality agreement with, or other contractual legal or fiduciary obligation of confidentiality to, the disclosing party or any other party with respect to such information; (c) becomes available to the recipient on a non-confidential basis from a source other than the disclosing party or any of its representatives (a “ Representative ”), provided that such source is not known by the recipient to be bound by a confidentiality agreement with, or other contractual, legal or fiduciary obligation of confidentiality to, the disclosing party or any other party with respect to such information; or (d) was independently developed by the recipient without reference to the Confidential Information, provided that such independent development can reasonably be demonstrated by the recipient. The term “ recipient ”, as used in this Agreement, refers to the Person (hereinafter defined) receiving any item of Confidential Information and the Affiliates of such Person. The term “Representative” shall include officers, directors, employees and representatives of a Party or its Affiliates.

Consequential Damages ” shall have the meaning assigned to such term in Section 6.4 .

Contract Year ” shall mean a twelve (12) month period commencing January 1 and ending the following December 31, provided that the initial Contract Year shall commence on the date that this Agreement becomes effective and end on the following December 31.

Dispute ” shall have the meaning assigned to such term in Section 3.3(a) .

Excluded Liabilities ” mean any liabilities or obligations that either (a) do not arise under or relate to the Services identified in Article 3 below; (b) arise or are attributable to acts or omissions occurring at a time other than during the Term; or (c) arise as a result of any breach by SouthStar of this Agreement other than a breach attributable to an action taken by SouthStar at AGLSC’s direction.

 

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Executive Committee ” shall mean the Executive Committee of SouthStar as established according to the LLC Agreement.

GNGC ” shall have the meaning assigned to such term in the recitals.

GPSC ” means the Georgia Public Service Commission or any successor state agency.

Governmental Authority ” means any nation, state, sovereign or government; any federal, regional, state, local or political subdivision; and any entity exercising executive, legislative, judicial, regulatory, or administrative functions of or pertaining to government, including without limitation the GPSC and the FERC.

Key Manager(s) ” means the personnel selected by AGLSC and SouthStar, which personnel is responsible for managing the Services provided by AGLSC to SouthStar hereunder. Key Managers may be either employees of AGLSC or Service Personnel.

LLC Agreement ” means the Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC as amended and restated.

Members ” shall have the meaning assigned to such term in the recitals.

Party ” or “ Parties ” shall have the meaning assigned to such term in the preamble.

Person ” means an individual, corporation, partnership, joint venture, limited liability company, trust, university, unincorporated organization, or government or any agency or political subdivision thereof.

Piedmont ” shall have the meaning assigned to such term in the recitals.

Representative ” shall have the meaning assigned to such term in the definition of “Confidential Information.”

Service Personnel ” means SouthStar’s employees/contractors who are providing Services to SouthStar.

Services ” shall have the meaning assigned to such term in the recitals.

SouthStar ” shall have the meaning assigned to such term in the preamble.

Term ” shall have the meaning assigned to such term in Section 2.4 .

ARTICLE 2. TERMS AND CONDITIONS

2.1         Services .    AGLSC will perform Services described in Section 3.1 and other services which would be generally common and ancillary to such Services or otherwise in AGLSC’s reasonable discretion. At the direction of the Executive Committee, AGLSC expressly and unconditionally agrees that any and all Services contemplated hereunder may be bid out to, awarded and/or provided by third parties other than AGLSC.

 

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2.2         Reimbursement of Certain Charges .  SouthStar shall pay quarterly an amount to AGLSC for the provision of such Services based on the attached Schedule A . AGLSC will reimburse SouthStar quarterly for expenses (equal to base salary plus allocated costs of employee benefits plus target bonus of the Service Personnel), if any, that SouthStar has incurred in the previous quarter for the employment of Service Personnel who have provided Services to SouthStar and which Services are the responsibility of AGLSC hereunder. The quarterly reimbursement by AGLSC will equal the sum of: (1) the expenses (base salary plus allocated costs of employee benefits plus target bonus, as applicable) of each Service Personnel for the previous quarter multiplied by (ii) the proportion of such Service Personnel’s time (based on a 40 hour work week) expended on providing Services to SouthStar during the prior quarter (if less than 100%, excluding scheduled employee leave time, holidays, vacation, etc.).

2.3         Billing and Payment .  By the fifteenth (15 th ) calendar day of each January, April, July, and October, each Party shall render to the other a statement for services or reimbursement, as applicable, provided for the preceding quarter. Each Party shall make payment (or credit) within thirty (30) days of receipt of each such statement, which payments and credits may be netted by the Parties to their convenience.

2.4         Term .  The term of this Agreement (the “ Term ”) shall commence on September 1, 2013 and shall extend from year to year thereafter or until terminated by the unanimous vote of SouthStar’s Executive Committee.

ARTICLE 3. SERVICES

3.1         Services to be Performed .  AGLSC will provide personnel (or reimburse SouthStar for Service Personnel, as applicable) to perform the Services listed below, as well as ancillary services that are consistent with providing those listed Services. AGLSC agrees that the Services provided hereunder will be performed in a professional manner and will be of professional quality consistent with industry standards and the scope, quality and level of Services that AGLSC provides to its other Affiliates.

(a)         Accounting and Tax Services .    AGLSC will provide all accounting and tax services required by SouthStar. This will include the quarterly production of financial statements suitable to the Members and their respective auditors. This will also include management reporting as required by SouthStar’s Members. Tax Services will include the preparation and payment for all property and transaction tax returns, oversight of all tax audits, completion of tax research and advice regarding new tax matters.

(b)         Internal Audit .    AGLSC will provide internal audit services that are consistent with those practices required by the Members and will provide an annual plan and report on performance against this plan to SouthStar’s Executive Committee.

(c)         Information Technology .    AGLSC will provide information technology (IT) services; provided however that AGLSC will make final decisions on the provision of such Services in its reasonable discretion. Investments in new IT systems, IT system deployments or system upgrades shall be authorized and approved pursuant to the provisions of the LLC Agreement and the Exhibits and Policies thereto.

 

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(d)         Human Resources .    AGLSC will provide human resources support services, including payroll processing, employee benefits services, support with the recruitment for new employees and any other related human resources support that SouthStar reasonably requests; provided however that AGLSC will make final decisions on the provision of such Services in its reasonable discretion.

(e)         Legal .   AGLSC will provide legal services, including legal analysis and advice related to both litigation and non-litigation matters, that are requested by SouthStar, which Services AGLSC will bill to SouthStar (in addition to amounts contemplated by Exhibit A hereto) at AGLSC’s internal costs. Cost and expense of outside legal services (which shall be procured pursuant to the terms of the LLC Agreement) shall be borne by SouthStar.

(f)         Treasury .  AGLSC will provide treasury and cash management services that are reasonably requested by SouthStar and will make recommendations to SouthStar’s Executive Committee regarding SouthStar’s capitalization and financial management. Debt incurrence will be governed by the LLC Agreement. AGLSC will report to the Executive Committee about SouthStar’s liquidity and capital requirements.

(g)         Risk Services .  AGLSC will provide risk services that are reasonably requested by SouthStar, including assuring data integrity through deal validation, executing the risk monitoring requirements specified in appropriate policies, analyzing and monitoring market and credit risk, and reporting risk data to management in compliance with appropriate policies. Such functions also include maintaining a process to ensure confirmations are sent and reviewed pursuant to contract terms, performing end-of-day valuation on hedge positions, conducting market and credit risk measurement, including value-at-risk, stress testing analysis, and mark-to-market valuation.

3.2         Personnel and Key Managers .

(a)  AGLSC shall select and assign AGLSC personnel or Service Personnel to constitute Key Managers for the purpose of managing the Services provided by AGLSC as described in Sections 3.1(a)-(g)  above. In the course of the Term, the Parties may agree that other Key Managers are necessary or reasonable for the provision of Services hereunder.

(b)  A representative of AGLSC and each of the Key Managers, who are not otherwise Service Personnel, if any, shall make themselves available no less than once a month to meet with the President of SouthStar (or other similarly situated Officer, if no President is appointed) to discuss (1) such Key Manager’s performance and the performance and expectation of Services being rendered hereunder and (2) any anticipated or forecasted events that may affect the Services.

(c)  In the event SouthStar in good faith determines that it is not in SouthStar’s best interest for a Key Manager, who is not Service Personnel, to continue in such capacity, then the President of SouthStar (or other similarly situated officer, if no President is appointed) shall give AGLSC written notice specifying the reason and requesting that such Key Manager be replaced

 

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or removed. If the removal as a Key Manager is justified and not otherwise unlawful, AGLSC shall remove and replace such Key Manager as soon as reasonably practicable or shall permit SouthStar to replace such Key Manager with Service Personnel or its own candidate, who shall be deemed a Service Personnel.

(d)  Such Key Managers may be Service Personnel or employees of AGLSC. AGLSC shall use commercially reasonable efforts to not reassign or replace any Key Manager (who is not a Service Personnel) more than once during any twelve month period unless SouthStar consents to such reassignment or replacement.

3.3         Disputes .

(a)  In the event of any dispute between the Parties regarding the provision of Services provided hereunder (“ Dispute ”), the Parties agree that such Dispute will be addressed and resolved by the procedures prescribed by this Section 3.3 .

(b)  In the event SouthStar is not satisfied with the provision of any Service hereunder (whether in the scope or quality of the Service actually provided), its President (or other similarly situated officer, if no President is appointed) shall execute a written notice detailing the nature and circumstances of SouthStar’s complaint and commercially reasonable suggestions for resolution of the Dispute within the terms provided by this Agreement. SouthStar shall provide the notice to AGLSC pursuant to the communications procedures outlined in Section 8.3 hereof. The President of SouthStar (or other similarly situated Officer, if no President is appointed) and appropriate representatives of AGLSC shall meet within seven (7) business days of AGLSC’s receipt of such notice to address the Dispute and attempt to negotiate a resolution of the Dispute within the provisions provided by the Agreement. AGLSC may invite the Key Managers responsible for the Service(s) related to the Dispute to any meeting with SouthStar to facilitate resolution. The resolution of any Dispute shall be written and signed by the President of SouthStar (or other similarly situated Officer, if no President is appointed) and appropriate officers of AGLSC.

(c)  If SouthStar and AGLSC are unable to resolve the Dispute within fifteen (15) Business Days of the first meeting between the Parties contemplated above (or such longer time as the parties may mutually agree), either Party may submit the Dispute (accompanied by a copy of SouthStar’s initial notice to AGLSC) to the Executive Committee. Any resolution negotiated and agreed upon by the Executive Committee shall be reduced to writing, adopted by consent of the Executive Committee and binding on the Parties.

(d)  In the event the Executive Committee is unable to resolve the Dispute within sixty (60) Business Days of the submission thereto, either Party, subject to the restrictions of the LLC Agreement or other governing documents, may take legal or other actions necessary to enforce its rights and obligations under this Agreement.

 

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ARTICLE 4. REPRESENTATIONS, WARRANTIES, AND ACKNOWLEDGMENTS

4.1         SouthStar Representations .  As of the date hereof, SouthStar represents and warrants as follows:

(a)        SouthStar is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware.

(b)        SouthStar has all requisite corporate power and authority to own its properties and assets and to carry on its business as currently conducted and as proposed to be conducted. SouthStar has all requisite corporate power and authority to execute, deliver and perform its obligations under this Agreement.

(c)        This Agreement has been duly authorized, executed and delivered by SouthStar and constitutes a legal, valid and binding obligation of SouthStar enforceable against it in accordance with its terms, except as such enforceability may be limited by applicable bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium or other laws from time to time in effect relating to creditors’ rights generally and to general equity principles.

(d)        The execution, delivery and performance by SouthStar of this Agreement, and all other agreements and instruments to be executed and delivered by SouthStar pursuant hereto or in connection herewith, an in compliance with the terms and provisions hereof, do not and will not (i) violate any provisions of any law, statute, rule or regulation, order, writ, judgment, injunction, decree, governmental permit, determination or award having applicability to SouthStar or any of its properties or assets; (ii) conflict with or result in a breach or violation of or constitute a default under any provision of the charter documents, bylaws or other comparable documents of SouthStar; or (iii) require any consent, approval or notice under or result in a violation or breach of or constitute (with or without due notice or lapse of time or both) a default under any note, bond, mortgage, license, contract, agreement or loan or credit agreement to which SouthStar is a party or by which SouthStar or any of its properties or assets may be bound or affected.

4.2         AGLSC Representations .    As of the date hereof, AGLSC represents and warrants as follows:

(a)        AGLSC is a corporation duly organized, validly existing and in good standing under the laws of the State of Georgia.

(b)        AGLSC has all requisite power and authority to own its properties and assets and to carry on its business as currently conducted and as proposed to be conducted. AGLSC has all requisite power and authority to execute, deliver and perform its obligations under this Agreement.

(c)        This Agreement has been duly authorized, executed and delivered by AGLSC and constitutes a legal, valid and binding obligation of AGLSC enforceable against it in accordance with its terms, except as such enforceability may be limited by applicable bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium or other laws from time to time in effect relating to creditors’ rights generally and to general equity principles.

(d)        The execution, delivery and performance by AGLSC of this Agreement, and all other agreements and instruments to be executed and delivered by AGLSC pursuant hereto or in connection herewith, and in compliance with the terms and provisions hereof, do not and will not (i) violate any provisions of any law, statute, rule or regulation, order, writ, judgment, injunction,

 

50


decree, governmental permit, determination or award having applicability to AGLSC or any of its properties or assets; (ii) conflict with or result in a breach or violation of or constitute a default under any provision of the charter documents, bylaws or other comparable documents of AGLSC; or (iii) require any consent, approval or notice under or result in a violation or breach of or constitute (with or without due notice or lapse of time or both) a default under any note, bond, mortgage, license, contract, agreement or loan or credit agreement to which AGLSC is a party or by which AGLSC or any of its properties or assets may be bound or affected.

(e)        AGLSC acknowledges and agrees that AGLSC shall neither take nor omit to take any action the taking or omission of which will directly impair or adversely affect the discharge of any of SouthStar’s obligations to customers or suppliers; cause SouthStar to breach any contract to which it is a party or by which it is bound; or cause SouthStar to violate any law or regulation to which it is subject.

(f)        The Parties agree that the provision of Services hereunder, and the conduct of each Party ancillary and related hereto, shall be in compliance with the provisions of OCGA § 46-4-159.

ARTICLE 5. TERMINATION OF AGREEMENT

5.1         Early Termination .  In addition to the termination rights set forth in Section 2.4 hereof, either Party may terminate this Agreement if existing federal, state and local regulatory rules, regulations or policies that serve as the basis for the Services described in this Agreement shall be modified, or authorization for the terms hereof is withheld in any manner that would be reasonably likely to have a material adverse affect on such Party or the benefits it anticipates deriving from the Services contemplated by this Agreement.

5.2         Notice of Early Termination .  A Party intending to terminate this Agreement pursuant to Section 5.1 shall give written notice of its intention to terminate and the reasons therefore to the other Party, which termination shall be effective no earlier than the thirtieth (30 th ) day following the receipt of said notice, whereupon the terminating Party shall be excused and relieved of all obligations and liabilities under this Agreement, except for those obligations incurred before the effective date of termination or as a result of termination. Each Party shall use every reasonable effort to mitigate any damages resulting from a breach and/or termination of this Agreement.

ARTICLE 6. INDEMNIFICATION

6.1         Indemnification Obligations of SouthStar .    Subject to Section 6.3 , SouthStar shall indemnify and hold harmless AGLSC and its Affiliates and each of their respective Representatives from and against any claim, liability, loss, cost, damage or expense (including, without limitation, reasonable attorneys’ fees, charges and disbursements) made against such indemnified party by third parties arising out of, or resulting from or in any way related to (a) the breach of or failure to perform or satisfy any of the representations, warranties or covenants made by SouthStar in this Agreement, or (b) any Excluded Liability.

6.2         Indemnification Obligations of AGLSC .  Subject to Section 6.3 , AGLSC shall indemnify and hold harmless SouthStar and its Affiliates and each of their respective Representatives from and against any claim, liability, loss, cost, damage or expense (including, without limitation,

 

51


reasonable attorneys’ fees, charges and disbursements) made against such indemnified party by third parties arising out of, resulting from or in any way related to (a) the breach of or failure to perform or satisfy any of the representations, warranties or covenants made by AGLSC in this Agreement, or (b) any Assumed Liability.

6.3         Third Party Claims .  With respect to claims made by third parties, the indemnifying party shall have the right to assume the defense of any such claim or action with counsel designated by the indemnifying party and reasonably satisfactory to the indemnified party. No indemnified party shall settle any claim or action with respect to which it has sought or intends to seek indemnification pursuant to this Article 6 without the prior written consent of the indemnifying party, which consent shall not be unreasonably withheld.

6.4         No Consequential Damages .  Subject to the last sentence of this Section 6.4 , neither Party shall be liable to the other Party or its Affiliates for consequential, incidental, indirect, punitive or special damages (collectively, “ Consequential Damages ”) resulting from any cause whatsoever, including without limitation, any loss of profits, sales or goodwill, loss of any other claim whether arising out of or relating to this Agreement, and each Party hereby releases the other Party from any liability for all such losses and damages. It is expressly agreed that no failure by either Party to fulfill any condition of this Agreement shall constitute a failure of essential purpose entitling either Party to seek Consequential Damages. Nothing in this Section 6.4 shall be deemed to prohibit an indemnified party from obtaining reimbursement of third party Consequential Damages suffered by such indemnified party.

6.5         Survival .  The provisions of this Article 6 shall survive the termination of this Agreement indefinitely.

ARTICLE 7. CONFIDENTIALITY

7.1         Confidentiality; Public Statements .  Except as provided in Section 7.2 below, each Party agrees that, during the Term, it will hold in strict confidence and will not without the prior written consent of the other Party disclose to any Person (a) any Confidential Information with respect to the other Party and its Affiliates, or (b) the terms and conditions and other information contained in this Agreement. The Parties shall consult with each other and no Party shall issue any public announcement or statement with respect to the existence of this Agreement, or any transaction contemplated hereby without the consent of the other Party.

7.2         Actions Prior to Disclosure .  In the event either Party determines that it is required by applicable law, rule, regulation or order of any Governmental Authority to disclose, file or otherwise make public the terms of this Agreement or any Confidential Information, it shall, prior to making any such disclosure, (a) notify the other Party of its determination that such disclosure is required and the basis for such determination; and (b) in the case of any disclosure or filing with any Governmental Authority, submit to the Governmental Authority, after consultation with the other Party, an application for confidential treatment (or such similar confidentiality request) and shall use reasonable efforts to obtain an order of the Governmental Authority granting the broadest confidential treatment that may be obtained with respect to this Agreement, or such other Confidential Information (as the case may be).

 

52


7.3         Non-Disclosure by Parties .    Notwithstanding the foregoing, each Party may disclose Confidential Information to its Representatives; provided, however, that each Representative who receives any such information shall be informed of the confidential nature of such information and shall be directed to treat such Confidential Information in accordance with the terms of this Article 7 . SouthStar and AGLSC shall be responsible for any breach of this Article 7 by any of their Representatives and each agrees, at its sole expense, to take all reasonable measures (including but not limited to court proceedings) to restrain its Representatives from prohibited or unauthorized disclosure or use of Confidential Information.

ARTICLE 8. MISCELLANEOUS

8.1         Entire Agreement; Modifications in Writing .  This Agreement together with all schedules attached hereto constitutes the entire agreement between the Parties pertaining to the subject matter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties. Except as specifically provided herein, no amendment, waiver, consent, modification or termination of any provisions of this Agreement shall be effective unless signed by SouthStar and AGLSC.

8.2         Binding Effect; Assignment .  The rights and obligations hereunder of either Party may not be assigned or delegated to any Person without the prior consent of the other Party. Except as expressly provided herein, this Agreement shall not be construed so as to confer any right or benefit upon any Person other than the Parties, and their respective successors and any permitted assigns. This Agreement shall be binding upon SouthStar and AGLSC, and their respective successors and permitted assigns.

8.3         Communications .  All notices and communications required or permitted under the terms of this Agreement shall be in writing, and shall be given by registered or certified mail, return receipt requested, air courier guaranteeing overnight delivery or personal delivery, to the addresses set forth below. All such notices and communications shall be deemed to have been duly given: at the time delivered by hand, if personally delivered; four (4) Business Days after being sent by certified mail, return receipt requested, if mailed; when answered back and on the next Business Day, if timely delivered to an air courier guaranteeing overnight delivery.

 

NOTICE TO AGLSC:

  

NOTICE TO SouthStar:

AGL Services Company

  

SouthStar Energy Services LLC

10 Peachtree Place

  

817 West Peachtree Street

Suite 1000

  

Atlanta, Georgia 30308

Atlanta, Georgia 30309

  

Attention: President

Attention: SVP & Treasurer

  

8.4         Execution of Counterparts .    This Agreement may be executed in any number of counterparts, each of which counterparts, when so executed and delivered, shall be deemed to be an original and all of which counterparts, taken together, shall constitute but one and the same agreement.

 

53


8.5         Governing Law .  This Agreement, and the rights and duties of the Parties arising out of such Agreement, shall be governed by and construed in accordance with the laws of the State of Georgia without regard to principles of conflicts of laws.

8.6         Severability of Provisions .  The invalidity of one or more provisions contained in this Agreement shall not affect the validity of the remaining portions of the Agreement so long as for both Parties the material purposes of the Agreement taken as a whole can be determined and effectuated. In the event that any or all of any of this Agreement is held to be invalid or unenforceable, the Parties agree to negotiate in good faith to reach an equitable agreement on such portion that is void or unenforceable. If any indemnity or hold harmless obligation (or portions thereof) in this Agreement is for any reason held to be invalid or unenforceable in any respect, and if the Parties fail to agree on a replacement provision, then such obligation shall be construed to apply to the fullest extent permitted by law but in no event beyond the scope and limits of those original indemnity and hold harmless obligations determined to be invalid or unenforceable.

8.7         Headings .  The section headings used or contained in this Agreement are for convenience of reference only and shall not affect the construction of this Agreement.

8.8         No Partnership Created .    The rights, liabilities, responsibilities and remedies of the Parties with respect to the subject matter of the Agreement shall be exclusively those expressly set forth in the Agreement. Neither Party is, or will represent itself as being, a partner of, or agent (except as expressly provided in the Agreement) or fiduciary for, the other Party with respect to the services covered by the Agreement, or otherwise.

8.9         No Implied Warranties .    Each Party hereby disclaims, and the other Party hereby waives, any implied representations, covenants, warranties and agreements, except those expressly set forth herein. This Agreement does not, and is not intended to, confer any rights or remedies upon any person other than the Parties hereto.

8.10       Adequate Assurance .    When reasonable grounds for insecurity of performance arise, SouthStar may demand adequate assurance of performance. Adequate assurance shall mean sufficient security in the form and for the term reasonably specified by SouthStar, including, but not limited to, a standby irrevocable letter of credit, a prepayment, a security interest in an asset acceptable to SouthStar or performance bond or guarantee by creditworthy entity. In the event AGLSC shall (i) make an assignment or any general arrangement for the benefit of creditors; (ii) default in any performance obligation to SouthStar; (iii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of proceeding or cause under any bankruptcy or similar law for the protection of creditors or have such petition filed or proceeding commenced against it; (iv) otherwise become bankrupt or insolvent (however evidenced); or (v) be unable to pay its debts as they fall due; then SouthStar shall have the right to either withhold and/or suspend payment, and/or terminate the Agreement without prior notice, in addition to any and all other remedies available hereunder.

8.11       Necessary Authorizations .    The Agreement is subject to all present and future valid orders, rules, and regulations of any regulatory body having jurisdiction. Each party represents that it has all necessary regulatory and other governmental authorizations for the transactions contemplated hereunder. The Parties agree to timely make all regulatory filings, if any, that may be needed to effectuate this Agreement.

 

54


8.12       Notice/Waiver .  The failure of a Party to give notice to any other Party or to take any other steps in exercising any right, or in respect of the breach or not of any provision of this Agreement, shall not operate as a waiver of that right, breach or provision nor shall any single or partial exercise of any right preclude any other or future exercise of that right or the exercise of any other right, whether in law or in equity or otherwise.

8.13       Termination of Prior Agreement .  The Parties agree that this Agreement hereby terminates, supercedes and restates the prior Services Agreement, dated as of March 31, 2004, between SouthStar and AGLSC.

IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed as of the date first above mentioned.

 

AGL Services Company

By

 

/s/ Andrew W. Evans

Name: 

 

Andrew W. Evans

Title: 

 

Executive Vice President and

 
     Chief Financial Officer                                     

SouthStar Energy Services LLC

By

 

/s/ Michael A. Braswell

Name: 

 

Michael A. Braswell

Title: 

 

CEO

 

 

55


SCHEDULE A

FEES

The fee for the Services rendered by AGLSC pursuant to the Services Agreement, of which this Schedule A forms a part, shall be equal to the sum of (1) $441,667 per month, payable quarterly for the pro-rata portion of the 2013 Contract Year; (2) and $1,325,000 payable quarterly (constituting an aggregate Contract Year fee of $5.3 million) for all of the 2014 Contract Year (the “ Service Fee ”), and (3) the total of any budgeted fees and expenses billed directly to AGLSC by a third party for products or services procured by AGLSC on behalf of, or for use by, SouthStar, which fees will be billed at actual cost.

AGLSC shall bill SouthStar quarterly for such Service Fee according to Section 2.3 of the Agreement.

Starting in Contract Year 2015 and for each Contract Year thereafter, the Service Fee shall increase by three percent (3%) annually.


EXHIBIT B

ADDRESSES FOR NOTICE

Piedmont Energy Company

4720 Piedmont Row Drive

Charlotte, North Carolina 28210

Attn: Karl W. Newlin, Senior Vice President

Telephone:

Facsimile:

Georgia Natural Gas Company

c/o AGL Resources Inc.

Ten Peachtree Place

Atlanta, Georgia 30309

Attn: L. Stephen Cave, Senior Vice President and Treasurer

Telephone:

Facsimile:


EXHIBIT C

NAMES AND ADDRESSES OF CURRENT MEMBERS

Piedmont Energy Company

4720 Piedmont Row Drive

Charlotte, North Carolina 28210

Attn: Senior Vice President

Georgia Natural Gas Company

c/o AGL Resources Inc.

Ten Peachtree Place

Atlanta, Georgia 30309

Attn: Senior Vice President and Treasurer


EXHIBIT D

COMPANY INTERESTS

 

Member

 

    Company Interest

Piedmont Energy Company

 

    15%

Georgia Natural Gas Company

 

    85%

CAPITAL ACCOUNT BALANCE

 

Member

 

    Account Balance

Piedmont Energy Company

 

    $38.316 million

Georgia Natural Gas Company

 

    $217.243 million

ALLOCABLE SHARES

 

Member

 

    Allocable Share

Piedmont Energy Company

 

    15%

Georgia Natural Gas Company

 

    85%


EXHIBIT E

{FORM OF}

SOUTHSTAR ENERGY SERVICES LLC

ADMISSION AGREEMENT

This Admission Agreement is entered into this      day of            , 20    , by and between SouthStar Energy Services LLC, a Delaware limited liability company (“the Company”) and                                                       .

 

WITNESSETH

WHEREAS, the Company was created pursuant to that certain Limited Liability Company Agreement (“the Company Agreement”) effective              , 1998

WHEREAS, the Company Agreement provides for the admission of Additional Members and requires an Additional Member to execute an Admission Agreement;

NOW THEREFORE, in consideration of the mutual agreements, promises, and undertakings hereinafter set forth, the Company and           agree as follows:

1. Capitalized words appearing in this Admission Agreement shall carry the definitions set forth in the Company Agreement unless the text of this Admission Agreement states otherwise.

2. Upon execution of this Admission Agreement           shall become a Member of the Company, shall be treated as a party to the Company Agreement for all purposes and shall be credited with a Company Interest of            percent ( %) of one hundred percent (100%) of all Company Interests and an initial Capital Account of $                          .

3.              hereby ratifies and adopts the entirety of the Company Agreement and agrees to accept all benefits granted to Members of the Company and to assume all obligations imposed on Members of the Company and to assume all obligations imposed on Members of the Company, including, without limitation, the obligation to make all Capital Contributions required of Members pursuant to Sections 9.1(b), 9.1(c) and 9.2 of the Company Agreement. The Company and              hereby acknowledge that              is not required to make an Initial Capital Contribution pursuant to Section 9.1(a) of the Company Agreement.

4. Exhibits B and D to the Company Agreement are hereby amended as to                and new Exhibits B and D are hereby substituted to the Company Agreement, which Exhibits are attached to this Admission Agreement, reflecting the admission of              as a Member of the Company (i) owning a        percent Company Interest and (ii) having an initial Capital Account of $          

5. Except as set forth in this Admission Agreement, the original terms and conditions of the Company Agreement shall remain in full force and effect.

 

1


SouthStar Energy Services LLC

By:

 

 

 

Title:

 

 

 

By:

 

 

 

Title:

 

 

 

 

2


Exhibit F

AMENDED AND RESTATED OPERATING POLICY

I. Definitions

1.1         Terms used herein shall have the meanings defined herein, or if such term is not defined herein, the meanings defined in the Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC effective September 1, 2013, as amended, restated or modified from time to time (the “ LLC Agreement ”).

1.2         Terms with unique or Company specific definitions may be indicated herein by the capitalization of the first letter of the word or words in such term.

1.3         The term “Budget” as used herein shall have the same meaning as the term Operating Budget, as such term is used in the LLC Agreement; provided, however, that the Budget for each Fiscal Year shall be presented to and approved by the Executive Committee by December 15 of the preceding Fiscal Year.

1.4         The term “Company” as used herein shall refer to SouthStar Energy Services LLC and its wholly owned Subsidiaries, as applicable.

1.5         The term “Direct Costs” as used herein shall include all direct payroll, transportation, travel, and out-of-pocket materials and supplies costs incurred by a Member Provider in connection with the rendering of said goods and services to the Company. In addition, with respect only to Direct Costs constituting payroll expenses, an additive of 35% shall be applied to such direct payroll expenses.

1.6         The term “Prime Rate” as used herein shall mean such per annum rate equal to the “Prime Rate” as in effect from time to time as published in the “Money Rates” section of the Wall Street Journal, or if such section or publication is no longer available, such other publication as reasonably determined by the Member Provider.

II. Intercompany Billing

2.1        Use of Goods and Services - From time to time, the Company may request that a Member or Affiliate of a Member (a “ Member Provider ”) provide goods and/or services to the Company that are not already the subject of a specific services contract or a contract otherwise approved by the Executive Committee in accordance with the LLC Agreement (an “ Affiliate Transaction ”). In such case, excluding Affiliate Transactions that have been previously approved by the Members (including through the Budget), all Direct Costs associated with the rendering of such goods and/or services will be billed to the Company by the Member Provider and paid by the Company on a monthly basis as set forth in this Operating Policy. Any Affiliate Transaction shall be on terms that are “arms-length” and fair to the Company or the disinterested Members; provided however, that any Affiliate Transaction in which the rates, terms or charges involved in the transaction: (a) are determined by competitive bids, (b) are made in the ordinary course of business of the Member Provider, (c) involve the rendering of services as a common or contract carrier or a public utility at rates or charges fixed in conformity with law or


governmental authority or (d) are approved or recognized by the disinterested Member(s) with full knowledge of the facts and circumstances, are per-se fair and at arms-length. The Company will provide to the Members annually a summary of shared services Affiliated Transactions that are included in the Budget.

2.2        Accounting - Each Member Provider shall maintain adequate books and records with respect to the goods and/or services provided to the Company pursuant to Section 2.1 above, and each Member shall be responsible for maintaining internal controls to ensure the costs associated with those Member Provider’s Affiliate Transactions are properly, accurately and consistently accounted for and billed in accordance with this Operating Policy.

2.3        Invoicing, Payment - Within thirty (30) calendar days after the close of each month, a Member Provider providing goods and/or services to the Company pursuant to Section 2.1 above shall invoice the Company for such goods and/or services. Such invoices shall be payable by the Company within fifteen (15) calendar days of receipt. The invoice shall include an itemized list of charges, including a reasonably detailed description of the nature of the functions, goods and/or services provided. In addition, the Member Provider shall make available any and all records requested by the Company to support such charges to whatever extent the Company reasonably deems appropriate.

Should the Company fail to remit the full amount when due, interest on the unpaid portion shall accrue at a rate equal to two percent (2%) over the Prime Rate from the date such amount was due until paid. In the event the Company fails to notify the Member Provider by the due date of the invoice that the Company in good faith disagrees with or disputes all or a portion of the amount billed by that Member Provider to the Company, the Company and the Member Provider shall in good faith work to resolve the dispute. Amounts in dispute shall not accrue interest.

III. Delegation Of Authority Levels

Financial

3.1          Banking facilities (accounts, etc.) and transfer of funds/overnight investments – will be managed by Company personnel. Authority for managing day to day operational items is vested at the Officer level (or such Officer’s delegate).

3.2          Receivables Exposure – will be managed by the Company, including without limitation purchase of receivables agreements with utilities. These items will be day to day operational items and will be managed at the Officer level (or such Officer’s delegate).

3.3        Credit Facilities – as approved by the Executive Committee.

3.4        Third party non-recourse borrowing, lending, or guarantees (as outlined in the LLC Agreement):

 

AMOUNT

  

AUTHORIZATION

£ $400,000 and Member guarantees

   President or Controller if delegated by President

>$400,000

   Unanimous Vote of Executive Committee

 

2


3.5        Financial Statements – Financial Statements will be provided by members of the Executive Committee within thirty (30) days after the close of each month. The statements shall consist of, but not be limited to, a balance sheet, an income statement, and a statement of cash flow (funds). Supporting schedules shall be prepared in compliance with generally accepted accounting principles consistently applied and be provided in detail sufficient to satisfy the requirements of the parent entities of the Members to prepare consolidated financial reports. To the extent Members have fiscal years different from the Company, the Company shall prepare its financial statements in a fashion that permits such Member to comply with its fiscal year reporting requirements.

Operations

The following limitations pertain to entering into natural gas purchase, sale, transportation, distribution or storage transactions:

3.6         Firm natural gas purchase, transportation or storage agreements must obtain the following approvals:

 

TERM LIMIT    AUTHORIZATION

£ 5 YEARS

   President or his delegate

>5 YEARS

   Unanimous Vote of Executive Committee

3.7         Firm Gas Sales agreements must obtain the following approvals:

 

TERM LIMIT    AUTHORIZATION

£ 5 YEARS

   President or his delegate

>5 YEARS

   Unanimous Vote of Executive Committee

3.8         Agreements with utilities for operations in markets approved by the Executive Committee, including without limitation purchase of receivables, billing and services agreements will be managed by the Company. These items will be day to day operational items and will be managed at the Officer level (or such Officer’s delegate).

3.9         Other than as specifically specified otherwise in this Operating Policy, entering into, amending, modifying or terminating (other than in accordance of the terms of such agreement) any agreement (excluding gas supply or purchase agreements, described above) or commitment to acquire or transfer any asset involving aggregate consideration (including assumed actual and contingent liabilities) or receipts, or delivery or receipt of goods or services having a value in excess of:

 

AMOUNT

  

AUTHORIZATION

£ $400,000 or items set forth in the Budget

   President or his delegate

>$400,000 for items not set forth in the Budget

   Unanimous Vote of Executive Committee

 

3


Legal Matters

3.10       After legal review, the following are required for action:

 

AMOUNT

       

AUTHORIZATION

    
Any non-operational contracts with related parties or third parties (excluding office space and equipment or other categories specifically noted below):         

£ $400,000 or items set forth in the Budget

      Officer level or delegate   

>$400,000 for items not set forth in the Budget

     

Unanimous Vote of Executive

Committee

  
Energy standard contract forms       Officer level or delegate   
Contracts w/non-standard payment provisions       President or his delegate   
Standard gas sales and purchase contracts       Officer level or delegate   
Filing a claim or lawsuit where amount claimed is £ $100,000       President or his delegate   
Settling a claim or lawsuit where fair market value of settlement amount is £ $100,000       President or his delegate   

External Communications

3.11       Third party communications should receive the following approvals prior to issuance:

 

COMMUNICATIONS

       

AUTHORIZATION

Employee articles published as a representative of the Company or relating to the Company       President or his delegate
News media releases and planned media interviews of employees or Executive Committee members in their roles as Executive Committee members (other than updates to websites in the ordinary course of business)      

The expected content shall be communicated one (1) business day prior to the interview or news release to each member of the Executive Committee. Formal press releases should be reviewed by the Executive Committee

 

4


Capital & Expense

3.12       The following authorizations are required for capital and operating expenditures:

 

CATEGORY

  

AUTHORIZATION

 

CAPITAL

  

 Per Budget and LLC Agreement

   Officer level or delegate

 In excess of Budget and £ $400,000

   President or his delegate

 In excess of Budget and >$400,000

  

Unanimous Vote of Executive

Committee

EXPENSE (other than bad debt)

  

 Per Budget and LLC Agreement

   Officer level or delegate

 In excess of Budget and £ $400,000

   President or his delegate

 In excess of Budget and >$400,000

  

Unanimous Vote of Executive

Committee

Personnel

3.13       The following authorizations are required for non-officer (non-vice president) personnel matters:

 

EMPLOYEE ACTION

       

AUTHORIZATION

Promotions within Budget

      President or his delegate

Salary increase/decrease within Budget

     

President or his delegate

Terminations

     

President or his delegate

Hiring within Budget

     

President or his delegate

Temporary employment

     

President or his delegate

Approval of annual short-term and long-term bonus structure       Compensation Committee of the Executive Committee

IV. Energy Credit Procedures

4.1        Credit Exposure – will be managed by the Company according to Risk Management Policy as approved by Unanimous Vote of the Executive Committee. These items will be day-to-day operational items and will be managed at the Officer level (or such Officer’s delegate).

4.2        Overrides of Credit Policy and/or the Credit Department – exceptions to the credit policy may be made only with the following approvals:

 

AMOUNT/DAYS

  

AUTHORIZATION

$400,000 for 45 days

   President or his delegate

$400,000 for 90 days

   Chairman of the Executive Committee and President

> $400,000

   Executive Committee

4.3        Credit Evaluation – governed by the Company’s current Risk Management Policy as approved by Unanimous Vote of the Executive Committee.

 

5


V. Location of Business Offices

5.1         The location of the business offices shall be:

 

Headquarters:

 

Field Office:

817 West Peachtree Street

Atlanta, Georgia 30308

 

N/A

VI. Risk Management Policy

6.1         Governed by the Company’s Risk Management Policy as approved by Unanimous Vote of the Executive Committee.

 

6


EXHIBIT G

{FORM OF}

INDEMNIFICATION AGREEMENT

This INDEMNIFICATION AGREEMENT is made and entered into as of the — day of January      2004 by AGL Resources Inc. (“ AGLR ”) and Piedmont Energy Partners, Inc. (“ Piedmont ”), collectively referred to herein as the “ Parties ”.

WHEREAS, Georgia Natural Gas Company (“ GNGC ”), a subsidiary of AGLR, and Piedmont Energy Company (“ Piedmont Energy ”), a subsidiary of Piedmont, are each members of SouthStar Energy Services LLC (“ SouthStar ”), a Delaware limited liability company, with GNGC and Piedmont Energy holding a                  percent (       %) and            percent (       %) membership interest in SouthStar (each an “ Company Interest ”), respectively.

WHEREAS, AGLR is guarantor to SouthStar under various arrangements (each referred to herein as a “ Guaranty ”), pursuant to which AGLR has agreed to guarantee the obligations of SouthStar;

WHEREAS, each Party believes that it is in its best interest for AGLR to be indemnified against any losses it might incur as a result of its providing financial support for SouthStar under any Guaranty to the extent that AGLR is required to bear more than GNGC’s Company Interest of SouthStar’s obligations pursuant to such Guarantees;

WHEREAS, the Parties agree that Piedmont should indemnify AGLR for such losses up to the amount of Piedmont Energy’s Company Interest of such losses; and

WHEREAS, this Agreement sets forth the terms and conditions of the Parties’ mutual agreement;

In consideration of the benefit the each Party and its affiliates derive from AGLR providing financial support to SouthStar pursuant to any Guaranty the Parties agree as follows:

 

    1. Piedmont shall indemnify, defend and hold AGLR harmless against any losses, costs, fees, liabilities or other expenses AGLR may incur as a result of providing financial support for SouthStar under any Guaranty, as applicable (“ Indemnified Expenses ”); provided however, that Indemnified Expenses shall include only those amounts actually incurred by AGLR as a consequence of a third party invoking its right under any Guaranty. The extent of obligation of Piedmont to indemnify AGLR shall be equal to the product of (a) the then-current Company Interest of Piedmont Energy, multiplied by (b) the Indemnified Expenses. Notwithstanding any statement herein to the contrary, Piedmont shall not be liable to AGLR to the extent that the Indemnified Expenses resulted from AGLR’s negligence or misconduct.

 

1


    2. AGLR shall invoice Piedmont (at the address set forth in numbered paragraph 6 below) no later than ten days prior to the end of each calendar month for Piedmont’s share (as calculated in Section 1 above) of the Indemnified Expenses due from the previous calendar month or any portion thereof. Piedmont shall pay AGLR the amount of such invoice (via wire transfer to the account specified on the invoice) no later than the last day of the calendar month during which AGLR sent the invoice.

 

       If Piedmont fails to pay all of the amount of any invoice when that amount becomes due, Piedmont shall pay AGLR a late charge on the unpaid balance that shall accrue daily on each calendar day from the due date at an annual rate equal to two percentage points above the then-effective monthly prime commercial lending rate per annum announced by Bank of America, N.A. from time to time multiplied by the unpaid balance; provided, that for any period that such rate exceeds any applicable maximum rate permitted by law, the rate shall equal the applicable maximum rate.

 

    3. This Agreement shall inure to the benefit of each Party, its successors, affiliates, assigns and creditors, and can be modified only by a written instrument signed by each Party. Neither Party shall have the right to assign this Agreement nor its obligations hereunder to any person or entity without the prior written consent of the other, which shall not be unreasonable withheld.

 

    4. This Agreement shall be governed by, and construed in accordance with the internal laws (but not the laws concerning conflicts of laws) of the state of Delaware.

 

    5. Each Party represents and warrants to the other that it is authorized to indemnify the other under the terms of this Agreement, that it has all of the rights and powers necessary to do so, and that the individual signing below is authorized to bind the Party to its obligations under this Agreement.

 

    6. Notices hereunder must be given in writing (which may be a facsimile transmission) to be effective and shall be effective upon receipt by the applicable Party at the address set forth below or at such other address as either Party may notify the other:

If to AGLR:

By Mail:

AGL Resources Inc.

P.O. Box 4569

Atlanta, GA 30302-4569

Attention: Chief Financial Officer

By Facsimile: (404) 584-3419

By Courier:

AGL Resources Inc.

Ten Peachtree Place, Suite 1000

Atlanta, Georgia 30308

Attention: Chief Financial Officer

 

2


If to Piedmont:

[to come]

 

    7. PIEDMONT HEREBY INTENTIONALLY AND VOLUNTARILY WAIVES ANY DEFENSE TO PAYMENT UNDER THIS AGREEMENT THAT IS BASED UPON OR ARISES OUT OFAGLR’S DIRECT OR INDIRECT OWNERSHIP OF AN EQUITY INTEREST IN SOUTHSTAR.

AGREED TO AND ENTERED INTO the date first written above by:

 

AGL Resources Inc.

 

By:

 

 

 

Title:

 

 

 
Piedmont Energy Partners, Inc.

By:

 

 

 

Title:

 

 

 
 

 

3


EXHIBIT H

{FORM OF}

CONVEYANCE AND ASSIGNMENT AGREEMENT

This Conveyance and Assignment Agreement (this “ Agreement ”), dated as of                      , is entered into by and between Georgia Natural Gas Company, a Georgia corporation, (“ GNGC ”) and Piedmont Energy Company, a North Carolina corporation (“ Piedmont ”)

WHEREAS, Piedmont and GNGC are each Members of SouthStar energy Services, LLC, A Delaware limited liability company (“ SouthStar ”);

WHEREAS, Piedmont has granted GNGC certain options to purchase its Company Interest in SouthStar and GNGC has exercised an option to purchase [all or a portion] of Piedmont’s Company Interest (the “ Percentage Interest ”) as provided herein.

NOW THEREFORE, in consideration of the premises and the agreements contained in this Agreement, and for other good and valuable consideration, the receipt and adequacy of which is hereby acknowledged, the GNGC and Piedmont agree as follows:

ARTICLE 1

1.1 Conveyance. Piedmont hereby grants, sells, transfers, assigns and conveys to GNGC, its successors and assigns, for its and their own use forever, all right, title and interest in and to the Percentage Interest for $                                                   in cash and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and GNGC hereby accepts the Percentage Interest.

TO HAVE AND TO HOLD the Percentage Interest unto GNGC, its successors and assigns, together with all the rights and appurtenances thereto belonging, subject, however, to the terms and conditions stated in this Agreement, forever.

1.2 Disclaimer of Warranties.

(a) PIEDMONT IS CONVEYING THE PERCENTAGE INTEREST WITHOUT REPRESENTATION OR WARRANTY, WHETHER EXPRESS, IMPLIED OR STATUTORY (ALL OF WHICH PIEDMONT HEREBY DISCLAIMS), AS TO TITLE OR ANY OTHER MATTER WHATSOEVER, EXCEPT AS PROVIDED HEREIN.

(b)        Piedmont and GNGC agree that the disclaimers contained in this Section 1.2 are “conspicuous” disclaimers. Any covenants implied by statute or law by the use of the words “grant,” “convey,” “bargain,” “sell,” “assign,” “transfer,” “deliver” or “set over” or any of them or any other words used in this Agreement are hereby expressly disclaimed, waived and negated.


ARTICLE 2

MISCELLANEOUS

2.1 Power of Attorney. Piedmont hereby constitutes and appoints GNGC, its successors and assigns, its true and lawful attorney-in-fact with full power of substitution for it and in its name, place and stead or otherwise on behalf of Piedmont, its successors and assigns, and for the benefit of GNGC, its successors and assigns, to demand and receive from time to time the Percentage Interest and to execute in the name of Piedmont and its successors and assigns instruments of conveyance, instruments of further assurance and to give receipts and releases in respect of the same, and from time to time to institute and prosecute in the name of GNGC or Piedmont for the benefit of GNGC as may be appropriate, any and all proceedings at law, in equity or otherwise which GNGC, its successors and assigns may deem proper in order to collect, assert or enforce any claims, rights or titles of any kind in and to the Percentage Interest, and to defend and compromise any and all actions, suits or proceedings in respect of any of the Percentage Interest and to do any and all such acts and things in furtherance of this Agreement as GNGC, its successors or assigns shall deem advisable. Piedmont hereby declares that the appointment hereby made and the powers hereby granted are coupled with an interest and are and shall be irrevocable and perpetual and shall not be terminated by any act of Piedmont, its successors or assigns or by operation of law.

2.2 Further Assurances. From time to time after the date hereof, and without any further consideration, Piedmont (or the general partner of Piedmont on behalf of Piedmont) shall execute, acknowledge and deliver all such additional deeds, assignments, bills of sale, conveyances, instruments, notices, releases, acquittances and other documents, and will do all such other acts and things, all in accordance with applicable law, as may be necessary or appropriate (i) more fully to assure GNGC, its successors and assigns, all of the properties, rights, titles, interests, estates, remedies, powers and privileges by this Agreement granted to GNGC or intended so to be and (ii) to more fully and effectively carry out the purposes and intent of this Agreement.

2.3 Counterparts.       This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, but all of which shall constitute one and the same agreement.

2.4 Governing Law.   This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware without regard to principles of conflict of law.

2.5 Bill of Sale; Assignment. To the extent required by applicable law, this Agreement shall also constitute a “bill of sale” or “assignment” of the Percentage Interest.

(Signatures begin on following page)

 

2


IN WITNESS WHEREOF , this Agreement has been duly executed by the parties hereto as of the date first above written.

 

Georgia Natural Gas Company
By:_____________________________
Name: __________________________
Title: ___________________________
Piedmont Energy Company
By:_____________________________
Name: __________________________
Title: ___________________________

 

3


LIMITED LIABILITY COMPANY INTEREST POWER

FOR VALUE RECEIVED, Piedmont Energy Company. hereby sells, assigns and transfers unto Georgia Natural Gas Company                              percent (       %) of its limited liability company interests (the “ Interests ”) in SouthStar Energy Services, LLC, a Delaware limited liability company (the “ Company ”), which Interests constitutes                              percent (       %) of the issued and outstanding limited liability company interests in the Company, standing in its name on the books of the Company, but otherwise uncertificated, and does hereby irrevocably constitute and appoint the Secretary of the Company attorney to transfer the Interests on the books of the Company with full powers of substitution in the premises.

 

Dated:

 

 

 

  Piedmont Energy Company
  By:_________________________________   
  Name: ______________________________   
  Title: _______________________________   

 

In the presence of:

_____________________

 

4

Exhibit 12

PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES

Computation of Ratio of Earnings to Fixed Charges

For Fiscal Years Ended October 31, 2009 through 2013

(in thousands except ratio amounts)

 

     2013      2012      2011      2010      2009  

Earnings:

              

Pre-tax income from continuing operations

   $ 193,081      $ 171,714      $ 158,320      $ 153,687      $ 169,502  

Distributed income of equity investees

     26,839        24,962        25,714        47,094        23,986  

Fixed charges

     57,549        46,978        54,239        55,567        51,156  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Adjusted Earnings

   $ 277,469      $ 243,654      $ 238,273      $ 256,348      $ 244,644  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Fixed Charges:

              

Interest

   $ 54,840      $ 43,908      $ 51,639      $ 53,226      $ 48,433  

Amortization of debt expense

     1,029        1,401        1,063        647        789  

Amortization of loss - reacquired debt

     238        238        99        —          —    

One-third of rental expense

     1,442        1,431        1,438        1,694        1,934  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Fixed Charges

   $ 57,549      $ 46,978      $ 54,239      $ 55,567      $ 51,156  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Ratio of Earnings to Fixed Charges

     4.82        5.19        4.39        4.61        4.78  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Exhibit 21

List of Subsidiaries

October 31, 2013

 

Name

  

State of Incorporation

  

Identity of Business Unit

Subsidiaries of Piedmont Natural Gas Company, Inc.:   
Piedmont Energy Partners, Inc.    North Carolina    Holding Company
Piedmont Hardy Storage Company, LLC    North Carolina   

Member of Hardy Storage

Company, LLC

Piedmont ENCNG Company, LLC    North Carolina   

Member of Piedmont Hardy

Storage Company, LLC

Subsidiaries of Piedmont Energy Partners, Inc.:   
Piedmont Propane Company    North Carolina    Dormant
Piedmont Interstate Pipeline Company    North Carolina   

Member of Pine Needle

LNG Company, L.L.C.

Piedmont Intrastate Pipeline Company    North Carolina   

Member of Cardinal

Pipeline Company, L.L.C.

Piedmont Energy Company    North Carolina   

Member of SouthStar

Energy Services, LLC

Piedmont Constitution Pipeline Company, LLC    North Carolina   

Member of Constitution

Pipeline Company, LLC

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-175386 and 333-184895 on Form S-3ASR, and in Registration Statement Nos. 333-76140, 333-132738, 333-161888 and 333-166298 on Form S-8, and in Post-Effective Amendment No. 1 to Registration Statement No. 333-76140 on Form S-8 of our reports dated December 23, 2013, relating to the consolidated financial statements of Piedmont Natural Gas Company, Inc. and subsidiaries, and the effectiveness of Piedmont Natural Gas Company, Inc. and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc. and subsidiaries for the year ended October 31, 2013.

 

/s/ Deloitte & Touche LLP
Charlotte, North Carolina
December 23, 2013

Exhibit 31.1

CERTIFICATION

I, Thomas E. Skains, certify that:

 

  1. I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc.;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

  4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


  5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

  Date:  

December 23, 2013

   

/s/ Thomas E. Skains

       

Thomas E. Skains

Chairman of the Board, President and Chief

Executive Officer

(Principal Executive Officer)

Exhibit 31.2

CERTIFICATION

I, Karl W. Newlin, certify that:

 

  1. I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc.;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

  4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


  5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date:  

December 23, 2013

   

/s/ Karl W. Newlin

     

Karl W. Newlin

Senior Vice President and Chief Financial

Officer

(Principal Financial Officer)

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Annual Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-K for the period ended October 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Skains, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

 

  (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

  (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

December 23, 2013

 

/s/ Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President and Chief

Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Annual Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-K for the period ended October 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Karl W. Newlin, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

 

  (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

  (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

December 23, 2013

 

/s/ Karl W. Newlin

Karl W. Newlin
Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.