10-K 1 d466906d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended: December 31, 2012

Commission File Number: 001-11590

 

 

CHESAPEAKE UTILITIES CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

State of Delaware   51-0064146

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including zip code)

302-734-6799

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Common Stock—par value per share $0.4867   New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

8.25% Convertible Debentures Due 2014

(Title of class)

 

 

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 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 amendments 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 “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨    Smaller Reporting Company   ¨

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

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2012, the last business day of its most recently completed second fiscal quarter, based on the last trade price on that date, as reported by the New York Stock Exchange, was approximately $401.3 million.

As of February 28, 2013 9,598,674 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2013 Annual Meeting of Stockholders are incorporated by reference in Part II and Part III.

 

 

 


Table of Contents

CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, 2012

TABLE OF CONTENTS

 

     Page  

Part I

     1   

Item 1. Business

     2   

Item 1A. Risk Factors

     14   

Item 1B. Unresolved Staff Comments

     21   

Item 2. Properties

     21   

Item 3. Legal Proceedings

     22   

Item 4. Mine Safety Disclosure

     22   

Item 4A. Executive Officers of the Registrant

     23   

Part II

     24   

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

     24   

Item 6. Selected Financial Data

     27   

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

     31   

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

     61   

Item 8. Financial Statements and Supplementary Data

     61   

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

     122   

Item 9A. Controls and Procedures

     122   

Item 9B. Other Information

     124   

Part III

     124   

Item 10. Directors, Executive Officers of the Registrant and Corporate Governanace

     124   

Item 11. Executive Compensation

     124   

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

     124   

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

     125   

Item 14. Principal Accounting Fees and Services

     125   

Part IV

     126   

Item 15. Exhibits, Financial Statement Schedules.

     126   

Signatures

     131   


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GLOSSARY OF KEY TERMS AND DEFINITIONS

KEY TERMS

Acquisition adjustment: The recovery, through rates, and inclusion in rate base, of the premium (amount in excess of net book value) paid for an acquisition as approved by the state Public Service Commission for the regulated operations.

Allowed return: Return on equity or pre-tax, pre-interest rate of return on investment approved by the state Public Service Commission or the Federal Energy Regulatory Commission for the respective regulated operation.

Bulk delivery: Propane delivery to customers based on the level of propane remaining in the tank located at the customer’s premises. We invoice and record revenues for the bulk delivery service at the time of delivery, rather than upon the customer’s actual usage.

Cost of sales: Includes the purchased cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities and the direct cost of labor spent on revenue-producing activities.

Delmarva natural gas distribution operation: Chesapeake’s Delaware and Maryland divisions.

Delmarva Peninsula: A peninsula on the east coast of the United States of America occupied by Delaware and portions of Maryland and Virginia. Chesapeake provides natural gas distribution, transmission and marketing services and propane distribution service to customers on the Delmarva Peninsula.

Electric distribution: Regulated electric distribution utility service. Florida Public Utilities Company provides this service to customers in northeast and northwest Florida. This service is regulated by the Florida Public Service Commission.

Firm service: Regulated utility service that cannot be disrupted to meet the needs of other customers.

Florida natural gas distribution operation: Chesapeake’s Florida division and the natural gas operation of Florida Public Utilities Company, including its Indiantown division.

Fuel cost recovery mechanism: A regulatory method of adjusting the utility billing rates to reflect changes in the cost of purchased fuel for the natural gas and electric distribution operations. This allows matching of revenues with natural gas and electric supply and transportation costs and typically provides full recovery of such costs.

Gross margin: A non-GAAP measure, which Chesapeake uses to evaluate the performance of its business segments. Gross margin is calculated by deducting the cost of sales from operating revenues. A more detailed description of gross margin, including how we calculate it, is provided in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this Annual Report on Form 10-K.

Interruptible service: Large commercial customers whose regulated utility service can be temporarily interrupted in order for the utility to meet the needs of firm service customers. The interruptible service customers pay lower delivery rates than firm service customers and they must be able to readily substitute an alternate fuel for natural gas.

Margins per gallon: A measure of profitability for propane distribution sales, calculated for each gallon of propane sold by deducting the cost of propane sold from the propane revenue.

Mark-to-market: The process of adjusting the carrying value of a position held in our forward contracts and derivative instruments to reflect their current fair value.

Natural gas distribution: Regulated natural gas distribution utility service. Both Chesapeake Utilities Corporation, through its Delaware, Maryland and Florida divisions, and Florida Public Utilities Company provide this service. This service is regulated by the Public Service Commission of each respective state.


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Natural gas marketing: Unregulated natural gas supply and supply management service for the sale of the natural gas commodity directly to residential, commercial and industrial customers through competitively-priced contracts. Peninsula Energy Services Company, Inc. provides this service.

Natural gas transmission: Regulated natural gas transportation service provided by Eastern Shore Natural Gas Company and Peninsula Pipeline Company, Inc. The interstate transportation service provided by Eastern Shore Natural Gas Company is regulated by the Federal Energy Regulatory Commission. The intrastate transportation service provided by Peninsula Pipeline Company, Inc. in Florida is regulated by the Florida Public Service Commission.

Normal Weather: The most recent 10–year average of heating and/or cooling degree-days in a particular geographic area.

Propane distribution: Unregulated propane distribution service to residential, commercial, industrial and wholesale customers. This service can be provided through delivery to a propane tank located on the customer’s premises or through an underground pipeline system.

Propane wholesale marketing: Unregulated service offering where propane is marketed to major independent oil and petrochemical companies, wholesale resellers and retail propane companies located primarily in the southeastern United States of America. This service typically utilizes forward or other option contracts that are financially settled. Xeron, Inc. provides this service.

Rate Case: A periodic filing with the state Public Service Commission or the Federal Energy Regulatory Commission to establish equitable rates and balance the interests of all classes of customers and shareholders.

Regulated energy: The largest operating segment of Chesapeake Utilities Corporation. All operations in this segment are regulated as to their rates and service, by the Public Service Commission having jurisdiction in each state in which the Company operates or by the Federal Energy Regulatory Commission.

Transportation service: Natural gas service to customers whereby a customer purchases natural gas commodity directly from a supplier but pays the utility to transport the gas over its distribution or transmission system to the customer’s facility.

DEFINITIONS

AFUDC: Allowance for funds used during construction

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

BravePoint: BravePoint®, Inc., an advanced information services subsidiary, headquartered in Norcross, Georgia

CDD: Cooling degree-days, which is the measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit

Chesapeake: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure

Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake

Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake

Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake


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Columbia: Columbia Gas Transmission, LLC

Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure

Crescent: Crescent Propane, Inc.

Delaware City Refinery: An oil refinery located in Delaware City, Delaware and owned by PBF Energy Inc.

Dodd-Frank Act: The Dodd-Frank Wall Street Reform and Consumer Protection Act

DSCP: Directors Stock Compensation Plan

Dt: Dekatherm, which is a natural gas unit of measurement that includes a standard measure for heating value

Dts/d: Dekatherms per day

Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake

EPA: United States Environmental Protection Agency

ESG: Eastern Shore Gas Company and its affiliates

FASB: Financial Accounting Standards Board

FERC: Federal Energy Regulatory Commission, an independent agency of the Federal government that regulates the interstate transmission of electricity, natural gas, and oil

FDEP: Florida Department of Environmental Protection

FDOT: Florida Department of Transportation

FGT: Florida Gas Transmission Company

FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake as of October 28, 2009, the date we acquired FPU

FPU Medical Plan: A separate unfunded postretirement medical plan for FPU sponsored by Chesapeake

FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake

FRP: Fuel Retention Percentage

GAAP: Accounting principles generally accepted in the United States of America

GRIP: Gas Reliability Infrastructure Program, which is a surcharge to natural gas customers designed to recover capital and other program-related costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services in Florida

GSR: Gas Service Rates

Gulf: Columbia Gulf Transmission Company

Gulf Power: Gulf Power Company


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Gulfstream: Gulfstream Natural Gas System, LLC

HDD: Heating degree-days, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit

IFRS: International Financial Accounting Standards

IGC: Indiantown Gas Company

IRS: Internal Revenue Service

MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use

MDE: Maryland Department of Environment

Marianna Commission: The City Commission of Marianna, Florida

MWH: Megawatt hour, which is a unit of measurement for electricity

NAM: Natural Attenuation Monitoring

NRG: NRG Energy Center Dover LLC

NYSE: New York Stock Exchange

OTC: Over-the-counter

PESCO: Peninsula Energy Services Company, Inc., a wholly-owned natural gas marketing subsidiary of Chesapeake

Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned Florida intrastate pipeline subsidiary of Chesapeake

Peoples Gas: The Peoples Gas System division of Tampa Electric Company

PIP: Performance Incentive Plan

PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake’s natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida

Rayonier: Rayonier Performance Fibers, LLC

Sanford Group: Florida Public Utilities Company and other responsible parties involved with the Sanford environmental site

SEC: Securities and Exchange Commission

Sharp: Sharp Energy, Inc., a wholly-owned propane distribution subsidiary of Chesapeake.

S&P 500 Index: Standard & Poor’s 500 Index

TETLP: Texas Eastern Transmission, LP


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TOU: Time-of-use

Transco: Transcontinental Gas Pipe Line Company, LLC

Virginia LP: Virginia LP Gas, Inc.

Xeron: Xeron, Inc., a wholly-owned propane wholesale marketing subsidiary of Chesapeake, based in Houston, Texas


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PART I

References in this document to “Chesapeake,” the “Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation, its divisions and/or its wholly-owned subsidiaries, as appropriate in the context of the disclosure.

Safe Harbor for Forward-Looking Statements

We make statements in this Annual Report on Form 10-K that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. These statements are subject to many risks and uncertainties. In addition to the risk factors described under Item 1A “Risk Factors,” the following important factors, among others, could cause actual future results to differ materially from those expressed in the forward-looking statements:

 

  state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries (including deregulation);

 

  the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates and whether the costs associated with such matters are adequately covered by insurance or recovered in rates;

 

  the loss of customers due to government-mandated sale of our utility distribution facilities;

 

  industrial, commercial and residential growth or contraction in our markets or service territories;

 

  the weather and other natural phenomena, including the economic, operational and other effects of hurricanes, ice storms and other damaging weather events;

 

  the timing and extent of changes in commodity prices and interest rates;

 

  general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control;

 

  changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now or may in the future own or operate;

 

  the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

 

  declines in the value of the pension plan assets and resultant cash funding requirements for our defined benefit pension plans;

 

  the creditworthiness of counterparties with which we are engaged in transactions;

 

  the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;

 

  the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

 

  conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;

 

  the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

 

  the ability to establish and maintain new key supply sources;

 

  the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses;

 

  the effect of competition on our businesses;

 

  the ability to construct facilities at or below estimated costs; and

 

  changes in technology affecting our advanced information services business.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 1


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ITEM 1. BUSINESS.

(a) Overview

Chesapeake Utilities Corporation (“Chesapeake” or “we”) is a Delaware corporation that was formed in 1947. We are a diversified utility company engaged, through our operating divisions and subsidiaries, in various energy and other businesses. The core of our business is regulated energy, which provides stable earnings from utility operations on the Delmarva Peninsula and in Florida. Our unregulated energy and other businesses provide opportunities to achieve returns greater than those of a traditional utility. The following chart shows, in simplified form, our principal business structure:

 

LOGO

On October 28, 2009, we completed a merger with Florida Public Utilities Company (“FPU”), pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. The acquisition of FPU significantly increased our overall presence in Florida and expanded our energy diversity by adding electric distribution to our business. As a result of the FPU acquisition, Chesapeake is a utility holding company subject to the regulatory oversight of the Federal Energy Regulatory Commission (“FERC”).

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 2


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(b) Operating Segments

We are composed of three operating segments:

 

  Regulated Energy. The regulated energy segment includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and service, by the Public Service Commission (“PSC”) having jurisdiction in each state in which we operate or by the FERC in the case of Eastern Shore Natural Gas (“Eastern Shore”).

 

  Unregulated Energy. The unregulated energy segment includes propane distribution, propane wholesale marketing and natural gas marketing operations, which are unregulated as to their rates and services.

 

  Other. The “Other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

The following table shows the size of each of our operating segments based on operating income for 2012 and net property, plant and equipment as of December 31, 2012:

 

           Net Property, Plant  

(dollars in thousands)

   Operating Income     & Equipment  

Regulated Energy

   $ 46,999         83   $ 486,072         90

Unregulated Energy

     8,355         15     38,582         7

Other

     1,281         2     17,127         3
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 56,635         100   $ 541,781         100
  

 

 

    

 

 

   

 

 

    

 

 

 

Additional financial information by business segment is included in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note 5, Segment Information.”

(i) Regulated Energy

Overview of Business

The regulated energy segment is our largest segment and consists of natural gas distribution and transmission operations on the Delmarva Peninsula and in Florida and an electric distribution operation in Florida.

Natural gas supplies nearly one-fourth of the energy used in the United States. Due to its efficiency, cleanliness and reliability, natural gas is growing increasingly popular. Supplies of natural gas are abundant, and 98.5 percent of the natural gas used in the United States comes from North America. Natural gas is delivered to customers through a safe and efficient underground pipeline system. As the cleanest-burning fossil fuel, increased use of natural gas can help address various environmental concerns today.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 3


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Natural Gas Distribution

Our Delmarva natural gas distribution operation serves 49,639 residential and 5,320 commercial and industrial customers in central and southern Delaware and on Maryland’s eastern shore. For the year ended December 31, 2012, operating revenues and deliveries by customer class for our Delmarva natural gas distribution operation were as follows:

 

     Operating Revenues     Deliveries  
     (in thousands)     (in Dts)  

Residential

   $ 42,452         62     2,511,444         28

Commercial

     19,250         29     2,717,673         29

Industrial

     5,648         8     3,876,693         42
  

 

 

    

 

 

   

 

 

    

 

 

 

Subtotal

     67,350         99     9,105,810         99

Interruptible

     229         0     124,063         1

Other (1)

     657         1     —            —     
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 68,236         100     9,229,873         100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) 

Operating revenues from “Other” include unbilled revenue, rental of gas properties, and other miscellaneous charges.

Our Florida natural gas distribution operation consists of Chesapeake’s Florida division, FPU’s natural gas operation, which was acquired in October 2009, and FPU’s Indiantown division, which was acquired in August 2010. Each component of our Florida natural gas distribution operation is separately regulated, as to its rates and service, by the Florida PSC. On a combined basis, our Florida natural gas distribution operation serves 62,386 residential customers and 6,670 commercial and industrial customers in 21 counties in Florida. For the year ended December 31, 2012, operating revenues and deliveries by customer class for our Florida natural gas distribution operation were as follows:

 

     Operating Revenues     Deliveries  
     (in thousands)     (in Dts)  

Residential

   $ 24,578         33     1,532,234         7

Commercial

     31,331         42     4,140,437         18

Industrial

     15,897         20     17,611,441         74

Other (1)

     3,561         5     181,566         1
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 75,367         100     23,465,678         100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) 

Operating revenues from “Other” include unbilled revenue, conservation revenue, fees for billing services provided to third parties, other miscellaneous charges and adjustments for pass-through taxes.

Natural Gas Transmission

Eastern Shore operates a 428-mile interstate pipeline system that transports natural gas from various points in Pennsylvania to our Delaware and Maryland natural gas distribution divisions, as well as to other utilities and industrial customers in southern Pennsylvania, Delaware and on the eastern shore of Maryland. Eastern Shore also provides swing transportation service and contract storage services. For the year ended December 31, 2012, operating revenues and deliveries by customer class for Eastern Shore were as follows:

 

     Operating Revenues     Deliveries  
     (in thousands)     (in Dts)  

Local distribution companies

   $ 22,365        66     7,765,044        23

Industrial

     8,548        25     23,337,949        68

Commercial

     2,947        9     2,986,146        9

Other (1)

     46        0     —           —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Subtotal

     33,906        100     34,089,139        100

Less: affiliated local distribution companies

     (14,125       (4,082,037  
  

 

 

     

 

 

   

Total non-affiliated

   $ 19,781          30,007,102     
  

 

 

     

 

 

   

 

(1) 

Operating revenues from “Other” sources are from rental of gas properties and reserve for rate case refund.

Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”) provides natural gas transportation service to FPU’s natural gas operation and an unaffiliated customer. Peninsula Pipeline transports natural gas to FPU in Nassau County, Florida, utilizing the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, which Peninsula Pipeline jointly owns with the Peoples Gas System division of Tampa Electric Company (“Peoples Gas”), as well as other pipelines solely owned by Peninsula Pipeline. Peninsula Pipeline commenced service to FPU in Nassau County, Florida in April 2012 and generated $1.6 million in operating revenues for the year ended December 31, 2012.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 4


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Peninsula Pipeline also provides natural gas transportation service to an unaffiliated customer under a 20-year agreement. This service, which began in January 2009, is provided at a fixed monthly charge through Peninsula Pipeline’s eight-mile pipeline located in Suwanee County, Florida. For the year ended December 31, 2012, Peninsula Pipeline generated $264,000 in operating revenues under the contract.

Electric Distribution

Our Florida electric distribution operation distributes electricity to 31,066 customers in four counties in northeast and northwest Florida. For the year ended December 31, 2012, operating revenues and deliveries by customer class for the FPU electric distribution operation were as follows:

 

     Operating Revenues     Deliveries  
     (in thousands)     (in MWHs)  

Residential

   $ 40,814        49     292,980         44

Commercial

     38,079        46     310,008         46

Industrial

     7,513        9     58,640         9
  

 

 

   

 

 

   

 

 

    

 

 

 

Subtotal

     86,406        104     661,628         99

Other (1)

     (3,845     -4     9,370         1
  

 

 

   

 

 

   

 

 

    

 

 

 

Total

   $ 82,561        100     670,998         100
  

 

 

   

 

 

   

 

 

    

 

 

 

 

(1)

Operating revenues from “Other” include unbilled revenue, conservation revenue, other miscellaneous charges and adjustments for pass-through taxes.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 5


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Supplies, Transmission and Storage

We believe that the availability of supply and transmission of natural gas and electricity is adequate under existing arrangements to meet the anticipated needs of customers.

Natural Gas Distribution- Delmarva Peninsula

Our Delaware and Maryland natural gas distribution divisions have both firm and interruptible transportation service contracts with five interstate “open access” pipeline companies, including our Eastern Shore pipeline. These divisions are directly interconnected with the Eastern Shore pipeline, and have contracts with interstate pipelines upstream of Eastern Shore, including Transcontinental Gas Pipe Line Company LLC (“Transco”), Columbia Gas Transmission LLC (“Columbia”), Columbia Gulf Transmission Company (“Gulf”) and Texas Eastern Transmission, LP (“TETLP”). The Transco, Columbia and TETLP pipelines are directly interconnected with the Eastern Shore pipeline. The Gulf pipeline is directly interconnected with Columbia and indirectly interconnected with the Eastern Shore pipeline. None of the upstream pipelines is owned or operated by Chesapeake or any of its operating divisions and subsidiaries.

On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP in conjunction with TETLP’s new expansion project. On February 23, 2012, in accordance with the terms outlined in the Precedent Agreement, our Delaware and Maryland divisions entered into two separate firm transportation service agreements with TETLP for 30,000 Dekatherms per day (“Dts/d”) and 10,000 Dts/d, respectively, commencing in November 2012. In November 2013, the maximum daily quantity under these agreements increases to 34,100 Dts/d and 15,900 Dts/d for our Delaware and Maryland divisions, respectively. These new firm transportation service agreements provide us with an additional direct interconnection with Eastern Shore’s transmission system and access to new sources of supply from other natural gas production regions, including the Appalachian production region, thereby providing increased reliability and diversity of supply. They also provide our Delaware and Maryland divisions with needed upstream transportation capacity to meet current and projected customer requirements.

The Delaware and Maryland divisions use their firm transportation resources to meet a significant percentage of their projected demand requirements. They purchase firm natural gas supplies to meet those projected requirements with purchases of baseload, daily spot and storage service. This gas is transported by the upstream pipelines and delivered to their interconnections with the Eastern Shore pipeline. The Delaware and Maryland divisions also have the capability to use propane-air peak-shaving equipment to supplement or displace natural gas purchases.

The following table shows the firm transportation and storage capacity for peak-day deliverability that the Delaware and Maryland divisions currently have under contract with Eastern Shore and pipelines upstream of the Eastern Shore pipeline, including the respective contract expiration dates.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 6


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Delaware

 

Pipeline

   Firm transportation
capacity maximum
peak-day daily
deliverability

(in Dts)
     Firm storage capacity
maximum peak-day
daily withdrawal

(in Dts)
     Expiration

Transco

     21,423         6,230       Various dates between 2013 and 2028

Columbia

     10,960         8,224       Various dates between 2014 and 2020

Gulf

     880         —         Expires in 2014

TETLP

     30,000         —         Expires in 2027

Eastern Shore

     70,654         4,146       Various dates between 2013 and 2027

Maryland

        

Pipeline

   Firm transportation
capacity maximum
peak-day daily
deliverability

(in Dts)
     Firm storage capacity
maximum peak-day
daily withdrawal

(in Dts)
     Expiration

Transco

     6,128         2,970       Various dates between 2013 and 2015

Columbia

     4,200         3,663       Various dates between 2014 and 2019

Gulf

     590         —         Expires in 2014

TETLP

     10,000         —         Expires in 2027

Eastern Shore

     27,398         2,307       Various dates between 2013 and 2027

Natural Gas Distribution – Florida

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties and Peninsula Energy Services Company, Inc. (“PESCO”), our natural gas marketing subsidiary. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.

 

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Contracts by Chesapeake’s Florida natural gas distribution division include two contracts with FGT, which expire on July 31, 2015 and 2020, and one contract with Gulfstream, which expires in 2022. These contracts are summarized in the following table:

 

Pipeline

   Month(s)    Daily Firm
Transportation Capacity

(in Dts)
     Expiration

FGT

   January to December      1,000       July 2015

FGT

   November to April      17,639       July 2020

FGT

   May to September      15,092       July 2020

FGT

   October      16,579       July 2020

Gulfstream

   January to December      10,000       May 2022

FPU has two firm transportation contracts with FGT, which expire in February 2015 and July 2020, respectively. FPU also has a third contract with FGT expiring in 2013, which contains reductions in the contracted transportation capacity between 2016 and 2023. FPU’s firm transportation contract with Florida City Gas expires in 2013. In 2012, FPU entered into a 15-year firm transportation agreement with Peninsula Pipeline to provide natural gas service into Nassau and Okeechobee counties in Florida. These contracts are summarized in the following table:

 

Pipeline

   Month(s)    Daily Firm
Transportation
Capacity

(in Dts)
     Expiration

Florida City Gas

   January to December      300       December 2013

FGT

   January to April      10,564       February 2015

FGT

   May to October      4,478       February 2015

FGT

   November to December      10,564       February 2015

FGT

   January to March      29,421       July 2020

FGT

   April      24,808       July 2020

FGT

   May to September      9,943       July 2020

FGT

   October      10,485       July 2020

FGT

   November to December      29,421       July 2020

FGT

   January to December      1,822       Various dates between 2016 and 2023

Peninsula Pipeline

   January to December      7,500       December 2027

FPU uses gas marketers and producers to procure all of its gas supplies for its natural gas distribution operation. FPU also uses Peoples Gas to provide wholesale gas sales service in areas distant from its interconnections with FGT.

Natural Gas Transmission

Eastern Shore has three contracts with Transco for a total of 7,292 dekatherms (“Dts”) of firm peak day storage entitlements and total storage capacity of 288,003 Dts. One of the contracts expires in 2013 and the other two expire in 2023. Eastern Shore is in the process of negotiating a 10-year extension of the contract which expires in 2013. Eastern Shore has retained these firm storage services in order to provide swing transportation service and firm storage service to customers that have requested such services.

Electric Distribution

Our electric distribution operation purchases its wholesale electricity primarily from two suppliers, JEA (formerly known as Jacksonville Electric Authority) and Gulf Power Company (“Gulf Power”), under all requirements contracts expiring in December 2017 and 2019, respectively. The JEA contract provides generation and transmission service to northeast Florida. The Gulf Power contract provides generation and transmission service to northwest Florida. Our electric distribution operation also has a renewable energy purchase agreement with Rayonier Performance Fibers, LLC (“Rayonier”). The Rayonier contract, which expires in 2023, commits FPU to purchase between 1.7 megawatt hour (“MWH”) and 3.0 MWH of electricity annually.

 

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Competition

See discussion of competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”

Rates and Regulation

Our natural gas and electric distribution operations are subject to regulation by the Delaware, Maryland or Florida PSC with respect to various aspects of their business, including rates for sales and transportation to all customers in each respective regulatory jurisdiction. All of our firm distribution sales rates are subject to fuel cost recovery mechanisms, which match revenues with natural gas and electric supply and transportation costs and normally allow full recovery of such costs. Adjustments under these mechanisms, which are limited to such costs, require periodic filings and hearings with the state PSC having jurisdiction.

Eastern Shore is subject to regulation as an interstate pipeline by the FERC, which regulates the terms and conditions of service and the rates Eastern Shore can charge for its transportation and storage services. Peninsula Pipeline is subject to regulation by the Florida PSC.

The following table shows the regulatory jurisdictions under which our regulated energy businesses currently operate, including the effective dates of the most recent full rate proceedings and the rates of return that were authorized therein:

 

Regulated Business

   Regulatory
Jurisdiction
   Effective Date of
the Currrent Rates
    Allowed
Return
 

Chesapeake—Delaware Division

   Delaware PSC      9/3/2008        10.25 (1) 

Chesapeake—Maryland Division

   Maryland PSC      12/1/2007        10.75 (1) 

Chesapeake—Florida Division

   Florida PSC      1/14/2010        10.80 (1) 

FPU—Natural Gas

   Florida PSC      1/14/2010  (3)      10.85 (1) 

FPU—Indiantown Division

   Florida PSC      6/17/2004        11.50 (1) 

FPU—Electric

   Florida PSC      5/22/2008        11.00 (1) 

Eastern Shore

   FERC      7/29/2011        13.90 (2) 

 

(1) 

Allowed return on equity

(2) 

Allowed overall pre-tax, pre-interest rate of return

(3) 

Effective date of the order approving the settlement agreement, which adjusted rates originally approved on June 4, 2009.

Peninsula Pipeline provides services based on negotiated rates, which are approved by the Florida PSC.

Management monitors the achieved rates of return of each of our regulated energy operations in order to ensure timely filing of rate cases.

Regulatory Proceedings

See discussion of regulatory activities in Item 8 under the heading “Notes to the Consolidated Financial Statements – Note 17, Rates and Other Regulatory Activities.”

 

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Seasonality of Natural Gas and Electric Distribution Revenues

Revenues from our residential and commercial natural gas distribution activities are affected by seasonal variations in weather conditions, which directly influence the volume of natural gas and electricity sold and delivered. Specifically, customer demand substantially increases during the winter months, when natural gas and electricity are used for heating. For electricity, customer demand also increases during the summer months, when electricity is used for cooling. Accordingly, the volumes sold for these purposes are directly affected by the severity of summer and winter weather and can vary substantially from year to year. Sustained warmer-than-normal temperatures during the heating season will tend to reduce use of natural gas and electricity, while sustained colder-than-normal temperatures will tend to increase consumption. Sustained cooler-than-normal temperatures during the cooling season will negatively affect electricity consumption. We measure the relative impact of weather by using an accepted degree-day methodology. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above or below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one heating degree-day. Each degree of temperature above 65 degree Fahrenheit is counted as one cooling degree-day. Normal heating degree-days are based on the most recent 10-year average.

For the electric distribution operations in northeast and northwest Florida, hot summers and cold winters produce year-round electric sales that normally do not have large seasonal fluctuations.

In an effort to stabilize the level of net revenues collected from customers in Maryland regardless of weather conditions, we implemented a weather normalization adjustment for our residential heating and smaller commercial heating customers. A weather normalization adjustment is a billing adjustment mechanism that is designed to eliminate the effect of deviations from average seasonal temperatures on utility net revenues.

Delaware, like many other states, has been looking at ways to enable implementation of energy efficiency and is considering revenue decoupling, which is a mechanism for separating the revenue needed to recover the fixed cost of delivery from the variable cost that fluctuates with the amount of natural gas consumed. Although the Delaware PSC has been investigating whether to implement a revenue decoupling mechanism for the natural gas distribution utilities in the state, it is uncertain as to whether the Delaware PSC will require our Delaware natural gas distribution division to file a request for decoupling or whether our Delaware division will file such request on its own.

(ii) Unregulated Energy

Overview of Business

Our unregulated energy segment provides propane distribution, propane wholesale marketing and natural gas marketing services to customers.

Propane Distribution

Propane is a form of liquefied petroleum gas, which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is a gas at normal pressure, it is easily compressed into liquid form for storage and transportation. Propane is a clean-burning fuel, gaining increased recognition for its environmental superiority, safety, efficiency, transportability and ease of use relative to alternative forms of fossil fuels. Propane is sold primarily in suburban and rural areas which are not served by natural gas distributors.

Our propane distribution operations sell propane primarily to residential, commercial/industrial and wholesale customers. Approximately 77 percent of operating revenues in 2012 were generated by the sales to retail residential, commercial and industrial customers. Sharp Energy Inc. (“Sharp”), our propane distribution subsidiary, serves 34,837 customers throughout Delaware, the eastern shore of Maryland and Virginia, and southeastern Pennsylvania. Our Florida propane distribution subsidiaries provide propane distribution service to 14,475 customers in various counties in Florida. For the year ended December 31, 2012, operating revenues and total gallons sold by our Delmarva and Florida propane distribution operations were as follows:

 

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     Operating Revenues     Total Gallons Sold  

Service Area

   (in thousands)     (in thousands)  

Delmarva

   $ 60,985         76     31,441         84

Florida

     18,931         24     5,997         16
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 79,916         100     37,438         100
  

 

 

    

 

 

   

 

 

    

 

 

 

Propane Wholesale Marketing

Xeron, Inc. (“Xeron”), our propane wholesale marketing subsidiary, markets propane to major independent oil and petrochemical companies, wholesale resellers and retail propane companies located primarily in the southeastern United States. Xeron enters into forward contracts with various counterparties to commit to purchase or sell an agreed-upon quantity of propane at an agreed-upon price at a specified future date, which typically ranges from one to six months from the execution of the contract. At the expiration of the forward contracts, Xeron typically settles its purchases and sales financially without taking the physical delivery of propane. Xeron also enters into futures and other option contracts that are traded on the InterContinentalExchange, Inc. The level and profitability of the propane wholesale marketing activity is affected by both propane wholesale price volatility and liquidity in the wholesale market. In 2012, Xeron had operating revenues totaling approximately $2.5 million, net of the associated cost of propane sold. For further discussion of Xeron’s wholesale marketing activities, market risks and controls that monitor Xeron’s risks, see Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk.”

Xeron does not own physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.

Natural Gas Marketing

Our natural gas marketing subsidiary, PESCO, provides natural gas supply and supply management services to 3,189 customers in Florida and 28 customers on the Delmarva Peninsula. It competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers through competitively-priced contracts. PESCO does not own or operate any natural gas transmission or distribution assets. The gas that PESCO sells is delivered to retail customers through affiliated and non-affiliated local distribution company systems and transmission pipelines. PESCO bills its customers through the billing services of the regulated utilities that deliver the gas, or directly, through its own billing capabilities. For the year ended December 31, 2012, PESCO’s operating revenues and deliveries were as follows:

 

     Operating Revenues     Deliveries  

Service Area

   (in thousands)     (in Dts)  

Florida

   $ 42,019        86     14,766,667        91

Delmarva

     7,020        14     1,544,849        9
  

 

 

   

 

 

   

 

 

   

 

 

 

Subtotal

     49,039        100     16,311,516        100

Less: sale to affiliate

     (3,029       (856,615  
  

 

 

     

 

 

   

Total unaffiliated

   $ 46,010          15,454,901     
  

 

 

     

 

 

   

PESCO currently has contracts with natural gas production companies for the purchase of firm natural gas supplies. These contracts provide a maximum firm daily entitlement of 35,000 Dts and expire in May 2013. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements prior to the end of the term of the existing contracts.

Supplies, Transportation and Storage

Our propane distribution operations purchase propane primarily from suppliers, including major oil companies, independent producers of natural gas liquids and from Xeron. In current markets, supplies of propane from these and other sources are readily available for purchase.

 

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Our propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to our bulk storage facilities. We own bulk propane storage facilities with an aggregate capacity of approximately 3.4 million gallons at various locations in Delaware, Maryland, Pennsylvania, Virginia and Florida. From these storage facilities, propane is delivered by “bobtail” trucks, owned and operated by us, to tanks located at the customers’ premises.

Competition

See discussion of competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”

Rates and Regulation

Propane distribution, propane wholesale marketing and natural gas marketing activities are not subject to any federal or state pricing regulation. Transport operations are subject to regulations concerning the transportation of hazardous materials promulgated by the Federal Motor Carrier Safety Administration within the United States Department of Transportation and enforced by the various states in which such operations take place. Propane distribution operations are also subject to state safety regulations relating to “hook-up” and placement of propane tanks.

Seasonality of Propane Revenues

Revenues from our propane distribution sales activities are affected by seasonal variations in weather conditions. Weather conditions directly influence the volume of propane sold and delivered to customers; specifically, customers’ demand substantially increases during the winter months when propane is used for heating. Accordingly, the propane volumes sold for this purpose are directly affected by the severity of winter weather and can vary substantially from year to year. Sustained warmer-than-normal temperatures will tend to reduce propane use, while sustained colder-than-normal temperatures will tend to increase consumption.

Many of our propane distribution customers are “bulk delivery” customers. We make deliveries of propane to the bulk delivery customers as needed, based on the level of propane remaining in the tank located at the customer’s premises. We invoice and record revenues for our bulk delivery service customers at the time of delivery, rather than upon customers’ actual usage, since the customers own the propane gas in the tank on their premises. The timing of deliveries to the bulk delivery customers can vary significantly from year to year depending on weather variation.

(iii) Other

The “Other” segment consists primarily of our advanced information services subsidiary, other unregulated subsidiaries that own real estate leased to Chesapeake and its subsidiaries and certain unallocated corporate costs, which are not directly attributable to a specific business unit.

Advanced Information Services

Our advanced information services subsidiary, BravePoint®, Inc. (“BravePoint”), is headquartered in Norcross, Georgia, and provides domestic and a limited number of international clients with information technology services and solutions for both enterprise and e-business applications.

Other Subsidiaries

Skipjack, Inc. and Eastern Shore Real Estate, Inc. own and lease office buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is an affiliated investment company incorporated in Delaware.

(c) Additional Information about the Business

(i) Capital Budget

A discussion of capital expenditures by business segment and capital expenditures for environmental remediation facilities is included in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

 

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(ii) Employees

As of December 31, 2012, we had a total of 738 employees, 127 of whom are union employees represented by three labor unions: the International Brotherhood of Electrical Workers, the International Chemical Workers Union and United Food and Commercial Workers Union, all of whose collective bargaining agreements expire in 2013.

(iii) Financial Information about Geographic Areas

All of our material operations, customers and assets are located in the United States.

(d) Available Information

As a public company, we file annual, quarterly and other reports, as well as our annual proxy statement and other information, with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room, 100 F Street, N.E., Washington, DC 20549-5546; the public may obtain information from the Public Reference Room by calling the SEC at 1-800-SEC-0330.

The SEC also maintains an Internet site that contains reports, proxy and information statements and other information regarding the Company. The address of the SEC’s Internet website is www.sec.gov. We make available, free of charge, on our Internet website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. The address of our Internet website is www.chpk.com. The content of this website is not part of this report.

We have a Business Code of Ethics and Conduct applicable to all employees, officers and directors and a Code of Ethics for Financial Officers. Copies of the Business Code of Ethics and Conduct and the Code of Ethics for Financial Officers are available on our Internet website. We also adopted Corporate Governance Guidelines and Charters for the Audit Committee, Compensation Committee and Corporate Governance Committee of the Board of Directors, each of which satisfies the regulatory requirements established by the SEC and the New York Stock Exchange (“NYSE”). The Board of Directors has also adopted Corporate Governance Guidelines on Director Independence, which conform to the NYSE listing standards on director independence. These documents are available on our Internet website or may be obtained by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, DE 19904.

If we make any amendment to, or grant a waiver of, any provision of the Business Code of Ethics and Conduct or the Code of Ethics for Financial Officers applicable to our principal executive officer, president, principal financial officer, principal accounting officer or controller, the amendment or waiver will be disclosed within four business days in a press release, by website disclosure, or by filing a current report on Form 8-K with the SEC.

Our Chief Executive Officer certified to the NYSE on May 31, 2012, that as of that date, he was unaware of any violation by Chesapeake of the NYSE’s corporate governance listing standards.

 

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ITEM 1A. RISK FACTORS.

The following is a discussion of the primary factors that may affect the operations or financial performance of our regulated and unregulated businesses. Refer to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 of this report for an additional discussion of these and other related factors that affect our operations and/or financial performance.

Financial Risks

Instability and volatility in the financial markets could have a negative impact on our ability to access capital at competitive rates.

Our business strategy includes the continued pursuit of growth, both organically and through acquisitions. To the extent that we do not generate sufficient cash flow from operations, we may incur additional indebtedness to finance our growth. Specifically, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows from our operations. We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. However, if we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.

A downgrade in our credit rating could adversely affect our access to capital markets and our cost of capital.

Our ability to obtain adequate and cost-effective capital depends on our credit ratings, which are greatly affected by our financial performance and the liquidity of financial markets. A downgrade in our current credit ratings could adversely affect our access to capital markets, as well as our cost of capital.

If we fail to comply with our debt covenant obligations, we could experience adverse financial consequences that could affect our liquidity and ability to borrow funds.

Our long-term debt obligations and committed short-term lines of credit contain financial covenants related to debt-to-capital ratios and interest-coverage ratios. Failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or the inability to borrow under certain credit agreements. Any such acceleration would cause a material adverse change in our financial condition.

An increase in interest rates may adversely affect our results of operations and cash flows.

An increase in interest rates, without the recovery of the higher cost of debt in the sales and/or transportation rates we charge our utility customers, could adversely affect future earnings. An increase in short-term interest rates would negatively affect our results of operations, which depend on short-term lines of credit to finance accounts receivable and storage gas inventories, as well as to temporarily finance capital expenditures.

Inflation may impact our results of operations, cash flows and financial position.

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. To help cope with the effects of inflation on our capital investments and returns, we seek rate increases from regulatory commissions for regulated operations and closely monitor the returns of our unregulated operations. There can be no assurance that we will be able to obtain adequate and timely rate increases to offset the effects of inflation. To compensate for fluctuations in propane gas prices, we adjust our propane selling prices to the extent allowed by the market. There can be no assurance, however, that we will be able to increase propane sales prices sufficiently to compensate fully for such fluctuations in the cost of propane gas to us.

 

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Our energy marketing subsidiaries are exposed to market risks, beyond our control, which could adversely affect our financial results and capital requirements.

Our energy marketing subsidiaries are subject to market risks beyond their control, including market liquidity and commodity price volatility. Although we maintain risk management policies, we may not be able to offset completely the price risk associated with volatile commodity prices, which could lead to volatility in earnings. Physical trading also has price risk on any net open positions at the end of each trading day, as well as volatility resulting from: (i) intra-day fluctuations of natural gas and/or propane prices, and (ii) daily price movements between the time natural gas and/or propane is purchased or sold for future delivery and the time the related purchase or sale is hedged. The determination of our net open position at the end of any trading day requires us to make assumptions as to future circumstances, including the use of natural gas and/or propane by its customers in relation to its anticipated market positions. Because the price risk associated with any net open position at the end of such day may increase if the assumptions are not realized, we review these assumptions daily. Net open positions may increase volatility in our financial condition or results of operations if market prices move in a significantly favorable or unfavorable manner, because the timing of the recognition of profits or losses on the economic hedges for financial accounting purposes usually does not match up with the timing of the economic profits or losses on the item being hedged. This volatility may occur, with a resulting increase or decrease in earnings or losses, even though the expected profit margin is essentially unchanged from the date the transactions were consummated.

Our energy marketing subsidiaries are exposed to credit risk of their counterparties.

Our energy marketing subsidiaries extend credit to counterparties and continually monitor and manage collections aggressively. Each of these subsidiaries is exposed to the risk that it may not be able to collect amounts owed to it. If the counterparty to such a transaction fails to perform, and any underlying collateral is inadequate, we could experience financial losses.

Our energy marketing subsidiaries are dependent upon the availability of credit to successfully operate their businesses.

Our energy marketing subsidiaries are dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If financial market conditions decline generally, or the financial condition of these subsidiaries or of our Company declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.

Current market conditions have adversely impacted the return on plan assets for our pension plans, which may require significant additional funding.

We have pension plans that have been closed to new employees. The costs of providing benefits and related funding requirements of these plans are subject to changes in the market value of the assets that fund the plans and the discount rates used to estimate the pension benefit obligations. As a result of the extreme volatility and disruption in the domestic and international equity, bond and interest rate markets in recent years, the asset values and benefit obligations of Chesapeake’s and FPU’s pension plans have fluctuated significantly since 2008. The funded status of the plans and the related costs reflected in our financial statements are affected by various factors that are subject to an inherent degree of uncertainty, particularly in the current economic environment. Future losses of asset values and further declines in discount rates may necessitate accelerated funding of the plans in the future to meet minimum federal government requirements as well as higher pension expense to be recorded in future years. Adverse changes on the asset values and benefit obligations of our pension plans may require us to record higher pension expense and fund obligations earlier than originally planned, which would have an adverse impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.

Operational Risks

Fluctuations in weather may cause a significant variance in our earnings.

Our natural gas and propane distribution operations are sensitive to fluctuations in weather conditions, which directly influence the volume of natural gas and propane we sell and deliver to our customers. A significant portion of our natural gas and propane distribution revenues is derived from the sales and deliveries of natural gas and propane to residential and commercial heating customers during the five-month peak heating season (November through March). If the weather is warmer than normal, we sell and deliver less natural gas and propane to customers, and earn less revenue, which could adversely affect our results of operations, cash flows and financial condition.

 

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Our electric operation, while generally less seasonal than natural gas and propane sales because electricity is used for both heating and cooling in our service areas, is also affected by variations in general weather conditions and particularly unusually severe weather conditions.

The amount and availability of natural gas, propane and electricity supplies are difficult to predict; a substantial reduction in available supplies could reduce our earnings in those segments.

Natural gas, propane and electricity production can be affected by factors beyond our control, such as weather, closings of energy generation facilities and refineries. If we are unable to obtain sufficient natural gas, electricity and propane supplies to meet demand, results in those businesses may be adversely affected. Any substantial decrease in the availability of supplies of natural gas, propane and electricity could result in increased supply costs and higher prices for customers, which could also adversely affect our financial condition and results of operations.

We rely on a limited number of natural gas, propane and electricity suppliers, the loss of which could have a material adverse effect on our financial condition and results of operations.

We have entered into various agreements with suppliers to purchase natural gas, propane and electricity to serve our customers. The loss of any significant suppliers or our inability to renew these contracts at favorable terms upon their expiration could significantly affect our ability to serve our customers and have a material adverse impact on our financial condition and results of operations.

A substantial disruption or lack of growth in interstate natural gas pipelines’ transmission and storage capacity and electric transmission capacity may impair our ability to meet customers’ existing and future requirements.

In order to meet existing and future customer demands for natural gas and electricity, we must acquire sufficient supplies of natural gas and electricity, interstate pipeline transmission and storage capacity, and electric transmission capacity to serve such requirements. We must contract for reliable and adequate upstream transmission capacity for our distribution systems while considering the dynamics of the interstate pipeline and storage and electric transmission markets, our own on-system resources, as well as the characteristics of our markets. Our financial condition and results of operations would be materially and adversely affected if the future availability of these capacities were insufficient to meet future customer demands for natural gas and electricity. Currently, our Florida natural gas operation relies primarily on one pipeline system, FGT, for most of its natural gas supply and transmission. Our Florida electric operation relies primarily on two suppliers, Gulf Power for the northwest service territory and JEA for the northeast service territory. Any interruption to these systems could adversely affect our ability to meet the demands of FPU’s customers and our earnings.

Commodity price increases may adversely affect the operating costs and competitive positions of our natural gas, electric and propane distribution operations, which may adversely affect our results of operations, cash flows and financial condition.

Natural Gas/Electric. Higher natural gas prices can significantly increase the cost of gas billed to our natural gas customers. Increases in the cost of coal, natural gas and other fuels used to generate electricity can significantly increase the cost of electricity billed to our electric customers. Damage to the production or transportation facilities of our suppliers, decreasing their supply of natural gas and electricity, could result in increased supply costs and higher prices for our customers. Such cost increases generally have no immediate effect on our revenues and net income because of our regulated fuel cost recovery mechanisms. Our net income, however, may be reduced by higher expenses that we may incur for uncollectible customer accounts and by lower volumes of natural gas and electricity deliveries when customers reduce their consumption. Therefore, increases in the price of natural gas, coal and other fuels can affect our operating cash flows and the competitiveness of natural gas and electricity as energy sources and consequently have an adverse effect on our operating cash flows.

 

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Propane. Propane costs are subject to volatile changes as a result of product supply or other market conditions, including weather and economic and political factors affecting crude oil and natural gas supply or pricing. For example, weather conditions could damage production or transportation facilities, which could result in decreased supplies of propane, increased supply costs and higher prices for customers. Such cost changes can occur rapidly and can affect profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate in response to propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, declines in retail sales volumes due to reduced consumption and increased amounts of uncollectible accounts may adversely affect net income.

Our propane inventory is subject to inventory valuation risk, which may result in a write-down of inventory.

Our propane distribution operations own bulk propane storage facilities, with an aggregate capacity of approximately 3.4 million gallons. We purchase and store propane based on several factors, including inventory levels and the price outlook. We may purchase large volumes of propane at current market prices during periods of low demand and low prices, which generally occur during the summer months. Propane is a commodity, and as such, its price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the wholesale price of the propane that we purchase can change rapidly over a short period of time. The retail market price for propane could fall below the price at which we made the purchases, which would adversely affect our profits or cause sales from that inventory to be unprofitable. In addition, falling propane prices may result in inventory write-downs as required by accounting principles generally accepted in the United States of America (“GAAP”) if the market price of propane falls below our weighted average cost of inventory, which could adversely affect net income.

Operating events affecting public safety and the reliability of our natural gas and electric distribution and transmission systems could adversely affect our operations and increase our costs.

Our natural gas and electric operations are exposed to operational events and risks, such as major leaks, outages, mechanical failures and breakdown, operations below expected level of performance or efficiency and accidents that could affect public safety and the reliability of our distribution and transmission systems, significantly increase costs and cause loss of customer confidence. If we are unable to recover from customers through the regulatory process, all or some of these costs and our authorized rate of return, our results of operations, financial condition and cash flows could be adversely affected.

We operate in a competitive environment and we may lose customers to competitors.

Natural Gas. Our natural gas marketing operations compete with third-party suppliers to sell natural gas to commercial and industrial customers. Our natural gas transmission and distribution operations compete with interstate pipelines when our transmission and/or distribution customers are located close enough to a competing pipeline to make direct connections economically feasible. Failure to retain and grow our customer base in the natural gas operations would have an adverse effect on our financial condition, cash flows and results of operations.

Electric. While there is active wholesale power sales competition in Florida, our retail electric business through FPU has remained substantially free from direct competition from other electric service providers. Generally, however, our retail electric business through FPU remains subject to competition from other energy sources. Changes in the competitive environment caused by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect our results of operations, cash flows and financial condition.

Propane. Our propane distribution operations compete with other propane distributors, primarily on the basis of service and price. Some of our competitors have significantly greater resources. Our ability to grow the propane distribution business is contingent upon capturing additional market share, expanding into new markets, and successfully utilizing pricing programs that retain and grow our customer base. Failure to retain and grow our customer base in our propane distribution operations would have an adverse effect on our results of operations, cash flows and financial condition.

 

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Our propane wholesale marketing operation competes with various marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.

Energy conservation could lower energy consumption and adversely affect our earnings.

We have seen various legislative and regulatory initiatives to promote energy efficiency and conservation at both federal and state levels. In response to the initiatives in the states, in which we operate, we have put into place programs to promote energy efficiency by our current and potential customers. To the extent a PSC allows us to recover the cost of such energy efficiency promotion, funding for such programs is recovered through the rates we charge to our regulated customers. However, lower energy consumption as a result of energy efficiency and conservation by current and potential customers may adversely affect our results of operations, cash flows and financial condition.

Changes in technology may adversely affect our advanced information services subsidiary’s competitiveness.

BravePoint participates in a market that is characterized by rapidly changing technology and accelerating product introduction cycles. The success of our advanced information services subsidiary depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services, on a timely basis, and by keeping pace with technological developments and emerging industry standards. There is no assurance that we will be able to keep up with technological advancements to the degree necessary to keep our products and services competitive.

Our use of derivative instruments may adversely affect our results of operations.

Fluctuating commodity prices may affect our earnings and financing costs because our propane distribution and wholesale marketing operations use derivative instruments, including forwards, futures, swaps and puts, to hedge price risk. In addition, we have utilized in the past, and may decide, after further evaluation, to continue to utilize derivative instruments to hedge price risk. While we have risk management policies and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial condition may be adversely affected.

Changes in customer growth may affect earnings and cash flows.

Our ability to increase gross margins in our regulated energy and unregulated propane distribution businesses is dependent upon growth in the residential construction market, adding new commercial and industrial customers and conversion of customers to natural gas, electricity or propane from other energy sources. Slowdowns in growth may adversely affect our gross margin, earnings and cash flows.

Our businesses are capital intensive, and the increased costs and/or delays of capital projects may adversely affect our future earnings.

Our businesses are capital intensive and require significant investments in on-going infrastructure projects. There are limited materials and qualified vendors that can be used in our projects. Our ability to timely complete our infrastructure projects and manage the overall cost of those projects is affected by the availability of the necessary materials and qualified vendors. Our future earnings could be adversely affected if we are unable to manage such capital projects effectively, or if full recovery of such capital costs is not permitted in future regulatory proceedings.

Our regulated energy business may be at risk if franchise agreements are not renewed.

Our regulated natural gas and electric distribution operations hold franchises in each of the incorporated municipalities that require franchise agreements in order to provide natural gas and electricity. Our natural gas and electric distribution operations are currently in negotiations for franchises with certain municipalities for new service areas and renewal of some existing franchises. Ongoing financial results would be adversely impacted from the loss of service to certain operating areas within our electric or natural gas territories in the event that franchise agreements were not renewed.

A strike, work stoppage or a labor dispute could adversely affect our operations.

We are party to collective bargaining agreements with various labor unions at some of our Florida operations. A strike, work stoppage or a labor dispute with a union or employees represented by a union could cause interruption to our operations. If a strike, work stoppage or other labor dispute were to occur, our results could be adversely affected.

 

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Accidents, natural disasters, severe weather (such as a major hurricane) and acts of terrorism could adversely impact earnings.

Inherent in energy transmission and distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, explosions, sabotage and mechanical problems. Natural disasters and severe weather may damage our assets, cause operational interruptions and result in the loss of human life. The threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas, electricity and propane that could affect our operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and companies in the energy industry may face a heightened risk of exposure to acts of terrorism. The insurance industry may also be affected by natural disasters, severe weather and acts of terrorism, and as a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms, which could adversely affect our results of operations, financial condition and cash flows.

A security breach disrupting our operating systems and facilities or exposing confidential information may adversely affect our reputation, disrupt our operations and increase our costs.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber-terrorism, could lead to system disruptions or generate facility shutdowns. If such an attack or security breach were to occur, our business, results of operations and financial condition could be adversely affected. Additionally, the protection of customer, employee and Company data is crucial to our operational security. A breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could occur and have an adverse effect on our reputation, results of operations and financial condition. A breakdown or breach could also materially increase our costs of maintaining our system and protecting it against future breakdowns or breaches. We take reasonable precautions to safeguard our information systems from cyber-attacks and security breaches; however, there is no guarantee that the procedures implemented to protect against unauthorized access to our information systems are adequate to safeguard against all attacks and breaches.

Regulatory, Legal and Environmental Risks

Regulation of our businesses, including changes in the regulatory environment, may adversely affect our results of operations, cash flows and financial condition.

The Delaware, Maryland and Florida PSCs regulate our utility operations in those states. Eastern Shore is regulated by the FERC. The PSCs and the FERC set the rates that we can charge customers for services subject to their regulatory jurisdiction. Our ability to obtain timely future rate increases and rate supplements to maintain current rates of return depends on regulatory approvals, and there can be no assurance that our regulated operations will be able to obtain such approvals or maintain currently authorized rates of return. When our earnings from the regulated utilities exceed the authorized rate of return, the respective PSC or the FERC in the case of Eastern Shore may require us to reduce our rates charged to customers in the future.

We are dependent upon construction of new facilities to support future growth in earnings in our natural gas and electric distribution and natural gas transmission operations.

Construction of new facilities required to support future growth is subject to various regulatory and developmental risks, including but not limited to: (a) our ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on terms that are acceptable to us; (b) potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; (c) inability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; (d) lack of anticipated future growth in available natural gas and electricity supply; and (e) insufficient customer throughput commitments.

 

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We are subject to operating and litigation risks that may not be fully covered by insurance.

Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting, transmitting and delivering natural gas, electricity and propane to end users. From time to time, we are a defendant in legal proceedings arising in the ordinary course of business. We maintain insurance policies with insurers to cover our general liabilities in the amount of $51 million, which we believe are reasonable and prudent. There can be no assurance, however, that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.

We may face certain regulatory and financial risks related to pipeline safety legislation.

A number of legislative proposals to implement increased oversight over natural gas pipeline operations and increased investment in facilities to inspect pipeline facilities, upgrade pipeline facilities, or control the impact of a breach of such facilities are pending at the federal level. Additional operating expenses and capital expenditures may be necessary to remain in compliance with the increased federal oversight resulting from such proposals. If such legislation is adopted and we incur additional expenses and expenditures as a result, our financial condition, results of operations and cash flows could be adversely affected, particularly if we are not authorized through the regulatory process to recover from customers some or all of these costs and our authorized rate of return.

Costs of compliance with environmental laws may be significant.

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long period of time to control environmental effects at our current and former operating sites, especially former manufactured gas plant (“MGP”) sites. Compliance with these legal obligations requires us to commit capital. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines.

To date, we have been able to recover, through regulatory rate mechanisms, the costs associated with the remediation of former MGP sites. There is no guarantee, however, that we will be able to recover future remediation costs in the same manner or at all. A change in our approved rate mechanisms for recovery of environmental remediation costs at former MGP sites could adversely affect our results of operations, cash flows and financial condition.

Further, existing environmental laws and regulations may be revised, or new laws and regulations seeking to protect the environment may be adopted and be applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable.

Derivatives legislation and the implementation of related rules could have an adverse impact on our ability to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) regulates derivative transactions, which include certain instruments used in our risk management activities. The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility, subject to certain exceptions for entities that use swaps to hedge or mitigate commercial risk. Although the Dodd-Frank Act includes significant new provisions regarding the regulation of derivatives, the impact of those requirements will not be known definitively until regulations have been adopted and fully implemented by both the SEC and the Commodities Futures Trading Commission, and market participants establish registered clearing facilities under those regulations. The legislation and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties.

Our business may be subject in the future to additional regulatory and financial risks associated with global warming and climate change.

There have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. The adoption of this type of legislation by Congress or similar legislation by states or the adoption of related regulations by federal or state governments mandating a substantial reduction in greenhouse gas emissions in the future could have far-reaching and significant impacts on the energy industry. Such new legislation or regulations could result in increased compliance costs for us or additional operating restrictions on our business, affect the demand for natural gas and propane or impact the prices we charge to our customers. At this time, we cannot predict the potential impact of such laws or regulations that may be adopted on our future business, financial condition or financial results.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

(a) General

We own offices and operate facilities in the following locations: Pocomoke, Salisbury, Cambridge, Easton, Elkton and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; Lecato, Virginia; and West Palm Beach, DeBary, Inglis, Indiantown, Marianna, Lantana, Lauderhill, Fernandina Beach, Micco, Newberry, Clewiston, Okeechobee, and Winter Haven, Florida. We rent office space in Dover and Ocean View, Delaware; West Palm Beach, Fernandina Beach, Clewiston, Okeechobee, and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Colora and Centerville, Maryland; Honey Brook, Blakeslee, Mount Pocono and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In general, we believe that our offices and facilities are adequate for the uses for which they are employed.

(b) Natural Gas Distribution

Our Delmarva natural gas distribution operation owns approximately 1,162 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in our Delaware and Maryland service areas. Our Florida natural gas distribution operation owns 2,532 miles of natural gas distribution mains (and related equipment). In addition, we have adequate gate stations to handle receipt of the gas in each of the distribution systems. We also own facilities in Delaware and Maryland, which we use for propane-air injection during periods of peak demand.

(c) Natural Gas Transmission

Eastern Shore owns and operates approximately 428 miles of transmission pipeline, extending from supply interconnects at Parkesburg, Daleville and Honey Brook, Pennsylvania; and Hockessin, Delaware, to approximately 93 delivery points in southeastern Pennsylvania, Delaware and the eastern shore of Maryland.

Peninsula Pipeline owns and operates approximately eight miles of transmission pipeline in Suwanee County, Florida. Peninsula Pipeline also owns approximately 45 percent of the 16-mile pipeline extending from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. The remaining 55 percent of the pipeline is owned by Peoples Gas.

(d) Electric Distribution

Our electric distribution operation owns and operates 20 miles of electric transmission line located in northeast Florida and 878 miles of electric distribution line located in northeast and northwest Florida.

(e) Propane Distribution and Wholesale Marketing

Our Delmarva propane distribution operation owns bulk propane storage facilities, with an aggregate capacity of approximately 2.7 million gallons, at 31 plant facilities in Delaware, Maryland, Pennsylvania and Virginia, located on real estate that is either owned or leased by our Company. Our Florida propane distribution operation owns 32 bulk propane storage facilities with a total capacity of 732,000 gallons. Xeron does not own physical storage facilities or equipment to transport propane; however, it leases propane storage and pipeline capacity from non-affiliated third parties.

 

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(f) Lien

All of the properties owned by FPU are subject to a lien in favor of the holders of its first mortgage bonds securing its indebtedness under its Mortgage Indenture and Deed of Trust. FPU owns offices and operates facilities in the following locations: West Palm Beach, DeBary, Inglis, Indiantown, Marianna, Lantana, Lauderhill, Fernandina Beach, Micco, Newberry, Clewiston and Okeechobee, Florida. FPU’s natural gas distribution operation owns 1,722 miles of natural gas distribution mains (and related equipment) in its service areas. FPU’s electric distribution operation owns and operates 20 miles of electric transmission line located in northeast Florida and 878 miles of electric distribution line located in northeast and northwest Florida. FPU’s propane distribution operation owns 32 bulk propane storage facilities with a total capacity of 732,000 gallons located in south and central Florida.

ITEM 3. LEGAL PROCEEDINGS.

(a) General

As disclosed in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note 19, Other Commitments and Contingencies,” we are involved in various legal actions and claims arising in the normal course of business. We are also involved in certain administrative proceedings before various governmental or regulatory agencies concerning rates. In the opinion of management, the ultimate disposition of these current proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

(b) Environmental

See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note 18, Environmental Commitments and Contingencies.”

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

 

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ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT.

Set forth below are the names, ages, and positions of our executive officers with their recent business experience. The age of each officer is as of the filing date of this report.

 

Name

   Age     

Position

Michael P. McMasters

     54       President and Chief Executive Officer

Beth W. Cooper

     46       Senior Vice President and Chief Financial Officer

Stephen C. Thompson

     52       Senior Vice President and President, Eastern Shore

Elaine B. Bittner

     43       Vice President of Strategic Development

Michael P. McMasters was appointed Chief Executive Officer effective January 1, 2011. He was appointed President on March 1, 2010 and was elected a director in 2010. Prior to his appointments and election, Mr. McMasters served as Executive Vice President and Chief Operating Officer since September 2008, Chief Financial Officer from 1997 to 2008 and Senior Vice President since 2004 to 2008. He has previously held the positions of Vice President, Treasurer, Director of Accounting and Rates, and Controller of the Company. In addition to his tenure with Chesapeake, Mr. McMasters also served as Director of Operations Planning for Equitable Gas Company. He has 33 years of experience in the utilities industry.

Beth W. Cooper was appointed Senior Vice President and Chief Financial Officer in September 2008 and Corporate Secretary in June 2005. Previously, she has served as Vice President from June 2005 to September 2008 and Treasurer from 2003 to May of 2012. Ms. Cooper joined the Company in 1990 and has previously served in the following roles: Assistant Vice President, Assistant Treasurer, Assistant Secretary, Director of Internal Audit and Director of Strategic Planning. Before joining the Company, Ms. Cooper was an auditor with Ernst & Young’s Entrepreneurial Services Group. She has 22 years of experience in the utilities industry.

Stephen C. Thompson was appointed Senior Vice President in 2004. Mr. Thompson is also President of Eastern Shore. Mr. Thompson joined the Company in 1983 and during his tenure has served as Senior Vice President and Vice President of the Company. Mr. Thompson also served as Director of Gas Supply and Marketing, Superintendent of Eastern Shore, and Regional Manager for the Florida distribution operations. Mr. Thompson has 29 years of experience in the utilities industry.

Elaine B. Bittner was appointed Vice President of Strategic Development in June of 2010. Previously, she has held various positions within the Company including Vice President of Eastern Shore from 2005 to 2010, Director of Eastern Shore, Director of Customer Services and Regulatory Affairs for Eastern Shore, Director of Environmental Affairs for Chesapeake and Environmental Engineer. Prior to joining the Company, Ms. Bittner was a Project Chemist, Client Consultant and Environmental Lab Chemist in the environmental industry specializing in environmental analysis and reporting related to volatile organic compounds. Ms. Bittner has 16 years of experience in the utilities industry.

 

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PART II

ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

(a) Common Stock Price Ranges, Common Stock Dividends and Shareholder Information:

Our common stock is listed on the NYSE under the symbol “CPK.” The high, low and closing prices of our common stock and dividends declared per share for each calendar quarter during 2012 and 2011 were as follows:

 

     Quarter Ended    High      Low      Close      Dividends
Declared
Per Share
 

2012

              
   March 31    $ 43.83       $ 39.89       $ 41.12       $ 0.345   
   June 30    $ 45.15       $ 40.22       $ 43.72       $ 0.365   
   September 30    $ 48.51       $ 43.65       $ 47.36       $ 0.365   
   December 31    $ 48.92       $ 41.17       $ 45.40       $ 0.365   

2011

              
   March 31    $ 42.47       $ 37.67       $ 41.62       $ 0.330   
   June 30    $ 43.14       $ 37.66       $ 40.03       $ 0.345   
   September 30    $ 41.50       $ 36.00       $ 40.11       $ 0.345   
   December 31    $ 44.53       $ 38.30       $ 43.35       $ 0.345   

Holders

At February 28, 2013, there were 2,348 holders of record of Chesapeake common stock.

Dividends

We have paid a cash dividend to common stock shareholders for 52 consecutive years. Dividends are payable at the discretion of our Board of Directors. Future payment of dividends, and the amount of these dividends, will depend on our financial condition, results of operations, capital requirements, and other factors. We declared quarterly cash dividends on our common stock in 2012 and 2011, totaling $1.440 per share and $1.365 per share, respectively.

Indentures to our long-term debt contain various restrictions. In terms of restrictions which limit the payment of dividends by Chesapeake, each of its unsecured senior notes contains a “Restricted Payments” covenant. The most restrictive covenants of this type are included within the 7.83 percent Senior Notes, due January 1, 2015. The covenant provides that Chesapeake cannot pay or declare any dividends or make any other Restricted Payments (such as dividends) in excess of the sum of $10.0 million plus consolidated net income of the Company accrued on and after January 1, 2001. As of December 31, 2012, Chesapeake’s cumulative consolidated net income base was $185.3 million, offset by Restricted Payments of $103.0 million, leaving $82.3 million of cumulative net income free of restrictions.

Each series of FPU’s first mortgage bonds contains a similar restriction that limits the payment of dividends by FPU. The most restrictive covenants of this type are included within the series that is due in 2022, which provides that FPU cannot make dividend or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. As of December 31, 2012, FPU had a cumulative net income base of $85.1 million, offset by restricted payments of $37.6 million, leaving $47.5 million of cumulative net income of FPU free of restrictions based on this covenant.

Recent Sales of Unregistered Securities

No securities were sold during the year 2012 that were not registered under the Securities Act of 1933, as amended.

 

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(b) Purchases of Equity Securities by the Issuer

The following table sets forth information on purchases by or on behalf of Chesapeake of shares of its common stock during the quarter ended December 31, 2012.

 

    Total           Total Number of Shares     Maximum Number of  
    Number     Average     Purchased as Part of     Shares That May Yet Be  
    of Shares     Price Paid     Publicly Announced Plans     Purchased Under the Plans  

Period

  Purchased     per Share     or Programs (2)     or Programs (2)  

October 1, 2012 through October 31, 2012 (1)

    250      $ 48.31        —          —     

November 1, 2012 through November 30, 2012

    —          —          —          —     

December 1, 2012 through December 31, 2012

    —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

    250      $ 48.31        —          —     
 

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Chesapeake purchased shares of common stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 15, Employee Benefit Plans.” During the quarter, 250 shares were purchased through the reinvestment of dividends on deferred stock units.

(2) 

Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Discussion of our compensation plans, for which shares of Chesapeake common stock are authorized for issuance, is included in the portion of the Proxy Statement captioned “Equity Compensation Plan Information” to be filed no later than March 31, 2013, in connection with our Annual Meeting to be held on or about May 2, 2013, and is incorporated herein by reference.

(c) Chesapeake Utilities Corporation Common Stock Performance Graph

The following Stock Performance graph compares cumulative total stockholder return on a hypothetical investment in our common stock during the five fiscal years ended December 31, 2012, with the cumulative total stockholder return on a hypothetical investment in both (i) the Standard & Poor’s 500 Index (“S&P 500 Index”), and (ii) an industry index consisting of Chesapeake and 10 companies from the current Edward Jones Natural Gas Distribution Group, a published listing of selected gas distribution utilities’ results. The Compensation Committee compares the performance of the companies from the Edward Jones Natural Gas Distribution Group to our performance for purposes of determining the level of long-term performance awards earned by our named executive officers.

The 10 companies from the current Edward Jones Natural Gas Distribution Group are: AGL Resources, Inc., Atmos Energy Corporation, Delta Natural Gas Company, Inc., The Laclede Group, Inc., New Jersey Resources Corporation, Northwest Natural Gas Company, Piedmont Natural Gas Company, Inc., RGC Resources, Inc., South Jersey Industries, Inc., and WGL Holdings, Inc.

The comparison assumes $100 was invested on December 31, 2007 in our common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of our common stock.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 25


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LOGO

 

     2007      2008      2009      2010      2011      2012  

Chesapeake

   $ 100       $ 103       $ 109       $ 145       $ 156       $ 169   

Industry Index

   $ 100       $ 107       $ 111       $ 130       $ 151       $ 147   

S&P 500

   $ 100       $ 63       $ 80       $ 92       $ 94       $ 109   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 26


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ITEM 6. SELECTED FINANCIAL DATA

 

For the Years Ended December 31,

   2012      2011      2010  

Operating (1)

        

(in thousands)

        

Revenues

        

Regulated Energy

   $ 246,208       $ 256,226       $ 269,438   

Unregulated Energy

     133,049         149,586         146,793   

Other

     13,245         12,215         11,315   
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 392,502       $ 418,027       $ 427,546   

Operating income

        

Regulated Energy

   $ 46,999       $ 43,911       $ 43,267   

Unregulated Energy

     8,355         9,619         8,150   

Other

     1,281         175         513   
  

 

 

    

 

 

    

 

 

 

Total operating income

   $ 56,635       $ 53,705       $ 51,930   

Net income from continuing operations

   $ 28,863       $ 27,622       $ 26,056   
  

 

 

    

 

 

    

 

 

 

Assets

        

(in thousands)

        

Gross property, plant and equipment

   $ 697,159       $ 625,488       $ 584,385   

Net property, plant and equipment

   $ 541,781       $ 487,704       $ 462,757   

Total assets

   $ 733,746       $ 709,066       $ 670,993   

Capital expenditures (1)

   $ 78,210       $ 44,431       $ 46,955   
  

 

 

    

 

 

    

 

 

 

Capitalization

        

(in thousands)

        

Stockholders’ equity

   $ 256,598       $ 240,780       $ 226,239   

Long-term debt, net of current maturities

     101,907         110,285         89,642   
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 358,505       $ 351,065       $ 315,881   

Current portion of long-term debt

     8,196         8,196         9,216   

Short-term debt

     61,199         34,707         63,958   
  

 

 

    

 

 

    

 

 

 

Total capitalization and short-term financing

   $ 427,900       $ 393,968       $ 389,055   
  

 

 

    

 

 

    

 

 

 

 

(1) 

These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. We closed our distributed energy operation in 2007. All assets of the water businesses were sold in 2004 and 2003. These amounts also include accruals for capital expenditures that we have incurred for each reporting period.

(2) 

These amounts include the financial position and results of operation of FPU for the period from the merger (October 28, 2009) to December 31, 2009. These amounts also include the effects of acquisition accounting and issuance of Chesapeake common shares as a result of the merger.

(3) 

FASB ASC 718, Compensation—Stock Compensation, and FASB ASC 715, Compensation—Retirement Plans, were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 27


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2009(2)     2008     2007     2006 (3)     2005     2004     2003  
           
           
           
$ 138,671      $ 116,123      $ 128,566      $ 124,438      $ 124,445      $ 98,037      $ 91,990   
  119,973        161,290        115,190        94,320        90,995        67,607        59,197   
  10,141        14,030        14,530        12,442        14,045        12,311        12,381   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
$ 268,785      $ 291,443      $ 258,286      $ 231,200      $ 229,485      $ 177,955      $ 163,568   
           
$ 26,668      $ 23,833      $ 21,739      $ 18,618      $ 16,278      $ 16,270      $ 16,208   
  8,390        3,600        5,244        3,650        4,167        3,185        4,321   
  (1,322     1,046        1,131        1,064        1,476        722        1,050   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
$ 33,736      $ 28,479      $ 28,114      $ 23,332      $ 21,921      $ 20,177      $ 21,579   
$ 15,897      $ 13,607      $ 13,218      $ 10,748      $ 10,699      $ 9,686      $ 10,079   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
           
           
$ 543,905      $ 381,689      $ 352,838      $ 325,836      $ 280,345      $ 250,267      $ 234,919   
$ 436,587      $ 280,671      $ 260,423      $ 240,825      $ 201,504      $ 177,053      $ 167,872   
$ 615,811      $ 385,795      $ 381,557      $ 325,585      $ 295,980      $ 241,938      $ 222,058   
$ 26,294      $ 30,844      $ 30,142      $ 49,154      $ 33,423      $ 17,830      $ 11,822   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
           
           
$ 209,781      $ 123,073      $ 119,576      $ 111,152      $ 84,757      $ 77,962      $ 72,939   
  98,814        86,422        63,256        71,050        58,991        66,190        69,416   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
$ 308,595      $ 209,495      $ 182,832      $ 182,202      $ 143,748      $ 144,152      $ 142,355   
  35,299        6,656        7,656        7,656        4,929        2,909        3,665   
  30,023        33,000        45,664        27,554        35,482        5,002        3,515   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
$ 373,917      $ 249,151      $ 236,152      $ 217,412      $ 184,159      $ 152,063      $ 149,535   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 28


Table of Contents

For the Years Ended December 31,

   2012     2011     2010  

Common Stock Data and Ratios

      

Basic earnings per share from continuing operations (1)

   $ 3.01      $ 2.89      $ 2.75   

Diluted earnings per share from continuing operations (1)

   $ 2.99      $ 2.87      $ 2.73   

Return on average equity from continuing operations (1)

     11.6     11.6     11.6

Common equity / total capitalization

     71.6     68.6     71.6

Common equity / total capitalization and short-term financing

     60.0     61.1     58.2

Book value per share

   $ 26.74      $ 25.15      $ 23.75   
  

 

 

   

 

 

   

 

 

 

Market price:

      

High

   $ 48.920      $ 44.530      $ 42.200   

Low

   $ 39.890      $ 36.000      $ 28.010   

Close

   $ 45.400      $ 43.350      $ 41.520   
  

 

 

   

 

 

   

 

 

 

Average number of shares outstanding

     9,586,144        9,555,799        9,474,554   

Shares outstanding at year-end

     9,597,499        9,567,307        9,524,195   

Registered common shareholders

     2,396        2,481        2,482   

Cash dividends declared per share

   $ 1.44      $ 1.37      $ 1.31   

Dividend yield (annualized) (4)

     3.2     3.2     3.2

Payout ratio from continuing operations (1) (5)

     47.8     47.4     47.6
  

 

 

   

 

 

   

 

 

 

Additional Data

      

Customers

      

Natural gas distribution

     124,015        121,934        120,230   

Electric distribution

     31,066        30,986        30,966   

Propane distribution

     49,312        48,824        48,100   
  

 

 

   

 

 

   

 

 

 

Volumes

      

Natural gas deliveries (in Dts)

     66,784,690        57,493,022        49,310,314   

Electric Distribution (in MWHs)

     670,998        694,653        751,507   

Propane distribution (in thousands of gallons)

     37,438        37,387        39,807   
  

 

 

   

 

 

   

 

 

 

Heating degree-days (Delmarva Peninsula)

      

Actual HDD

     3,936        4,221        4,831   

10-year average HDD (normal)

     4,491        4,499        4,528   

Heating degree-days (Florida)

      

Actual HDD

     633        753        1,501   

10-year average HDD (normal)

     915        920        863   

Cooling degree-days (Florida)

      

Actual CDD

     2,871        2,858        2,859   

10-year average CDD (normal)

     2,756        2,718        2,695   

Propane bulk storage capacity (in thousands of gallons)

     3,400        3,351        3,041   

Total employees (1)

     738        711        734   
  

 

 

   

 

 

   

 

 

 

 

(1) 

These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. We closed our distributed energy operation in 2007. All assets of the water businesses were sold in 2004 and 2003.

(2) 

These amounts include the financial position and results of operation of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009.

(3) 

FASB ASC 718, Compensation—Stock Compensation, and FASB ASC 715, Compensation—Retirement Plans, were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

(4) 

Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then dividing that amount by the closing common stock price at December 31.

(5) 

The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 29


Table of Contents
2009(2)     2008     2007     2006 (3)     2005     2004     2003  
           
$ 2.17      $ 2.00      $ 1.96      $ 1.78      $ 1.83      $ 1.68      $ 1.80   
$ 2.15      $ 1.98      $ 1.94      $ 1.76      $ 1.81      $ 1.64      $ 1.76   
  11.2     11.2     11.5     11.0     13.2     12.8     14.4
  68.0     58.7     65.4     61.0     59.0     54.1     51.2
  56.1     49.4     50.6     51.1     46.0     51.3     48.8
$ 22.33      $ 18.03      $ 17.64      $ 16.62      $ 14.41      $ 13.49      $ 12.89   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
           
$ 35.000      $ 34.840      $ 37.250      $ 35.650      $ 35.780      $ 27.550      $ 26.700   
$ 22.020      $ 21.930      $ 28.000      $ 27.900      $ 23.600      $ 20.420      $ 18.400   
$ 32.050      $ 31.480      $ 31.850      $ 30.650      $ 30.800      $ 26.700      $ 26.050   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  7,313,320        6,811,848        6,743,041        6,032,462        5,836,463        5,735,405        5,610,592   
  9,394,314        6,827,121        6,777,410        6,688,084        5,883,099        5,778,976        5,660,594   
  2,670        1,914        1,920        1,978        2,026        2,026        2,069   
$ 1.25      $ 1.21      $ 1.18      $ 1.16      $ 1.14      $ 1.12      $ 1.10   
  3.9     3.9     3.7     3.8     3.7     4.2     4.2
  57.6     60.5     60.2     65.2     62.3     66.7     61.1

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
           
           
  117,887        65,201        62,884        59,132        54,786        50,878        47,649   
  31,030        —          —          —          —          —          —     
  48,680        34,981        34,143        33,282        32,117        34,888        34,894   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
           
  50,159,227        46,539,142        42,910,964        41,826,357        43,716,921        39,469,915        37,478,009   
  105,739        —          —          —          —          —          —     
  32,546        27,956        29,785        24,243        26,178        24,979        25,147   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
           
  4,729        4,431        4,504        3,931        4,792        4,553        4,715   
  4,462        4,401        4,376        4,372        4,436        4,389        4,409   
           
  911        —          —          —          —          —          —     
  849        —          —          —          —          —          —     
           
  2,770        —          —          —          —          —          —     
  2,687        —          —          —          —          —          —     
  3,042        2,471        2,441        2,315        2,315        2,045        2,195   
  757        448        445        437        423        426        439   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 30


Table of Contents

ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This section provides management’s discussion of Chesapeake and its consolidated subsidiaries, with specific information on results of operations, liquidity and capital resources, as well as discussion of how certain accounting principles affect our financial statements. It includes management’s interpretation of financial results of the Company and its operating segments, the factors affecting these results, the major factors expected to affect future operating results as well as investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.

Several factors exist that could influence our future financial performance, some of which are described in Item 1A, “Risk Factors.” They should be considered in connection with forward-looking statements contained in this report, or otherwise made by or on behalf of us, since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

The following discussions and those later in the document on operating income and segment results include the use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated energy operations and under its competitive pricing structure for unregulated natural gas marketing and propane distribution operations. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

(a) Introduction

We are a diversified utility company engaged, directly or through subsidiaries, in regulated energy businesses, unregulated energy businesses, and other unregulated businesses, including advanced information services.

Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:

 

  executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital;

 

  expanding the regulated energy distribution and transmission businesses into new geographic areas and providing new services in our current service territories;

 

  expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities;

 

  expanding both our regulated energy and unregulated energy businesses through strategic acquisitions;

 

  utilizing our expertise across our various businesses to improve overall performance;

 

  pursuing and entering new unregulated energy markets that will complement our existing strategy and operating units;

 

  enhancing marketing channels to attract new customers;

 

  providing reliable and responsive customer service to existing customers so they become our best promoters;

 

  empowering and engaging our employees at all levels to work in unison to achieve our strategy;

 

  engaging our local communities and governments in a cooperative and mutually beneficial way;

 

  maintaining a capital structure that enables us to access capital as needed;

 

  maintaining a consistent and competitive dividend for shareholders; and

 

  creating and maintaining a diversified customer base, energy portfolio and utility foundation.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 31


Table of Contents

(b) Highlights and Recent Developments

Our net income for 2012 was $28.9 million, or $2.99 per share (diluted), compared to $27.6 million, or $2.87 per share (diluted), and $26.1 million, or $2.73 per share (diluted), for 2011 and 2010, respectively.

Our operations are primarily related to natural gas, electricity and propane, both in the regulated and unregulated sectors, and are generally located on the Delmarva Peninsula and in Florida. We also have an advanced information services subsidiary, which provides both products and consulting services. The following is a summary of key factors affecting our businesses and their impacts on our results. More detailed discussion and analysis are provided in the “Results of Operations” section.

Growth

We continue to see growth in our natural gas businesses from our efforts over the past several years to expand our services by delivering clean-burning, environmentally friendly natural gas to customers. We are identifying and developing additional opportunities that will generate growth over the next several years.

New natural gas transmission services and growth in natural gas distribution customers generated $3.6 million and $2.7 million, respectively, in additional gross margin for 2012, compared to 2011. These increases in gross margin were related primarily to the continued execution of our strategic plan, including expansion of natural gas service to new areas and conversion of several large commercial and industrial customers to natural gas. In addition, new services are being initiated by our natural gas transmission subsidiaries in response to increased demand for natural gas service on the Delmarva Peninsula and in Florida, both from our natural gas distribution operations and other unaffiliated customers directly connected to the transmission systems.

Major Expansion Initiatives and Customer Growth Reflected in Results

In late 2011 and during 2012, we expanded natural gas transmission and distribution services to Sussex County, Delaware and Nassau County, Florida and also initiated natural gas transmission service in Worcester and Cecil Counties, Maryland. These major expansion initiatives increased our natural gas footprint, delivering natural gas service to areas where it was not previously available. These initiatives generated $2.9 million of additional gross margin for our natural gas transmission operations in 2012. Natural gas distribution service to two large industrial customers in Lewes, Delaware and two industrial facilities of an existing customer in southeastern Sussex County, Delaware generated $588,000 of additional gross margin for 2012. The following table summarizes our major expansion initiatives that have already commenced (dollars in thousands):

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 32


Table of Contents

Project

   Date of
New Service
   2011
Margin
     2012
Margin
     Estimated
Annualized
Margin
 

Sussex County, DE expansion

           

Transmission (for Lewes, DE)—3,250 Dts/d

   Nov-11    $ 156       $ 935       $ 935   

Distribution—Two large industrial customers in Lewes, DE

   Dec-11      1         500         391   

Transmission (for southeastern part) 1,550 Dts/d

   Mar-12 to May-12      —            334         446   

Distribution—Two facilities of an existing customer in the southeastern part of Sussex County

   Mar-12 to Aug-12      —            89         154   
     

 

 

    

 

 

    

 

 

 
      $ 157       $ 1,858       $ 1,926   

Cecil County, MD expansion

           

Transmission—4,070 Dts/d

   Nov-12    $ —         $ 147       $ 882   

Worcester County, MD expansion

           

Transmission—1,450 Dts/d

   Jun-12 to Jan-13    $ —         $ 90       $ 391   

Nassau County, FL expansion

           

Transmission—A new fixed annual rate service (1)

   Apr-12    $ —         $ 1,537       $ 2,100   
     

 

 

    

 

 

    

 

 

 
      $ 157       $ 3,632       $ 5,299   
     

 

 

    

 

 

    

 

 

 

Total by Geographic Location of the Project:

           

Delmarva Natural Gas Distribution

      $ 1       $ 589       $ 545   

Delmarva Natural Gas Transmission

        156         1,506         2,654   

Florida Natural Gas Transmission

        —            1,537         2,100   
     

 

 

    

 

 

    

 

 

 
      $ 157       $ 3,632       $ 5,299   
     

 

 

    

 

 

    

 

 

 

 

(1) 

Peninsula Pipeline commenced its service in April 2012, using compressed natural gas while a new pipeline was being constructed. The new pipeline was completed and placed in service in December 2012. Peninsula Pipeline is expected to incur approximately $800,000 in annual transportation costs upon the completion of the new pipeline, which will reduce this gross margin.

Other Growth

In addition to the recent expansion initiatives, the Delmarva natural gas distribution operation has added 12 new large industrial and commercial customers since the beginning of 2011, which generated $574,000 in additional gross margin in 2012, compared to 2011. Growth in residential and other commercial customers on the Delmarva Peninsula generated $513,000 in additional gross margin in 2012. Customer growth in Florida, primarily from commercial and industrial customers, generated $986,000 in additional gross margin in 2012.

Future Major Expansion Initiatives and Opportunities

Although not affecting results in 2012, Eastern Shore entered into precedent agreements with NRG Energy Center Dover LLC (“NRG”) and PBF Energy Inc. (“Delaware City Refinery”) to further expand its transmission system in order to provide additional services to these customers. Eastern Shore expects to enter into firm transportation service agreements with NRG and Delaware City Refinery upon satisfaction of certain conditions pursuant to the respective precedent agreements. These additional services are expected to be initiated in late 2013. A delay in obtaining the regulatory approval from the FERC for construction of these new facilities could delay the service initiation.

In Florida, Peninsula Pipeline entered into a firm transportation agreement with an unaffiliated utility, which will generate an estimated annual gross margin of approximately $840,000. This service is expected to be initiated in the second quarter of 2013 upon completion of construction of the new facility.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 33


Table of Contents

The following table summarizes our future major expansion initiatives and opportunities (dollars in thousands):

 

     Date of    Estimated

Project

   New Service    Annualized Margin

Service to an unaffiliated Florida utility (1)

   Apr-13    $840

Service to NRG’s Dover, DE electric generation plant

     

Transmission—13,440 Dts/d (2)

   Nov-13    $2,400 to $2,800

Delaware City refinery expansion

     

Transmission—15,000 Dts/d (2)(3)

   Dec-13    $1,600
     

 

      $4,840 to $5,240
     

 

 

(1)

Estimated annual margin is based on a fixed monthly reservation charge agreed to by the customer.

(2)

A precedent agreement has been executed by the parties for these services. The figures provided represent the estimated margin pursuant to the respective precedent agreement. A firm transportation service agreement will be executed by the parties upon satisfying certain conditions.

(3) 

This contract is expected to replace the 10,000 Dts/d contract with annualized gross margin of $1.1 million, which expired in November 2012.

As we expand our natural gas service to new areas, first through transmission service and distribution service to large industrial customers, our natural gas distribution operations continue to pursue additional opportunities to provide service to residential and other commercial and industrial customers in those areas. In an effort to increase the availability of natural gas within our Delaware service areas, our Delaware natural gas distribution division filed an application with the Delaware PSC in June 2012 to add several natural gas expansion service offerings. These offerings include a monthly fixed charge in lieu of upfront contributions from customers to extend the distribution system and optional service offerings to assist customers in the process of converting to natural gas. The goal of these new offerings is to meet the energy needs of residents, communities and businesses throughout our service territory, specifically in areas of southeastern Sussex County, where natural gas will now be available. The Delaware PSC is currently reviewing this application.

Acquisition

In June 2012, we entered into an agreement with Eastern Shore Gas Company and its affiliates (collectively “ESG,” which is not related to our interstate natural gas transmission subsidiary) to purchase their operating assets for approximately $16.5 million. These assets are currently used to provide propane distribution service to approximately 11,000 residential and commercial customers in Worcester County, Maryland, primarily through underground propane gas distribution systems. We are evaluating the potential conversion of some of these underground propane distribution systems to natural gas where it is economical and feasible. We filed an application with the Maryland PSC for approval of the transaction in August 2012. The transaction, which is also subject to obtaining consents from certain local jurisdictions to the assignment of certain franchise agreements and the satisfaction of other closing conditions, is expected to be completed in 2013. We expect to finance the acquisition using unsecured short-term debt. The acquisition is expected to be accretive to earnings per share in 2013 and thereafter.

Investing in Growth

To continue our growth, we are expanding our resources and capabilities. We are in the early stages of several natural gas distribution expansions on the Delmarva Peninsula, including expansions into Sussex County, Delaware, and Worcester and Cecil Counties in Maryland. These expansions will require not only the construction or conversion of distribution facilities, but also the conversion of customers’ appliances or equipment inside their homes. We have begun the process of reorganizing our Delmarva natural gas distribution operation and expect to increase our staff to support these expansions. Secondly, as a result of BravePoint’s growth over the last several quarters, BravePoint is continuing to add team members. During 2012, BravePoint’s other operating expenses increased by $1.5 million, compared to 2011, due primarily to the additional staff. Finally, to increase our capacity to appropriately manage future growth, resources have been, and continue to be, added in several key functional areas, including, but not limited to, Human Resources, Communications and Strategic Business Development. During 2012, we incurred $312,000 in additional acquisition-related costs, compared to 2011, and $446,000 in new costs associated with increased capacity for future growth. We expect additional increases in costs associated with these key functional areas in the future.

Weather and Consumption

Weather affects customer energy consumption, especially the consumption by residential and commercial customers during the peak heating and cooling seasons. Natural gas, electricity and propane are all used for heating in our service territories, and we use heating degree-days (“HDD”) to analyze the weather impact. Only electricity is used for cooling and we use cooling degree-days (“CDD”) to analyze the weather impact. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above or below 65 degrees Fahrenheit. Each degree of temperature above or below 65 degrees Fahrenheit is counted as one CDD or one HDD. We use 10-year historical averages to define “normal” weather for this analysis.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 34


Table of Contents

Significantly warmer temperatures in 2012, particularly during the first three months of the year when the demand for natural gas and propane are at their highest, had a large negative impact on our earnings. Lower customer energy consumption directly attributable to warmer temperatures in 2012 reduced gross margin by $3.6 million, compared to 2011. Temperatures in 2012 on the Delmarva Peninsula and in Florida were seven percent (285 HDD) and 16 percent (120 HDD), respectively, warmer than 2011. Compared to normal, temperatures in 2012 on the Delmarva Peninsula and in Florida were 12 percent (555 HDD) and 31 percent (282 HDD), respectively, warmer and reduced gross margin for 2012 by approximately $5.1 million, compared to gross margin that we would have generated under normal temperatures.

CDD remained relatively unchanged in 2012 and 2011 (2,871 CDD in Florida in 2012, compared to 2,858 CDD in Florida in 2011) and did not result in a significant variance in our gross margin.

Other Regulatory Matters

In January 2012, the Florida PSC issued an order approving the recovery of $34.2 million as an acquisition adjustment and $2.2 million in merger-related costs in connection with Chesapeake’s acquisition of FPU in 2009. The inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these assets through amortization expense increase our earnings and cash flows above what we would have achieved absent the regulatory approval. The acquisition adjustment and merger-related costs are to be amortized over 30 years and five years, respectively, beginning in November 2009. Based upon the effective date and outcome of the order, we recorded the amortization as an expense beginning in 2012, which resulted in an increase in amortization expense of $2.4 million in 2012. We expect to record $2.4 million ($1.4 million, net of tax) in amortization expense in 2013, $2.3 million ($1.4 million, net of tax) in 2014, and $1.8 million ($1.1 million, net of tax) annually thereafter until 2039. In FPU’s future rate proceedings, if it is determined that the level of cost savings supporting recovery of the acquisition adjustment no longer exists, the remaining acquisition adjustment may be partially or entirely disallowed by the Florida PSC. If such an event were to occur, we would have to expense the corresponding unamortized amount of the disallowed acquisition adjustment.

In November 2012, the Florida PSC issued an order approving the recognition of a $1.9 million regulatory liability for FPU for a one-time tax contingency gain, including income tax gross-up, to be amortized over a period from January 2012 to October 2014. This tax contingency gain is related to an income tax liability recorded by FPU prior to the merger with Chesapeake. As the liability no longer exists, upon receiving the Florida PSC order, we recorded an amortization credit of $684,000 in 2012, which was recorded in the fourth quarter.

In addition to regulatory proceedings, we were involved in a legal dispute over alleged breaches of a franchise agreement by FPU. Prior to the scheduled trial date, FPU and the City of Marianna reached an agreement in principle to resolve their dispute, which resulted in the City of Marianna dismissing its legal action with prejudice on February 11, 2013. The agreement in principle requires the City of Marianna and FPU to negotiate and prepare a formal settlement agreement that is subject to approval by FPU’s Board of Directors and the City Commission of Marianna, Florida (the “Marianna Commission”). The settlement agreement would contemplate, in pertinent part, the sale of FPU’s facilities within the City of Marianna’s corporate limits to the City of Marianna and, in connection therewith, require the City of Marianna to enter into an operating agreement with FPU pursuant to which FPU will operate and maintain the facilities sold to the City of Marianna. FPU serves approximately 3,000 customers in the City of Marianna. Total litigation expense associated with the City of Marianna litigation is approximately $1.4 million as of December 31, 2012. These costs have been expensed as incurred, however, the Florida PSC has permitted FPU to seek recovery in a future rate proceeding. Additional information is presented in Item 8 under the heading Notes to the Consolidated Financial Statements – Note 19, Other Commitments and Contingencies.”

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 35


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Propane Prices

Propane prices affect both retail and wholesale marketing margins. Our propane distribution operation usually benefits from rising propane prices by selling propane to its customers based upon higher wholesale prices, while its average cost of inventory trails behind. Retail prices generally take into account replacement cost, along with other factors, such as competition and market conditions. When wholesale prices (replacement costs) increase, retail prices generally increase, and our margins expand until the current wholesale price is fully reflected in the average cost of inventory. The opposite occurs when propane prices decline. Our propane wholesale marketing operation benefits from price volatility in the propane wholesale market by entering into trading transactions.

Our propane distribution operations generated additional gross margin of $2.7 million due to higher retail margins per gallon in 2012, compared to 2011. Sustained retail pricing in response to local market conditions, along with lower propane inventory costs as a result of declining wholesale prices and favorable supply plans, contributed to this increase in retail margins per gallon.

Xeron executed trades with higher margins in 2012, compared to 2011, as the market presented opportunities resulting from fluctuations in wholesale propane prices during 2012. Xeron generated $225,000 of additional gross margin in 2012, compared to 2011.

Advanced Information Services

In September 2011, BravePoint, our advanced information services subsidiary, released a new product, ProfitZoom™, an integrated system encompassing financial, job costing and service management modules, which was designed specifically for the fire protection and specialty contracting industries. ProfitZoom™ was built as a successor product to another software solution that BravePoint previously marketed and supported for companies in the fire suppression industry. Understanding the needs of the industry and utilizing its technology expertise, BravePoint began developing the ProfitZoom™ product in 2009. In addition, BravePoint is utilizing a component of ProfitZoom™, “Application Evolution™”, to provide services to new and existing customers both in the fire suppression industry and other unrelated businesses. BravePoint generated $1.4 million in revenue from the sale of these two products and related services during 2012, compared to $572,000 in 2011. To date, BravePoint has successfully implemented or is currently implementing ProfitZoom™ for eight customers in the fire suppression industry. Application Evolution™ is currently utilized by nine customers. These ProfitZoom™ and Application Evolution™ contracts are expected to generate approximately $537,000 in additional revenue over the next 12 months. Additional sales proposals are under consideration by both existing and potential new customers.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 36


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(c) Critical Accounting Policies

We prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. We base our estimates on historical experience and on various assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Since most of our businesses are regulated and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates. Management believes that the following policies require significant estimates or other judgments of matters that are inherently uncertain. These policies and their application have been reviewed by our Audit Committee.

Regulatory Assets and Liabilities

As a result of the ratemaking process, we record certain assets and liabilities in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 980, “Regulated Operations,” and consequently, the accounting principles applied by our regulated energy businesses differ in certain respects from those applied by the unregulated businesses. Costs are deferred when there is a probable expectation that they will be recovered in future revenues as a result of the regulatory process. As more fully described in Item 8 under the heading “Notes to the Consolidated Financial Statements – Note 2, Summary of Significant Accounting Policies,” we have recorded regulatory assets of $80.1 million and regulatory liabilities of $45.1 million at December 31, 2012. If we were required to terminate application of ASC Topic 980, we would be required to recognize all such deferred amounts as a charge or a credit to earnings, net of applicable income taxes. Such an adjustment could have a material effect on our results of operations.

Valuation of Environmental Assets and Liabilities

As more fully described in Item 8 under the heading “Notes to the Consolidated Financial Statements – Note 18, Environmental Commitments and Contingencies,” we are currently participating in the investigation, assessment or remediation of six former MGP sites. We have also been in discussions with the Maryland Department of Environment (“MDE”) regarding a seventh former MGP site. Amounts have been recorded as environmental liabilities and associated environmental regulatory assets based on estimates of future costs to remediate these sites, which are provided by independent consultants, and future recovery of those costs in rates. At December 31, 2012, we had $10.7 million in environmental liabilities, representing our estimate of such future costs. We also had $5.9 million in regulatory and other assets, representing the amount of our environmental remediation costs to be recovered in future rates. There is uncertainty in these amounts, because the United States Environmental Protection Agency (“EPA”), or other applicable state environmental authority, may not have selected the final remediation methods. In addition, there is uncertainty with regard to amounts that may be recovered from other potentially responsible parties.

Derivatives

We use derivative and non-derivative instruments to manage the risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. We also use derivative instruments to engage in propane wholesale marketing activities. We continually monitor the use of these instruments to ensure compliance with our risk management policies and account for them in accordance with appropriate GAAP. If these instruments do not meet the definition of derivatives or are considered “normal purchases and sales,” they are accounted for on an accrual basis of accounting.

The following is a review of our use of derivative instruments at December 31, 2012 and 2011:

 

During 2012 and 2011, our natural gas distribution, electric distribution, propane distribution and natural gas marketing operations entered into physical contracts for the purchase or sale of natural gas, electricity and propane. These contracts either did not meet the definition of derivatives as they did not have a minimum requirement to purchase/sell or were considered “normal purchases and sales,” as they provided for the purchase or sale of natural gas, electricity or propane to be delivered in quantities expected to be used and sold by our operations over a reasonable period of time in the normal course of business. Accordingly, these contracts were accounted for on an accrual basis of accounting.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 37


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During 2012, our propane distribution operation entered into call options to protect against an increase in propane prices associated with the propane purchased for the propane price cap program in December 2012 through March 2013. We accounted for the call options as fair value hedges, and the change in fair value of $111,000 effectively reduced the propane inventory balance at December 31, 2012.

 

During 2011, our propane distribution operation entered into a put option to protect against the decline in propane prices and related potential inventory losses associated with the propane purchased for the propane price cap program in the upcoming heating season. We accounted for the put option as a fair value hedge. Since the propane prices fell below the strike price of $1.445 per gallon in January through March of 2012, we received $118,000 representing the difference between the market price and the strike price during those months.

 

Xeron, our propane wholesale marketing subsidiary, enters into forward, futures and other contracts that are considered derivatives. These contracts are marked to market, using prices at the end of each reporting period, and unrealized gains or losses are recorded in the consolidated statements of income as revenue or expense. These contracts generally mature within one year and are almost exclusively for propane commodities. For 2012 and 2011, these contracts had net unrealized losses of $339,000 and net unrealized gains of $41,000, respectively. We had $210,000 in mark-to-market energy assets and $331,000 in mark-to-market energy liabilities related to these contracts at December 31, 2012. We had $1.7 million in mark-to-market energy assets and $1.5 million in mark-to-market energy liabilities related to these contracts at December 31, 2011.

Operating Revenues

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC of each state in which we operate. Eastern Shore’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.

For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers, and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.

The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in the statement of income. For propane bulk delivery customers without meters and advanced information services customers, we record revenue in the period the products are delivered and/or services are rendered.

Each of our natural gas distribution operations in Delaware and Maryland, our bundled natural gas distribution service in Florida and our electric distribution operation in Florida has a fuel cost recovery mechanism. This mechanism provides us with a method of adjusting billing rates to customers to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

We charge flexible rates to industrial interruptible customers on our natural gas distribution systems to compete with the price of alternative fuel that they can use. Neither we nor any of our interruptible customers are contractually obligated to deliver or receive natural gas on a firm service basis.

Allowance for Doubtful Accounts

An allowance for doubtful accounts is recorded against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experience, the condition of the overall economy and our assessment of our customers’ inability or reluctance to pay. If circumstances change, however, our estimate of the recoverability of accounts receivable may also change. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 38


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Pension and Other Postretirement Benefits

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on the pension costs and liabilities. The assumed discount rates, the assumed health care cost trend rates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Item 8 under the heading “Notes to the Consolidated Financial Statements – Note 15, Employee Benefit Plans,” including plan asset investment allocation, estimated future benefit payments, general descriptions of the plans, significant assumptions, the impact of certain changes in assumptions, and significant changes in estimates.

Total pension and other postretirement benefit costs included in operating income were $599,000, $1.9 million and $2.0 million, in 2012, 2011 and 2010, respectively. The total costs for 2012 include a curtailment gain of $892,000 associated with a plan change for the postretirement medical plan for FPU, effective January 1, 2012, $170,000 of which was recorded in 2012 and the remaining portion was deferred as a regulatory liability. The total costs for 2011 included $436,000 of settlement charges associated with the retirement of a former executive. We expect to record pension and postretirement benefit costs of approximately $999,000 for 2013. Actuarial assumptions affecting 2012 include expected long-term rates of return on plan assets of 6.0 percent and 7.0 percent for Chesapeake’s pension plan and FPU’s pension plan, respectively, and discount rates of 3.50 percent and 3.75 percent for Chesapeake’s and FPU’s plans, respectively. The discount rate for each plan was determined by management considering high-quality corporate bond rates, such as Moody’s Aa bond index and the Citigroup yield curve, changes in those rates from the prior year and other pertinent factors, including the expected lives of the plans and the availability of the lump-sum payment option.

Actual changes in the fair value of plan assets and the differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent decrease in the discount rate could increase our annual pension and postretirement costs by approximately $11,000, and a 0.25 percent increase could decrease our annual pension and postretirement costs by approximately $13,000. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $124,000 and would not have an impact on the postretirement and supplemental executive retirement plans because these plans are not funded.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 39


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(d) Results of Operations

 

(in thousands except per share)

                 Increase                   Increase  

For the Years Ended December 31,

   2012      2011      (decrease)     2011      2010      (decrease)  

Business Segment:

                

Regulated Energy

   $ 46,999       $ 43,911       $ 3,088      $ 43,911       $ 43,267       $ 644   

Unregulated Energy

     8,355         9,619         (1,264     9,619         8,150         1,469   

Other

     1,281         175         1,106        175         513         (338
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Operating Income

     56,635         53,705         2,930        53,705         51,930         1,775   

Other Income

     271         906         (635     906         195         711   

Interest Charges

     8,747         9,000         (253     9,000         9,146         (146
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Pre-tax Income

     48,159         45,611         2,548        45,611         42,979         2,632   

Income Taxes

     19,296         17,989         1,307        17,989         16,923         1,066   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Net Income

   $ 28,863       $ 27,622       $ 1,241      $ 27,622       $ 26,056       $ 1,566   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Earnings Per Share of Common Stock

                

Basic

   $ 3.01       $ 2.89       $ 0.12      $ 2.89       $ 2.75       $ 0.14   

Diluted

   $ 2.99       $ 2.87       $ 0.12      $ 2.87       $ 2.73       $ 0.14   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

2012 compared to 2011

Our net income increased by approximately $1.2 million, or $0.12 per share (diluted) in 2012, compared to 2011. Key variances include:

 

(in thousands, except per share amounts)    Pre-tax
Income
    Net
Income
    Earnings
Per Share
 

2011 Reported Results

   $ 45,611      $ 27,622      $ 2.87   

Adjusting for unusual items:

      

Weather impact

     (3,627     (2,197     (0.23

Amortization of acquisition premium and costs

     (2,354     (1,426     (0.15

Severance and pension settlement charge in 2011

     1,299        787        0.08   

Florida natural gas reserve and sales tax reserve reversal in 2011

     (1,049     (636     (0.07

Amortization of deferred tax gain

     684        414        0.04   

Litigation settlement with a major propane supplier in 2011

     (575     (348     (0.04

Gain from the sale of Internet Protocol asset in 2011

     (553     (335     (0.03
  

 

 

   

 

 

   

 

 

 
     (6,175     (3,741     (0.40

Increased Margins:

      

Natural gas growth

     6,263        3,793        0.40   

Higher propane retail margins per gallon

     2,724        1,650        0.17   

BravePoint

     2,602        1,576        0.16   
  

 

 

   

 

 

   

 

 

 
     11,589        7,019        0.73   

Increased Other Operating Expenses:

      

BravePoint, primarily due to employee-related costs

     (1,523     (923     (0.10

Higher depreciation, asset removal and facilities costs

     (1,326     (803     (0.08

Acquisition-related costs and increased capacity for future growth

     (758     (459     (0.05
  

 

 

   

 

 

   

 

 

 
     (3,607     (2,185     (0.23

Net other changes

     741        148        0.02   
  

 

 

   

 

 

   

 

 

 

2012 Reported Results

   $ 48,159      $ 28,863      $ 2.99   
  

 

 

   

 

 

   

 

 

 

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 40


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Our results for 2012 reflected additional gross margin generated by: (a) the natural gas transmission and distribution operations as a result of major expansion initiatives in Sussex County, Delaware; Worcester and Cecil Counties, Maryland; and Nassau County, Florida; (b) additional customer growth; and (c) additional transmission services provided to an existing industrial customer. Higher retail propane margins per gallon, as a result of sustained retail prices and favorable supply costs, and increased product sales and consulting activities from BravePoint also generated additional gross margin. These increases in gross margin more than offset a reduction of $3.6 million in gross margin due to significantly warmer temperatures in 2012, particularly during the first three months of the year. Also included in the 2012 results is the amortization expense of $2.4 million related to the recovery of the FPU acquisition adjustment and merger-related costs, partially offset by an amortization credit of $684,000 associated with FPU’s pre-merger deferred income tax gain. Higher expenses associated with growth initiatives and capital investments to support growth and system integrity also offset the gross margin increases.

2011 compared to 2010

Our net income increased by approximately $1.6 million, or $0.14 per share (diluted) in 2011, compared to 2010. Key variances include:

 

(in thousands, except per share amounts)    Pre-tax
Income
    Net
Income
    Earnings
Per Share
 

2010 Reported Results

   $ 42,979      $ 26,056      $ 2.73   

Adjusting for unusual itiems:

      

Lower energy consumption, due primarily to weather

     (5,233     (3,168     (0.33

Florida regulatory reserve recorded in 2010 and reversed in 2011

     1,500        921        0.10   

Severance and pension settlement charge in 2011

     (1,284     (777     (0.08

Sales tax reserves recorded in 2010 and reversed in 2011

     959        589        0.06   

Absence of merger-related costs in 2011

     660        395        0.04   

Litigation settlement with a major propane supplier in 2011

     575        342        0.04   

Gain from the sale of Internet Protocol asset in 2011

     553        331        0.03   
  

 

 

   

 

 

   

 

 

 
     (2,270     (1,367     (0.14

Increased Margins:

      

New natural gas transportation services

     2,914        1,702        0.17   

Growth in natural gas distribution customers

     2,362        1,419        0.15   

Higher propane retail margins per gallon

     2,248        1,381        0.14   
  

 

 

   

 

 

   

 

 

 
     7,524        4,502        0.46   

Increased Other Operating Expenses:

      

Increased depreciation and asset removal costs from regulated assets

     (1,232     (732     (0.08

BravePoint’s decline in operating income due to a new product launch

     (858     (527     (0.05

Increased vehicle fuel costs

     (621     (376     (0.04

Additional legal costs as a result of an electric franchise dispute

     (537     (330     (0.03
  

 

 

   

 

 

   

 

 

 
     (3,248     (1,965     (0.20

Net other changes

     626        396        0.02   
  

 

 

   

 

 

   

 

 

 

2011 Reported Results

   $ 45,611      $ 27,622      $ 2.87   
  

 

 

   

 

 

   

 

 

 

Our results for 2011 reflected additional gross margin generated by: (a) new services initiated by the natural gas transmission operation; (b) customer growth in the natural gas distribution operations; and (c) higher retail propane margins per gallon, as a result of unusually low retail margins per gallon in 2010 due to high spot purchases to meet the high customer demands in the cold winter. These increases in gross margin more than offset a reduction of $5.2 million in gross margin as a result of lower customer energy consumption due primarily to significantly warmer temperatures in 2011, compared to 2010. During 2011, we recorded $1.3 million in non-recurring charges related to severance and pension settlements. Also included in the 2011 results are the impact of reversing the Florida regulatory reserve and sales tax reserve, both of which were recorded in 2010, and one-time gains related to proceeds from a litigation settlement with a major supplier and sale of a non-operating asset. BravePoint’s operating income declined by $858,000 in 2011, compared to 2010, as a result of the launch of ProfitZoomTM. We also incurred additional legal costs of $537,000 as a result of an electric franchise dispute.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 41


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The following section provides a more detailed analysis of our results by segment.

Regulated Energy

 

                   Increase                   Increase  

For the Years Ended December 31,

   2012      2011      (decrease)     2011      2010      (decrease)  
(in thousands)                                         

Revenue

   $ 246,208       $ 256,226         ($10,018   $ 256,226       $ 269,438         ($13,212

Cost of sales

     111,402         128,111         (16,709     128,111         145,207         (17,096
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Gross margin

     134,806         128,115         6,691        128,115         124,231         3,884   

Operations & maintenance

     61,113         59,816         1,297        59,816         57,464         2,352   

Depreciation & amortization

     18,653         16,512         2,141        16,512         14,680         1,832   

Other taxes

     8,041         7,876         165        7,876         8,820         (944
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Other operating expenses

     87,807         84,204         3,603        84,204         80,964         3,240   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Operating Income

   $ 46,999       $ 43,911       $ 3,088      $ 43,911       $ 43,267       $ 644   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Weather and Customer Analysis

                
                   Increase                   Increase  

For the Years Ended December 31,

   2012      2011      (decrease)     2011      2010      (decrease)  

Delmarva Peninsula

                

Actual HDD

     3,936         4,221         (285     4,221         4,831         (610

10-year average HDD

     4,491         4,499         (8     4,499         4,528         (29

Estimated gross margin per HDD

   $ 1,712       $ 2,064         ($352   $ 2,064       $ 1,995       $ 69   

Per residential customer added:

                

Estimated gross margin

   $ 375       $ 375       $ 0      $ 375       $ 375       $ 0   

Estimated other operating expenses

   $ 113       $ 111       $ 2      $ 111       $ 105       $ 6   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Florida

                

Actual HDD

     633         753         (120     753         1,501         (748

10-year average HDD

     915         920         (5     920         863         57   

Actual CDD

     2,871         2,858         13        2,858         2,859         (1

10-year average CDD

     2,756         2,718         38        2,718         2,695         23   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Average number of residential customers

                

Delmarva natural gas distribution

     49,639         48,680         959        48,680         47,638         1,042   

Florida natural gas distribution

     62,386         61,525         861        61,525         61,053         472   

Florida electric distribution

     23,670         23,598         72        23,598         23,589         9   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total

     135,695         133,803         1,892        133,803         132,280         1,523   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

2012 Compared to 2011

Operating income for our regulated energy segment for 2012 was $47.0 million, an increase of $3.1 million, or seven percent, compared to 2011. An increase in gross margin of $6.7 million was partially offset by an increase in other operating expenses of $3.6 million.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 42


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Gross Margin

Gross margin for our regulated energy segment increased by $6.7 million, or five percent, in 2012, compared to 2011. Items contributing to the year-over-year increase in gross margin are listed in the following table:

 

(in thousands)

      

Gross margin for the year ended December 31, 2011

   $ 128,115   
  

 

 

 

Factors contributing to the gross margin increase for the year ended December 31, 2012:

  

Major expansion initiatives

     3,475   

Other customer growth—natural gas distribution

     2,073   

Florida natural gas regulatory reserve

     (750

Eastern Shore rate case settlement

     737   

Other new services—natural gas transmission

     713   

Decreased customer consumption—weather and other

     (230

Other

     673   
  

 

 

 

Gross margin for the year ended December 31, 2012

   $ 134,806   
  

 

 

 

Major Expansion Initiatives

Major expansion initiatives in Sussex County, Delaware; Worcester and Cecil Counties, Maryland; and Nassau County, Florida generated $3.5 million in additional gross margin in 2012, compared to 2011. In Sussex County, Delaware, Eastern Shore initiated new transmission service and our Delmarva natural gas distribution operation initiated distribution service to two large industrial customers in Lewes, Delaware during the fourth quarter of 2011. These services generated $779,000 and $499,000, respectively, of additional gross margin in 2012. Eastern Shore also began new transmission service and our Delmarva natural gas distribution operation initiated distribution service to two industrial facilities of an existing customer in southeast Sussex County, Delaware generating $334,000 and $89,000, respectively, of additional gross margin during 2012. Eastern Shore also generated $90,000 in additional transmission gross margin as a result of the Worcester County, Maryland expansion, and Eastern Shore commenced additional transmission service in Worcester County, Maryland during the first quarter of 2013. The Cecil County, Maryland expansion commenced during the fourth quarter of 2012 and generated $147,000 of additional transmission gross margin. The Nassau County, Florida expansion generated $1.5 million in additional transmission gross margin for Peninsula Pipeline.

Other Customer Growth – Natural Gas Distribution

The Florida natural gas distribution operation generated $986,000 of additional gross margin due primarily to a three-percent growth in commercial and industrial customers.

The Delmarva natural gas distribution operation generated $1.1 million of additional gross margin in 2012, compared to 2011, due primarily to the addition of 12 new large commercial and industrial customers since the beginning of 2011 and two-percent growth in residential customers.

Florida Natural Gas Regulatory Reserve

In January 2012, the Florida PSC issued an order approving the recovery of $34.2 million as an acquisition adjustment and $2.2 million in merger-related costs in connection with the Company’s acquisition of FPU in 2009. In the order, the Florida PSC also determined that no refund should be made to customers as a result of the 2010 earnings of our Florida natural gas distribution operations. Pursuant to this order, in the fourth quarter of 2011, we reversed the $750,000 reserve, which was accrued in the third and fourth quarters of 2010 based on the contingent regulatory risks associated with the Florida natural gas earnings, merger benefits and recovery of the acquisition adjustment.

Eastern Shore Rate Case Settlement

Eastern Shore generated $737,000 of additional gross margin in 2012, compared to 2011, as a result of new rates that became effective July 2011.

Other New Services – Natural Gas Transmission

Eastern Shore generated additional gross margin of $713,000 in 2012, due primarily to a new transmission service agreement for an additional 9,514 Dts/d with an existing industrial customer for the period from November 2011 to October 2012.

Decreased Customer Consumption – Weather and Other

Customer consumption of natural gas and electricity decreased, primarily on the Delmarva Peninsula, during 2012, compared to 2011. Consumption of energy is normally highest during the first and fourth quarters due to colder temperatures. The first quarter of 2012 was the warmest first quarter in the past 10 years, both on the Delmarva Peninsula and in Florida. We estimate that significantly warmer weather in 2012, primarily during the first three months of 2012, resulted in a period-over-period decrease of approximately $926,000 in gross margin, most of which occurred during the first three months of the year. This decrease was partially offset by $696,000 in higher gross margins due primarily to other volume increases in Florida.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 43


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Other Operating Expenses

Other operating expenses for the regulated energy segment increased by $3.6 million for 2012 due largely to: (a) $2.4 million in increased amortization expense associated with the recovery of the FPU acquisition adjustment and merger-related costs, which was partially offset by an amortization credit of $684,000 associated with FPU’s pre-merger deferred income tax gain; (b) $1.3 million in higher depreciation expense, asset removal and facilities costs associated with capital investments; (c) $646,000 in increased costs associated with investing in growth; (d) $379,000 in increased payroll and benefits cost for the Delmarva natural gas distribution operation due to increased staffing to support expansions; (e) $325,000 in increased costs related to pipeline integrity requirements; (f) $305,000 in higher legal costs associated with an electric franchise dispute in Marianna, Florida; and (g) $254,000 in an increased accrual for general liability claim. These increases in expenses were partially offset by $1.2 million in reduced payroll and benefits, primarily in Florida, because of a workforce reduction in 2011, and one-time charges totaling $1.1 million in 2011 as a result of the voluntary workforce reduction in Florida and pension settlements.

2011 Compared to 2010

Operating income for our regulated energy segment increased by approximately $644,000, or one percent, in 2011, compared to 2010, which was generated from a gross margin increase of $3.9 million, offset by an other operating expense increase of $3.2 million.

Gross Margin

Gross margin for our regulated energy segment increased by $3.9 million, or three percent, in 2011, compared to 2010. Items contributing to the year-over-year increase in gross margin are listed in the following table:

 

(in thousands)

      

Gross margin for the year ended December 31, 2010

   $ 124,231   
  

 

 

 

Factors contributing to the gross margin increase for the year ended December 31, 2011:

  

Decreased customer consumption, due primarily to weather

     (3,753

New transportation services

     2,914   

Net customer growth in distribution services

     2,739   

Florida natural gas regulatory reserve

     1,500   

Change in rates

     409   

Other

     75   
  

 

 

 

Gross margin for the year ended December 31, 2011

   $ 128,115   
  

 

 

 

Decreased Customer Consumption, Due Primarily to Weather

Customer consumption of natural gas and electricity decreased, both on the Delmarva Peninsula and in Florida, during 2011, compared to 2010. The decline in consumption was due primarily to significantly warmer weather during the heating season, resulting in a year-over-year decrease of approximately $3.8 million in gross margin. In 2011, HDD decreased by 13 percent, or 610 HDD, on the Delmarva Peninsula and by 50 percent, or 748 HDD, in Florida, compared to 2010. Measured against normal HDD (10-year historical average) in 2011, the weather on the Delmarva Peninsula was six percent, or 278 HDD, warmer than normal, and the weather in Florida was 18 percent, or 167 HDD, warmer than normal. We estimate that this warmer-than-normal weather reduced gross margin of the regulated energy segment by approximately $2.1 million in 2011.

 

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New Transportation Services

In January 2011, Eastern Shore commenced new transportation service for 20,000 Dts/d of capacity associated with its eight-mile mainline extension to interconnect with TETLP’s pipeline system, which generated gross margin of $2.0 million in 2011.

Other additional transportation services that commenced in May 2010, November 2010 and November 2011, as a result of Eastern Shore’s system expansion projects, generated additional gross margin of $542,000 in 2011.

Eastern Shore entered into two additional transportation services agreements with an existing industrial customer, one for the period from May 2011 to April 2021 for an additional 3,405 Dts/d and the second for the period from November 2011 to October 2012 for an additional 9,514 Dts/d. These additional services generated additional gross margin of $243,000 and $168,000, respectively, in 2011.

Partially offsetting these gross margin increases was a gross margin decrease of $66,000 due to the expiration in April 2010 of two transportation service contracts.

Net Customer Growth in Distribution Services

The Delmarva natural gas distribution operation generated $1.6 million of additional gross margin due to net customer growth. Gross margin from commercial and industrial customers for the Delmarva natural gas distribution operation increased by $1.2 million in 2011, due primarily to the addition of 20 large commercial and industrial customers since June 2010. Two-percent growth in residential customers generated an additional $429,000 of gross margin for the Delmarva natural gas distribution operation.

The Florida natural gas distribution operations generated $771,000 of additional gross margin primarily as a result of a two-percent growth in commercial and industrial customers. In addition, 700 new customers, added as a result of our purchase of the operating assets of Indiantown Gas Company (“IGC”) in August 2010, generated $377,000 of additional gross margin during 2011 due to the inclusion of a full year of results.

Florida Natural Gas Regulatory Reserve

In January 2012, the Florida PSC issued an order, approving the recovery of $34.2 million as an acquisition adjustment and $2.2 million in merger-related costs in connection with our acquisition of FPU in 2009. In the order, the Florida PSC also determined that no refund should be made to customers as a result of the 2010 earnings of our Florida natural gas distribution operations. Pursuant to this order, in the fourth quarter of 2011, we reversed the $750,000 reserve, which was accrued in the third and fourth quarters of 2010 based on the contingent regulatory risks associated with the Florida natural gas earnings, merger benefits and recovery of the acquisition adjustment.

Change in Rates

On January 24, 2012, the FERC approved a rate case settlement for Eastern Shore. In 2011, we recorded $409,000 of additional gross margin as a result of implementing the new rates pursuant to the settlement.

Other Operating Expenses

Other operating expenses for the regulated energy segment increased by $3.2 million for 2011 due largely to the following factors: (a) $1.2 million in higher depreciation expense and asset removal costs associated with capital investments; (b) $1.1 million in non-recurring severance and pension settlement charges; (c) $537,000 in increased legal costs associated with the electric franchise dispute in Marianna, Florida; (d) $403,000 in additional expenses related to pipeline integrity projects for Eastern Shore to comply with increased pipeline regulatory requirements; (e) $375,000 in increased amortization expense related to the change in the recovery period of certain specific project costs; (f) $355,000 in higher vehicle fuel costs; and (g) $896,000 in lower taxes other than income taxes, due to an accrual in 2010 for potential additional sales taxes and gross receipts taxes and the reversal of a portion of the accrual in 2011 as a result of the collection and remittance of those taxes.

 

Chesapeake Utilities Corporation 2012 Form 10-K     Page 45


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Unregulated Energy

 

                   Increase                   Increase  

For the Years Ended December 31,

   2012      2011      (decrease)     2011      2010      (decrease)  
(in thousands)                                         

Revenue

   $ 133,049       $ 149,586         ($16,537   $ 149,586       $ 146,793       $ 2,793   

Cost of sales

     97,137         112,415         (15,278     112,415         110,679         1,736   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Gross margin

     35,912         37,171         (1,259     37,171         36,114         1,057   

Operations & maintenance

     22,804         22,863         (59     22,863         22,751         112   

Depreciation & amortization

     3,420         3,229         191        3,229         3,569         (340

Other taxes

     1,333         1,460         (127     1,460         1,644         (184
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Other operating expenses

     27,557         27,552         5        27,552         27,964         (412
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Operating Income

   $ 8,355       $ 9,619         ($1,264   $ 9,619       $ 8,150       $ 1,469   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Weather Analysis — Delmarva

                
                   Increase                   Increase  

For the Years Ended December 31,

   2012      2011      (decrease)     2011      2010      (decrease)  

Actual HDD

     3,936         4,221         (285     4,221         4,831         (610

10-year average HDD

     4,491         4,499         (8     4,499         4,528         (29

Estimated gross margin per HDD

   $ 2,882       $ 2,869       $ 13      $ 2,869       $ 2,611       $ 258   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

2012 Compared to 2011

Operating income for our unregulated energy segment for 2012 was $8.4 million, a decrease of $1.3 million, or 13 percent, compared to 2011, due primarily to a decrease in gross margin of $1.3 million. Other operating expenses for 2012 remained unchanged from 2011.

Gross Margin

Gross margin for our unregulated energy segment decreased by $1.3 million, or three percent, in 2012, compared to 2011. Items contributing to the year-over-year decrease in gross margin are listed in the following table:

 

(in thousands)

      

Gross margin for the year ended December 31, 2011

   $ 37,171   
  

 

 

 

Factors contributing to the gross margin decrease for the year ended December 31, 2012:

  

Decreased customer consumption—weather and other

     (3,259

Increase in retail margins per gallon

     2,724   

Gain from litigation settlement—recorded in 2011

     (575

Other

     (149
  

 

 

 

Gross margin for the year ended December 31, 2012

   $ 35,912   
  

 

 

 

Decreased Customer Consumption – Weather and Other

Significantly warmer weather, particularly during the first three months of 2012 when propane demand for heating is typically at its highest, resulted in decreased gross margin of $2.7 million in 2012, compared to 2011. Additionally, both our Delmarva and Florida propane distribution operations experienced a decline in sales volume beyond the estimated weather impact in 2012, compared to 2011, due to the timing of deliveries to bulk-delivery customers, conservation and other factors. This additional decline in sales volume was partially offset by additional gross margin generated from 1,180 customers acquired in late 2011 and early 2012, following the purchase of the operating assets of several small propane distribution companies in Florida. These factors resulted in a net decrease in propane gross margin of $515,000 in 2012, compared to 2011.

 

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Increase in Retail Margins per Gallon

Higher retail margins per gallon in the Delmarva and Florida propane distribution operation generated $631,000 and $2.1 million, respectively, of additional gross margin in 2012, compared to 2011. Sustained retail pricing in response to local market conditions and lower average propane inventory cost contributed to the higher retail margins per gallon.

Gain from Litigation Settlement – Recorded in 2011

A non-recurring gain of $575,000 was recorded in 2011 related to our share of proceeds received from an antitrust litigation settlement with a major propane supplier and is reflected as a period-over-period decrease in gross margin.

Other

PESCO’s gross margin decreased by $310,000 in 2012, compared to 2011. PESCO’s gross margin in 2011 benefited from unusually large favorable imbalance resolutions with third-party intrastate pipelines, with which PESCO contracts for supply. Imbalance resolutions are not predictable and, therefore, are not included in our long-term financial plans or forecasts. Lower gross margin from imbalance resolutions was partially offset by additional gross margin generated by new customers and contracts.

Partially offsetting the decrease in PESCO’s gross margin was the increase in gross margin of Xeron, which increased by $225,000 in 2012, compared to 2011, as a result of higher margins from its trading activity. Xeron executed trades with higher margins in 2012 as the market presented opportunities from fluctuations in wholesale propane prices.

Other Operating Expenses

Other operating expenses for the unregulated energy segment were $27.6 million for both 2012 and 2011.

2011 Compared to 2010

Operating income for our unregulated energy segment increased by approximately $1.5 million, or 18 percent, in 2011 compared to 2010, which was attributable to an increase in gross margin of $1.1 million and a decrease in other operating expenses of $412,000.

Gross Margin

Gross margin for our unregulated energy segment increased by $1.1 million, or three percent in 2011 compared to 2010. Items contributing to the year-over-year decrease in gross margin are listed in the following table:

 

(in thousands)

      

Gross margin for the year ended December 31, 2010

   $ 36,114   
  

 

 

 

Factors contributing to the gross margin increase for the year ended December 31, 2011:

  

Volume decrease—weather and other

     (2,759

Increase in retail margin per gallon

     2,248   

Gain from litigation settlement

     575   

Propane wholesale marketing

     431   

Natural gas marketing

     362   

Miscellaneous fees and other

     200   
  

 

 

 

Gross margin for the year ended December 31, 2011

   $ 37,171   
  

 

 

 

Volume Decrease – Weather and Other

A decline in customer consumption, due primarily to a decrease in HDD, resulted in decreased gross margin of $1.5 million in 2011, compared to 2010, for the Delmarva propane distribution operation. A decrease in propane deliveries to bulk customers, due to lower non-weather-related consumption and the timing of deliveries, also decreased gross margin by $1.3 million.

 

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Increase in Retail Margin per Gallon

The propane distribution operations generated additional gross margin of $2.2 million due to higher margins per gallon for 2011, compared to 2010. Propane retail margins per gallon on the Delmarva Peninsula during 2011 returned to more normal levels, compared to retail margins per gallon during 2010. The lower margins in 2010 were caused by colder temperatures and higher cost spot purchases during the first quarter when customer demand was the highest. Also contributing to the gross margin increase were higher margins per gallon in Florida as the propane distribution operation continued to adjust its retail pricing in response to market conditions.

Gain from Litigation Settlement

We recorded a one-time gain of $575,000 in the first quarter of 2011 related to our share of proceeds received from an antitrust litigation settlement with a major propane supplier.

Propane Wholesale Marketing

Xeron generated $431,000 of additional gross margin in 2011, compared to 2010, due primarily to a 22-percent increase in trading activity.

Natural Gas Marketing

PESCO generated higher gross margin of $362,000 in 2011, compared to 2010. Favorable imbalance resolutions with third-party pipelines, with which PESCO contracts for natural gas supply, generated this increase. Such imbalance resolutions are not predictable and therefore, are not included in our long-term financial plans or forecasts.

Other Operating Expenses

Other operating expenses for the unregulated energy segment decreased by $412,000 in 2011, compared to 2010. In 2010, we expensed $370,000 related to the settlement of a propane class action litigation and recorded $351,000 in amortization expense associated with the favorable propane supply contracts acquired in the merger with FPU, which was recorded as an intangible asset. The absence of these expenses in 2011 resulted in a decrease in other operating expenses in 2011, compared to 2010. These decreases were partially offset by a $265,000 increase in vehicle fuel costs in 2011.

Other

 

                   Increase                    Increase  

For the Years Ended December 31,

   2012      2011      (decrease)      2011      2010      (decrease)  
(in thousands)                                          

Revenue

   $ 18,357       $ 13,829       $ 4,528       $ 13,829       $ 13,142       $ 687   

Cost of sales

     8,872         7,051         1,821         7,051         6,316         735   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Gross margin

     9,485         6,778         2,707         6,778         6,826         (48

Operations & maintenance

     6,953         5,515         1,438         5,515         5,426         89   

Depreciation & amortization

     438         413         25         413         289         124   

Other taxes

     814         676         138         676         600         76   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Other operating expenses

     8,205         6,604         1,601         6,604         6,315         289   

Operating Income — Other

     1,280         174         1,106         174         511         (337

Operating Income — Eliminations

     1         1         —            1         2         (1
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operating Income

   $ 1,281       $ 175       $ 1,106       $ 175       $ 513         ($338
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2012 Compared to 2011

Operating income for our “Other” segment for 2012 was $1.3 million, an increase of $1.1 million, compared to 2011. The increase was attributable to higher operating income from BravePoint.

BravePoint, which reported operating income of $828,000 in 2012, compared to an operating loss of $270,000 for 2011, generated increased gross margin of $2.6 million, $852,000 of which represents increased margin from ProfitZoom™ and Application Evolution™ sales and related services. The remaining increase in gross margin was generated from higher consulting revenues and other product sales. This increase in gross margin was partially offset by $1.5 million of increased other operating expenses as a result of resources added to support these services.

 

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2011 Compared to 2010

Operating income for our “Other” segment for 2011 was $175,000, representing a decrease of $338,000 from operating income of $513,000 for 2010. The decrease was attributable to lower operating income of $1.0 million from BravePoint, offset partially by the absence in 2011 of $660,000 in merger-related costs expensed in 2010.

BravePoint reported an operating loss of $270,000 in 2011, compared to operating income of $759,000 in 2010. During 2011, BravePoint incurred $1.1 million in additional costs associated with the product development and release of ProfitZoomTM. BravePoint recorded $572,000 in revenue in 2011 from these new contracts.

Other Income

Other income for 2012, 2011 and 2010 was $271,000, $906,000 and $195,000, respectively. Included in other income for 2011 was a $553,000 gain from the sale of a non-operating Internet Protocol address asset. The remaining balance in other income includes non-operating investment income, interest income, late fees charged to customers and gains or losses from the sale of assets.

Interest Expense

2012 Compared to 2011

Total interest expense for 2012 decreased by approximately $253,000, or three percent, compared to 2011. The decrease in interest expense is attributable primarily to decreases of $699,000 in other long-term interest expense due to scheduled repayments and $337,000 in interest on deposits from FPU’s customers due to a lower interest rate on those deposits. Additionally contributing to the decrease, is a reduction of $41,000 in short-term interest expense due to slightly lower borrowings and rates in 2012, compared to 2011. Offsetting the decrease in interest expense was additional interest expense of $824,000 related to the $29 million long-term debt issuance of 5.68 percent unsecured senior notes on June 23, 2011. We used the proceeds from these notes to repay a portion of Chesapeake’s short-term loan credit facilities, which had been used to redeem two series of FPU first mortgage bonds.

2011 Compared to 2010

Total interest expense for 2011 decreased by $146,000, or two percent, compared to 2010. The decrease in interest expense is attributable primarily to a decrease of $651,000 in long-term interest expense as scheduled repayments decreased the outstanding principal balances. Offsetting this decrease was additional interest expense of $505,000 related to the $29 million long-term debt issuance of 5.68 percent unsecured senior notes on June 23, 2011. We used the proceeds to permanently finance the redemption of the 6.85 percent and 4.90 percent series of FPU first mortgage bonds. These redemptions occurred in January 2010 and were previously financed by Chesapeake’s short-term loan facilities.

Income Taxes

2012 Compared to 2011

Income tax expense was $19.3 million in 2012, compared to $18.0 million in 2011. Our effective tax rate was 40.1 percent in 2012, compared to 39.4 percent in 2011. The increase in our effective tax rate in 2012 is due primarily to a $300,000 tax contingency accrual associated with a state tax audit recorded during 2012.

2011 Compared to 2010

Income tax expense was $18.0 million in 2011, compared to $16.9 million in 2010. Our effective income tax rate for 2011 and 2010 remained unchanged at 39.4 percent.

 

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(e) Liquidity and Capital Resources

Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to finance capital expenditures.

Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered by our natural gas, electric, and propane distribution operations to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

Capital expenditures, which are our investments in new or acquired plant and equipment, are our largest capital requirements. Our capital expenditures during 2012, 2011 and 2010 were $78.2 million, $44.4 million and $47.0 million, respectively. We experienced a significant increase in our capital expenditures in 2012, compared to 2011 and 2010, as a result of continued expansions of our natural gas distribution and transmission systems on the Delmarva Peninsula and in Florida as well as a natural gas infrastructure replacement program in Florida, electric infrastructure improvements in Florida to increase the distribution system reliability, and various customer billing system and other initiatives.

We have budgeted $112.3 million for capital expenditures during 2013. The following table shows the 2013 capital expenditure budget by segment:

 

(dollars in thousands)  

Regulated Energy:

  

Natural gas distribution

   $ 66,900   

Natural gas transmission

     28,609   

Electric distribution

     5,131   
  

 

 

 

Total Regulated Energy

     100,640   

Unregulated Energy:

  

Propane distribution

     3,837   

Other unregulated energy

     1,400   
  

 

 

 

Total Unregulated Energy

     5,237   

Other

  

Advanced information services

     473   

Other

     5,985   
  

 

 

 

Total Other

     6,458   
  

 

 

 

Total 2013 capital expenditures

   $ 112,335   
  

 

 

 

We expect to fund the 2013 capital expenditures program from short-term borrowings, cash provided by operating activities, and other sources. The capital expenditures program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.

In addition, we recently entered into an agreement with ESG to purchase its propane distribution assets that serve approximately 11,000 residential and commercial customers in Worcester County, Maryland, primarily through underground propane gas distribution systems. The purchase price is approximately $16.5 million, which is subject to certain adjustments as specified in the agreement. We expect to finance the purchase of these assets using unsecured short-term debt. The transaction is expected to be completed in 2013.

 

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Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors. The following presents our capitalization, excluding and including short-term borrowings, as of December 31, 2012 and 2011:

 

     December 31,     December 31,  
     2012     2011  
(in thousands)                           

Long-term debt, net of current maturities

   $ 101,907         28   $ 110,285         31

Stockholders’ equity

     256,598         72     240,780         69
  

 

 

    

 

 

   

 

 

    

 

 

 

Total capitalization, excluding short-term debt

   $ 358,505         100   $ 351,065         100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

     December 31,     December 31,  
     2012     2011  
(in thousands)                           

Short-term debt

   $ 61,199         14   $ 34,707         9

Long-term debt, including current maturities

     110,103         26     118,481         30

Stockholders’ equity

     256,598         60     240,780         61
  

 

 

    

 

 

   

 

 

    

 

 

 

Total capitalization, including short-term debt

   $ 427,900         100   $ 393,968         100
  

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2012, we did not have any restrictions on our cash balances. Both Chesapeake’s senior notes and FPU’s first mortgage bonds contain a restriction that limits the payment of dividends or other restricted payments in excess of certain pre-determined thresholds. As of December 31, 2012, $82.3 million of Chesapeake’s cumulative consolidated net income and $47.5 million of FPU’s cumulative net income were free of such restrictions.

 

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Table of Contents

Short-term Borrowings

Our outstanding short-term borrowings at December 31, 2012 and 2011 were $61.2 million and $34.7 million, respectively, at the weighted average interest rates of 1.48 percent and 1.53 percent, respectively.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of December 31, 2012, we had four unsecured bank lines of credit with two financial institutions for a total of $100.0 million. Two of these unsecured bank lines, totaling $60.0 million, are available under committed lines of credit. None of these unsecured bank lines of credit requires compensating balances. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. We are currently authorized by our Board of Directors to borrow up to $100.0 million of short-term debt, as required, from these unsecured bank lines of credit.

In addition to the four unsecured bank lines of credit, we entered into a new, unsecured short-term credit facility for $40 million with an existing lender on June 22, 2012. Short-term borrowings under this new facility bear interest at LIBOR plus 80 basis points or, at our discretion, the lender’s base rate plus 80 basis points. This facility, which is structured in the form of a revolving credit note, matures on October 31, 2013.

Our outstanding borrowings under these unsecured bank lines of credit at December 31, 2012 and 2011 were $56.4 million and $30.5 million, respectively. During 2012, 2011 and 2010, the average borrowings from these unsecured bank lines of credit were $23.4 million, $11.0 million and $10.5 million, respectively, at weighted average interest rates of 1.79 percent, 2.35 percent and 2.40 percent, respectively. The maximum month-end borrowings from these unsecured bank lines of credit during 2012, 2011 and 2010 were $56.4 million, $35.4 million and $64.0 million, respectively, which occurred during the fall and winter months when our working capital requirements were at the highest level. Also included in our outstanding short-term borrowings at December 31, 2012 and 2011 were $4.8 million and $4.2 million, respectively, in book overdrafts, which if presented would be funded through the bank lines of credit.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, 2012, 2011 and 2010:

 

For the Years Ended December 31,

   2012     2011     2010  
(in thousands)                   

Net cash provided by (used in):

      

Operating activities

   $ 65,872      $ 71,121      $ 61,118   

Investing activities

     (69,829   &