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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, 2010
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 o. No þ.
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 o. No þ.
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 þ. No o.
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 o. No o.
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. þ
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 o   Accelerated filer þ   Non-accelerated filer o   Smaller Reporting Company o
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o. No þ.
The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2010, 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 $297.6 million.
As of February 28, 2011, 9,529,333 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2011 Annual Meeting of Stockholders are incorporated by reference in Part II and Part III.
 
 

 

 


 

Chesapeake Utilities Corporation
Form 10-K
YEAR ENDED DECEMBER 31, 2010
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 Exhibit 4.9
 Exhibit 10.6
 Exhibit 10.8
 Exhibit 10.13
 Exhibit 10.28
 Exhibit 10.30
 Exhibit 10.41
 Exhibit 10.43
 Exhibit 12
 Exhibit 14.1
 Exhibit 14.2
 Exhibit 21
 Exhibit 23.1
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 

 


Table of Contents

GLOSSARY OF KEY TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
Subsidiaries of Chesapeake Utilities Corporation
     
BravePoint
  BravePoint®, Inc., a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake
Chesapeake
  The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
Company
  The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
ESNG
  Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake
FPU
  Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake, effective October 28, 2009
PESCO
  Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake
PIPECO
  Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake
Sharp
  Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake’s and Sharp’s subsidiary, Sharpgas, Inc.
Xeron
  Xeron, Inc., a wholly-owned subsidiary of Chesapeake
Regulatory Agencies
     
Delaware PSC
  Delaware Public Service Commission
DOT
  United States Department of Transportation
EPA
  United States Environmental Protection Agency
FASB
  Financial Accounting Standards Board
FERC
  Federal Energy Regulatory Commission
FDEP
  Florida Department of Environmental Protection
Florida PSC
  Florida Public Service Commission
IASB
  International Accounting Standards Board
IRS
  Internal Revenue Service
Maryland PSC
  Maryland Public Service Commission
MDE
  Maryland Department of the Environment
PSC
  Public Service Commission
SEC
  Securities and Exchange Commission
Accounting Standards Related
     
ASC
  FASB Accounting Standards Codification TM
ASU
  FASB Accounting Standards Update
GAAP
  Generally Accepted Accounting Principles
IFRS
  International Financial Reporting Standards
FASB
  Financial Accounting Standards Board

 

 


Table of Contents

Other
     
AS/SVE
  Air Sparging and Soil/Vapor Extraction
BS/SVE
  Bio-Sparging and Soil/Vapor Extraction
CDD
  Cooling Degree-Days
Columbia
  Columbia Gas Transmission, LLC
DSCP
  Directors Stock Compensation Plan
Dts
  Dekatherms
Dts/d
  Dekatherms per Day
FCG
  Florida City Gas
FGT
  Florida Gas Transmission Company
FRP
  Fuel Retention Percentage
GSR
  Gas Sales Service Rates
Gulf
  Columbia Gulf Transmission Company
Gulf Power
  Gulf Power Company
Gulfstream
  Gulfstream Natural Gas System, LLC
HDD
  Heating Degree-Days
IGC
  Indiantown Gas Company
Mcf
  Thousand Cubic Feet
MGP
  Manufactured Gas Plant
MWH
  Megawatt Hour
NYSE
  New York Stock Exchange
PIP
  Performance Incentive Plan
RAP
  Remedial Action Plan
S&P 500 Index
  Standard & Poor’s 500 Index
Sanford Group
  FPU and Other Responsible Parties involved with the Sanford Environmental Site
TETLP
  Texas Eastern Transmission, LP
Transco
  Transcontinental Gas Pipe Line Company, LLC

 

 


Table of Contents

Part I
References in this document to “Chesapeake,” “the Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation 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 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. You 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;
   
industrial, commercial and residential growth or contraction in our service territories;
   
the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and ice storms;
   
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, 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;
   
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 market prices of equity securities and resultant cash funding requirements for our defined benefit pension plans;
   
the creditworthiness of counterparties with which we are engaged in transactions;
   
growth in opportunities for our business units;
   
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 manage and maintain key customer relationships;
   
the ability to maintain key supply sources;

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 1


Table of Contents

   
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;
   
changes in technology affecting our advanced information services business; and
   
operational and litigation risks that may not be covered by insurance.
Item 1. Business.
(a)  
Overview
 
   
We are a diversified utility company engaged in various energy and other businesses. Chesapeake is a Delaware corporation that was formed in 1947. 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. We operate regulated energy businesses through our natural gas distribution divisions in Delaware, Maryland and Florida, natural gas and electric distribution operations in Florida through FPU, and natural gas transmission operations on the Delmarva Peninsula and Florida through our subsidiaries, Eastern Shore Natural Gas Company (“ESNG”) and Peninsula Pipeline Company, Inc. (“PIPECO”), respectively. Our unregulated businesses include our natural gas marketing operation through Peninsula Energy Services Company, Inc. (“PESCO”); propane distribution operations through Sharp Energy, Inc. and its subsidiary Sharpgas, Inc. (collectively “Sharp”) and FPU’s propane distribution subsidiary, Flo-Gas Corporation; and our propane wholesale marketing operation through Xeron, Inc. (“Xeron”). We also have an advanced information services subsidiary, BravePoint®, Inc. (“BravePoint”).
(b)  
Operating Segments
 
   
We are composed of three operating segments:
   
Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the Public Service Commission (“PSC”) having jurisdiction in each operating territory or by the Federal Energy Regulatory Commission (“FERC”) in the case of ESNG.
   
Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale 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 2010 and net property, plant and equipment as of December 31, 2010:
                                 
                    Net Property, Plant  
(in thousands)   Operating Income     & Equipment  
Regulated Energy
  $ 43,509       84 %   $ 414,622       90 %
Unregulated Energy
    7,908       15 %     35,658       8 %
Other
    513       1 %     12,477       2 %
 
                       
Total
  $ 51,930       100 %   $ 462,757       100 %
 
                       
Additional financial information by business segment is included in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note C, Segment Information.”

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 2


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(i)  
Regulated Energy
 
   
Our regulated energy segment provides natural gas distribution services in Delaware, Maryland and Florida, electric distribution services in Florida and natural gas transmission services in Delaware, Maryland, Pennsylvania and Florida.
 
   
Natural Gas Distribution
 
   
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. With 99 percent of the natural gas consumed in the United States coming from North America, supplies of natural gas are abundant. 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.
 
   
Our Delaware and Maryland natural gas distribution divisions serve 52,686 residential and commercial customers and 177 industrial customers in central and southern Delaware and Maryland’s Eastern Shore. For the year ended December 31, 2010, operating revenues and deliveries by customer class for our Delaware and Maryland distribution divisions were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Residential
  $ 46,041       57 %     2,881,073       35 %
Commercial
    27,896       34 %     2,145,143       26 %
Industrial
    3,766       5 %     3,020,907       36 %
 
                       
Subtotal
    77,703       96 %     8,047,123       97 %
Interruptible
    655       1 %     232,653       3 %
Other (1)
    2,507       3 %            
 
                       
Total
  $ 80,865       100 %     8,279,776       100 %
 
                       
(1)  
Operating revenues from “other” include unbilled revenue, rental of gas properties, and other miscellaneous charges.
Our Florida natural gas distribution operations consist of Chesapeake’s Florida division and FPU’s natural gas operation, which was acquired in the merger with FPU in October 2009. In August 2010, FPU added a new division through the purchase of the natural gas operating assets of Indiantown Gas Company (“IGC”). On a combined basis, our Florida natural gas distribution operations serve 61,053 residential customers and 6,314 commercial and industrial customers in 20 counties in Florida. For the year ended December 31, 2010, operating revenues and deliveries by customer class for our Florida natural gas distribution operations were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcf’s)  
Residential
  $ 27,742       35 %     1,716,934       8 %
Commercial
    39,006       48 %     4,451,414       20 %
Industrial
    13,043       16 %     15,582,234       72 %
Other (1)
    607       1 %     12,723        
 
                       
Total
  $ 80,398       100 %     21,763,305       100 %
 
                       
(1)  
Operating revenues from “other” include unbilled revenue, conservation revenue, fees for billing services provided to third parties and other miscellaneous charges.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 3


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Electric Distribution
Our Florida electric distribution operation, which was acquired in the FPU merger, distributes electricity to 30,966 customers in four counties in northeast and northwest Florida. For the year ended December 31, 2010, operating revenues and deliveries by customer class for the FPU electric distribution operation were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (MWHs)  
Residential
  $ 51,498       55 %     347,040       47 %
Commercial
    45,332       48 %     332,322       45 %
Industrial
    7,705       8 %     66,580       9 %
 
                       
Subtotal
    104,535       111 %     745,942       101 %
Other (1)
    (10,452 )     (11 %)     (6,286 )     (1 %)
 
                       
Total
  $ 94,083       100 %     739,656       100 %
 
                       
(1)  
Operating revenues from “other” include unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges and adjustments for pass-through taxes.
Natural Gas Transmission
ESNG operates a 396-mile interstate pipeline system that transports natural gas from various points in Pennsylvania to Chesapeake’s 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. ESNG also provides swing transportation service and contract storage services. For the year ended December 31, 2010, operating revenues and deliveries by customer class for ESNG were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Local distribution companies
  $ 20,441       76 %     10,848,108       62 %
Industrial
    4,864       18 %     4,794,442       27 %
Commercial
    1,571       6 %     1,962,890       11 %
Other (1)
    41       0 %            
 
                       
Subtotal
    26,917       100 %     17,605,440       100 %
Less: affiliated local distribution companies
    (12,903 )     (48 %)     (5,853,083 )     (33 %)
 
                       
Total non-affiliated
  $ 14,014       52 %     11,752,357       67 %
 
                       
(1)  
Operating revenues from “other” sources are from rental of gas properties.
PIPECO currently provides natural gas transportation services to a customer for a period of 20 years beginning in January 2009 at a fixed monthly charge, through an eight-mile pipeline located in Suwanee County, Florida, which PIPECO owns. For the year ended December 31, 2010, PIPECO had $264,000 in operating revenues under the contract.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 4


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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- Delaware and Maryland
Our Delaware and Maryland natural gas distribution divisions have both firm and interruptible transportation service contracts with five interstate “open access” pipeline companies, including the ESNG pipeline. These divisions are directly interconnected with the ESNG pipeline, and have contracts with interstate pipelines upstream of ESNG, 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 ESNG pipeline. The Gulf pipeline is directly interconnected with the Columbia pipeline and indirectly interconnected with the ESNG pipeline. None of the upstream pipelines is owned or operated by an affiliate of the Company.
On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP in conjunction with TETLP’s new expansion project. Upon satisfaction of certain conditions provided in the Precedent Agreement, the Delaware and Maryland divisions will execute two firm transportation service contracts, one for our Delaware division for 28,986 Mcfs per day and one for our Maryland division for 9,662 Mcfs per day, to be effective on the service commencement date of the project, which is currently projected to occur in November 2012. The new firm transportation service contracts between our Delaware and Maryland divisions and TETLP will provide us with an additional direct interconnection with ESNG’s transmission system and access to new sources of natural gas supplies from other natural gas production regions, including the Appalachian production region, thereby providing increased reliability and diversity of supply. They will also provide our Delaware and Maryland divisions with additional upstream transportation capacity to meet current customer demands and to plan for sustainable growth. In December 2010, ESNG completed its mainline extension to interconnect with the TETLP pipeline. Until TETLP’s expansion project is completed, our Delaware and Maryland divisions expect to utilize currently available capacity on a portion of TETLP’s existing pipeline. For the 2010 and 2011 winter season, our Delaware and Maryland divisions have contracted for 14,493 Mcfs per day and 4,831 Mcfs per day, respectively, from TETLP.
The Delaware and Maryland divisions use their firm transportation supply resources to meet a significant percentage of their projected demand requirements and they purchase natural gas supplies on the spot market from various suppliers as needed to match firm supply and demand. This gas is transported by the upstream pipelines and delivered to their interconnections with ESNG. These divisions also have the capability to use propane-air peak-shaving to supplement or displace spot market purchases.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 5


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The following table shows the firm transportation and storage capacity that the Delaware and Maryland divisions currently have under contract with ESNG and pipelines upstream of the ESNG pipeline, including the respective contract expiration dates.
Delaware
                     
    Firm transportation     Firm storage capacity      
    capacity maximum     maximum peak-day      
    peak-day daily     daily withdrawal      
Pipeline   deliverability (Mcfs)     (Mcfs)     Expiration
Transco
    20,699       6,190     Various dates between 2012 and 2028
Columbia
    17,836       7,946     Various dates between 2011 and 2020
Gulf
    850           Expires in 2014
TETLP
    14,493           Expires in 2012
ESNG
    64,602       4,006     Various dates between 2011 and 2027
Maryland
                     
    Firm transportation     Firm storage capacity      
    capacity maximum     maximum peak-day      
    peak-day daily     daily withdrawal      
Pipeline   deliverability (Mcfs)     (Mcfs)     Expiration
Transco
    5,921       2,909     Various dates between 2012 and 2013
Columbia
    6,473       3,539     Various dates between 2011 and 2018
Gulf
    570           Expires in 2014
TETLP
    4,831           Expires in 2012
ESNG
    21,380       2,228     Various dates between 2011 and 2027
The Delaware and Maryland divisions currently have contracts with several suppliers for the purchase of firm natural gas supply in the amount of their capacities on the Transco and Columbia pipelines.
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 Public Service Commission (“Florida PSC”), all of the capacity under these agreements has been released to various third-parties, including PESCO. 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.
Contracts by Chesapeake’s Florida natural gas distribution division with FGT include: (a) a contract, which expires on July 31, 2012, for daily firm transportation capacity of 17,175 Mcfs for the months of November through April, capacity of 14,695 Mcfs for the months of May through September, and 16,143 Mcfs for October; and (b) a contract for daily firm transportation capacity of 974 Mcfs daily, which expires in 2015. Chesapeake’s contract with Gulfstream is for daily firm transportation capacity of 9,737 Mcfs and expires in 2022.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 6


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FPU has the following firm transportation contracts with FGT:
(a) two contracts expiring in July 2020 for daily firm transportation capacity of:
         
    Daily Firm  
    Transportation Capacity  
    (in Mcfs)  
January — March
    28,647  
April
    24,156  
May — September
    9,681  
October
    10,210  
November — December
    28,647  
(b) one contract expiring in February 2015 for daily firm transportation capacity of:
         
    Daily Firm  
    Transportation Capacity  
    (in Mcfs)  
January — April
    10,286  
May — October
    4,360  
November — December
    10,286  
(c) one contract for daily firm transportation capacity of 1,774 Mcfs with various partial expiration dates between 2016 and 2023.
FPU also has a firm transportation contract with Florida City Gas (“FCG”), expiring in 2013, which provides daily firm transportation capacity of 292 Mcfs on its Pioneer Pipeline, and a firm transportation contract with IGC, expiring in 2016, which provides daily firm transportation capacity of 487 Mcfs on its distribution system.
FPU uses gas marketers and producers to procure all of its gas supplies for its natural gas distribution operations. FPU also uses TECO Peoples Gas to provide wholesale gas sales service in areas distant from its interconnections with FGT.
Natural Gas Transmission
ESNG has three contracts with Transco for a total of 7,045 Mcfs of firm peak day storage entitlements and total storage capacity of 278,264 Mcfs, each of which expires in 2013. ESNG has retained these firm storage services in order to provide swing transportation service and firm storage service to those customers that have requested such services.
Electric Distribution
Our electric distribution operation through FPU purchases all of its wholesale electricity from two suppliers: Gulf Power Company (“Gulf Power”) and JEA (formerly known as Jacksonville Electric Authority). Both of these contracts are all requirement contracts and they expire in December 2019 and December 2017, respectively. The JEA contract provides generation, transmission and distribution service to northeast Florida. The Gulf Power contract provides generation, transmission and distribution service to northwest Florida.

 

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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 and Florida PSCs with respect to various aspects of their business, including rates for sales and transportation to all customers in each respective 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 regulatory authority having jurisdiction.
ESNG is subject to regulation as an interstate pipeline by the FERC, which regulates the terms and conditions of service and the rates ESNG can charge for its transportation and storage services. PIPECO 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:
                 
    Regulatory   Effective Date of   Allowed  
Regulated Business   Jurisdiction   the Currrent Rates   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 — Electric
  Florida PSC   5/22/2008     11.00% (1)  
ESNG
  FERC   9/1/2007     13.60% (2)  
(1)  
Allowed return on equity
 
(2)  
Allowed overall pre-tax, pre-interest rate of return
 
(3)  
Effective date of the Order approving settlement agreement, which adjusted rates originally approved on June 4, 2009.
PIPECO, which is regulated by the Florida PSC, currently provides service to one customer at a negotiated rate.
On December 30, 2010, ESNG submitted a base rate filing to the FERC. See discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Rate Filings and Other Regulatory Activities.”
Management monitors the achieved rates of return of each of our regulated energy operations in order to ensure timely filing of rate cases.

 

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Regulatory Proceedings
See discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Rate Filings and Other Regulatory Activities.”
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 sold and delivered. Specifically, customer demand substantially increases during the winter months, when natural gas is used for heating. Accordingly, the 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 use of natural gas, while sustained colder-than-normal temperatures will tend to increase 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 below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one heating 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 regardless of weather conditions, we received approval from the Maryland Public Service Commission (“Maryland PSC”) on September 26, 2006 to implement 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 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. Since March of 2007, the Delaware Public Service Commission (“Delaware PSC”) has been investigating whether to implement a revenue decoupling mechanism for the natural gas distribution utilities. Recently, the Delaware PSC decided in response to a decoupling request by another Delaware distribution utility that it would need a further review of the implementation plan, including more customer education about decoupling and the greater awareness of energy efficiency programs, prior to approving the request. Our Delaware natural gas distribution operation is currently evaluating the feasibility of decoupling. In light of the Delaware PSC’s recent actions, it is uncertain as to when our Delaware natural gas distribution operation will file a request for decoupling or whether it will be required to file such request by the Delaware PSC.
(ii)  
Unregulated Energy
Our unregulated energy segment provides natural gas marketing, propane distribution and propane wholesale marketing services to customers.

 

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Natural Gas Marketing
Our natural gas marketing subsidiary, PESCO, provides natural gas supply and supply management services to 2,486 customers in Florida and 11 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, 2010, PESCO’s operating revenues and deliveries were as follows:
                                 
    Operating Revenues     Deliveries  
State   (in thousands)     (Mcfs)  
Florida
  $ 47,441       86 %     8,236,014       84 %
Delmarva
    8,006       14 %     1,538,895       16 %
 
                       
Total
  $ 55,447       100 %     9,774,909       100 %
 
                       
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 Mcfs, and expire in May 2011. 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.
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.
Sharp, our propane distribution subsidiary, serves 34,243 customers throughout Delaware, the Eastern Shore of Maryland and Virginia, and southeastern Pennsylvania. Our Florida propane distribution subsidiary provides propane distribution services to 13,857 customers in parts of Florida. For the year ended December 31, 2010, operating revenues and total gallons sold by our Delmarva and Florida propane distribution operations were as follows:
                                 
    Operating Revenues     Total Gallons Sold  
State   (in thousands)     (in thousands)  
Delmarva
  $ 68,558       79 %     32,617       82 %
Florida
    18,725       21 %     6,995       18 %
 
                       
Total
  $ 87,283       100 %     39,612       100 %
 
                       
Propane Wholesale Marketing
Xeron, our propane wholesale marketing operation, markets propane to large, independent petrochemical companies, resellers and retail propane companies in the southeastern United States. The propane wholesale marketing business is affected by propane wholesale price volatility and supply levels. In 2010, Xeron had operating revenues totaling approximately $1.8 million, net of the associated cost of propane sold. For further discussion of Xeron’s trading and 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.

 

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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. Supplies of propane from these and other sources are readily available for purchase.
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 3.0 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
Natural gas marketing, propane distribution and propane wholesale 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 (“DOT”) 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.
(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. Certain corporate costs that have not been allocated to different operations consist of merger-related costs that have been expensed and have not been allocated because such costs are not directly attributable to the business unit operations.
Advanced Information Services
Our advanced information services subsidiary, BravePoint, is headquartered in Norcross, Georgia, and provides domestic and 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.

 

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(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.”
  (ii)  
Employees
As of December 31, 2010, we had a total of 734 employees, 160 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 at 100 F Street, N.E., Washington, DC 20549-5546; the public may obtain information on the operation of 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 Financial Officer Code of Ethics 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. Each of these documents also is 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 June 3, 2010 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 financial, operational, regulatory and legal, and environmental risk factors that may affect the operations and/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
The anticipated benefits of the merger with FPU may not be realized.
We entered into the merger with FPU with the expectation that the merger would result in various benefits, including, among other things, synergies, cost savings and operating efficiencies. Although we have achieved significant synergies, cost savings and operating efficiencies since the merger, there can be no assurance that these benefits will be sustained in the future, or additional benefits will be achieved in the future. Failure to sustain these benefits or achieve additional benefits in the future will adversely affect our expected future performance.
We are currently in discussions with the Office of Public Counsel of Florida and the Florida PSC staff regarding the benefits and cost savings of the merger, current and expected earnings level as well as the recovery of approximately $34.9 million in purchase premium and $2.2 million in merger-related costs. If we fail to obtain the necessary approval to earn a return on the purchase premium and merger-related costs and treat the amortization as allowable operating costs, we may be required to expense the amortization of these assets without recovery which will adversely affect our financial performance for the related periods. We may also be required to pass on to ratepayers, some, or all of the increased earnings generated from cost savings, resulting from the merger.
Instability and volatility in the financial markets could have a negative impact on our growth strategy.
Our business strategy includes the continued pursuit of growth, both organically and through acquisitions. To the extent that we do not generate sufficient cash 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. Currently, $40 million of the total $100 million of short-term lines of credit utilized to satisfy our short-term financing requirements are discretionary, uncommitted lines of credit. We utilize discretionary lines of credit to reduce the cost associated with these short-term financing requirements. 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.
Debt covenant obligations, if triggered, may affect our financial condition.
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.

 

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The continuation of recent economic conditions could adversely affect our customers and negatively impact our financial results.
A continued downturn in the economies of the regions in which we operate, together with increased unemployment, mortgage and other credit defaults and significant decreases in the values of homes and investment assets, have adversely affected the financial resources of many domestic households. These economic conditions have slowed the growth in our customer base and cash flows. It is unclear whether governmental responses to these conditions will be successful in lessening the severity or duration of the current recession. As a result, our customers may use less natural gas, electricity or propane and it may become more difficult for them to pay their bills. This may slow collections and lead to higher than normal levels of accounts receivable, which in turn, could increase our financing requirements and result in higher bad debt expense.
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.
Our operations are exposed to market risks, beyond our control, which could adversely affect our financial results and capital requirements.
Our natural gas marketing and propane wholesale marketing operations are subject to market risks beyond their control, including market liquidity and commodity price volatility. Although we maintain a risk management policy, 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 Xeron 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 have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.
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. These subsidiaries are also 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.

 

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Current market conditions have had an adverse impact on the return on plan assets for our pension plans, which may require significant additional funding and adversely affect our cash flows.
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. As a result of the extreme volatility and disruption in the domestic and international equity and bond markets in recent years, the asset values 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 may necessitate accelerated funding of the plans in the future to meet minimum federal government requirements. Downward pressure on the asset values of our pension plans may require us to 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
We may be unable to successfully integrate operations after the merger.
The merger between Chesapeake and FPU involves the integration of two companies that have previously operated independently. We began the process of integrating operations, both geographically and organizationally, immediately after the merger and this process is still on-going today. While significant progress has been made in integration, we continue to combine and enhance various systems, facilities and personnel deployment. Throughout the integration process, we are subject to employee workforce factors, including loss of key employees, availability of qualified personnel, collective bargaining agreements with unions and work stoppages that could affect our business and financial condition. Continued integration efforts may divert management’s focus and resources from other strategic opportunities. The diversion of management’s attention and any delays or difficulties encountered in connection with continued integration activities could result in the disruption of our ongoing businesses or inconsistencies in standards, controls, procedures and policies that adversely affect our ability to maintain relationships with customers, suppliers, employees and others with whom we have business dealings.
Fluctuations in weather may adversely affect our results of operations, cash flows and financial condition.
Our natural gas and propane distribution operations are sensitive to fluctuations in weather conditions, which directly influence the volume of natural gas and propane sold and delivered. 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. In addition, hurricanes or other extreme weather conditions could damage production or transportation facilities, which could result in decreased supplies of natural gas, propane and electricity, increased supply costs and higher prices for customers.
Our electric operations, while generally less seasonal than natural gas and propane sales as electricity is used for both heating and cooling in our service areas, are also affected by variations in general weather conditions and unusually severe weather.
The amount and availability of natural gas, electricity and propane supplies are difficult to predict; a substantial reduction in available supplies could reduce our earnings in those segments.
Natural gas, electricity and propane production can be affected by factors beyond our control, such as weather, closings of 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.

 

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We rely on a limited number of natural gas, electric and propane suppliers, the loss of which could have a materially adverse effect on our financial condition and results of operations.
Our natural gas distribution and marketing operations, electric distribution operation and propane operations have entered into various agreements with suppliers to purchase natural gas, electricity and propane to serve their 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.
We rely on having access to interstate natural gas pipelines’ transmission and storage capacity and electric transmission capacity; a substantial disruption or lack of growth in these services 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 natural gas supplies, interstate pipeline transmission and storage capacity, and electric transmission capacity to serve such requirements. We must contract for reliable and adequate delivery 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, FPU’s natural gas is transported primarily through one pipeline system. Any interruption to that system could adversely affect our ability to meet the demands of FPU’s customers and our earnings.
Commodity price changes may 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 and other fuels can significantly increase the cost of electricity billed to our electric 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.
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. 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 risk, which may adversely affect our results of operations and financial condition.
Our propane distribution operations own bulk propane storage facilities, with an aggregate capacity of approximately 3.0 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 unit 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 unit price of the propane that we purchase can change rapidly over a short period of time. The 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 U.S. generally accepted accounting principles (“GAAP”) if the market price of propane falls below our weighted average cost of inventory, which could adversely affect net income.

 

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Operating events affecting public safety and the reliability our natural gas and electric distribution systems could adversely affect the results of operations, cash flows and financial condition.
Our business is exposed to operational events, such as major leaks, mechanical problems and accidents, that could affect the public safety and reliability of our natural gas distribution and transmission systems, significantly increase costs and cause loss of customer confidence. The occurrence of any such operational events could adversely affect the results of operations, financial condition and cash flows. If we are unable to recover from customers, through the regulatory process, all or some of these costs and our authorized rate of return on these costs, this also could adversely affect the results of operations, financial condition and cash flows.
Our electric operation is subject to various operational risks, including accidents, outages, equipment breakdowns or failures, or operations below expected levels of performance or efficiency. Problems such as the breakdown or failure of electric equipment or processes and interruptions in service which would result in performance below expected levels of output or efficiency, particularly if extended for prolonged periods of time, could have a materially adverse effect on our financial condition and results of operations.
Because we operate in a competitive environment, we may lose customers to competitors which could adversely affect our results of operations, cash flows and financial condition.
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. 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 new service territories, and successfully utilizing pricing programs that retain and grow our customer base. Failure to retain and grow our customer base in our propane gas operations would have an adverse effect on our results of operations, cash flows and financial condition.
Our propane wholesale marketing operations compete with various marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.
Changes in technology may adversely affect our advanced information services subsidiary’s results of operations, cash flows and financial condition.
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.

 

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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 a risk management policy 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 these markets may adversely affect our gross margin in our regulated energy or propane distribution businesses, earnings and cash flows.
Our businesses are capital intensive, and the costs of capital projects may be significant.
Our businesses are capital intensive and require significant investments in internal infrastructure projects. Our results of operations and financial condition could be adversely affected if we do not pursue or are unable to manage such capital projects effectively or if full recovery of such capital costs is not permitted in future regulatory proceedings.
The risk of terrorism and political unrest and the current hostilities in the Middle East may adversely affect the economy and the price and availability of propane, refined fuels, electricity and natural gas.
Terrorist attacks, political unrest and the current hostilities in the Middle East may adversely affect the price and availability of propane, refined fuels and natural gas, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil, electricity or natural gas supplies and markets, and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport/transmit propane, electricity and natural gas if our means of supply transportation, such as rail, power grid or pipeline, become damaged as a result of an attack. A lower level of economic activity following such events could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity and hostilities in the Middle East could likely lead to increased volatility in prices for propane, refined fuels, electricity and natural gas. We maintain insurance policies with insurers in such amounts and with such coverage and deductibles as 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.
Operational interruptions to our natural gas transmission and natural gas and electric distribution activities, caused by accidents, malfunctions, severe weather (such as a major hurricane), a pandemic or acts of terrorism, could adversely impact earnings.
Inherent in natural gas transmission and natural gas and electric distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, explosions and mechanical problems. If they are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in the loss of human life, significant damage to property, environmental damage and impairment of our operations. The location of pipeline, storage, transmission and distribution facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Our natural gas and electric distribution, natural gas transmission and propane storage facilities may be targets of terrorist activities that could disrupt our ability to meet customer requirements. Terrorist attacks may also disrupt capital markets and our ability to raise capital. A terrorist attack on our facilities, or those of our suppliers or customers, could result in a significant decrease in revenues or a significant increase in repair costs. The occurrence of any of these events could adversely affect our results of operations, cash flows and financial condition.

 

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Our regulated energy business will 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 results of operation.
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.
Regulatory and Legal Risks
Regulation of our Company, 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. ESNG is regulated by the FERC. These commissions 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, these commissions may require us to refund the excess earnings or reduce our rates charged to customers in the future.
We are required to detail known benefits, synergies, cost savings and cost increases resulting from the FPU merger and present the information in the “come-back” filing to the Florida PSC by April 29, 2011 (within 18 months of the FPU merger). We also intend to seek for the recovery of the purchase premium and merger-related costs from the FPU merger. We are currently in discussions with the Office of Public Counsel of Florida regarding the “come-back” filing and the recovery of the purchase premium and merger-related costs. The outcome of such discussions or the ultimate outcome of the “come-back” filing, are unknown at this time.
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.
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. As a result, we are sometimes a defendant in legal proceedings arising in the ordinary course of business. We maintain insurance policies with insurers in the amount of $51 million covering general liabilities of our Company, 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.

 

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We have recorded significant amounts of goodwill and regulatory assets prior to obtaining a rate order. An adverse outcome could result in an impairment of those assets.
The merger with FPU and the purchase of the operating assets from IGC resulted in approximately $34.9 million in purchase premium which is currently recorded as goodwill. We intend to seek regulatory approval to include the purchase premium and approximately $2.2 million in merger-related costs in future rates in Florida. Other utilities in Florida, including Chesapeake and FPU in the past, have been successful in recovering similar costs by demonstrating benefits to customers attributable to the business combination. The ultimate outcome of such regulatory proceedings will depend on various factors, including but not limited to, our ability to demonstrate the benefits of the merger, the regulatory environment in Florida and the results of our Florida regulated operations. If we are not successful in obtaining regulatory approval to recover these costs in future rates, we will be required to perform impairment tests of goodwill and regulatory assets, the results of which could be an impairment of all or part of the goodwill and/or regulatory assets in the future.
We may face certain regulatory and financial risks related to climate change legislation.
A number of proposals to limit greenhouse gas emissions, measured in carbon dioxide equivalent units, are pending, or at least being considered, at regional, federal and international levels. These proposals would require us to measure and potentially limit greenhouse gas emissions from our energy operations and our customers or purchase allowances for such emissions. While we cannot predict with certainty the extent of these limitations or when they will become effective, these actions could:
   
increase our costs related to operations, energy efficiency activities and compliance;
   
affect the demand for natural gas, electricity and propane; and
   
increase the prices we charge our energy customers.
The occurrence of any such legislation could adversely affect our results of operations, financial condition and cash flows. If our regulated energy operations are unable to recover from customers through the regulatory process all or some of these costs and our authorized rate of return on these costs, this also could adversely affect our results of operations, financial condition and cash flows.
We may face certain regulatory and financial risks related to pipeline safety legislation.
A number of proposals to implement increased oversight over 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. While we cannot predict with certainty the extent of these expenses and expenditures or when they will become effective, the adoption of such legislation could adversely affect our results of operations, financial conditions and cash flows. If our regulated natural gas operations are unable to recover from customers through the regulatory process all or some of these costs and our authorized rate of return on these costs, this also could adversely affect our results of operations, financial condition and cash flows.

 

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Environmental Risks
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 current and former operating sites, including former manufactured gas plant (“MGP”) sites that we have acquired from third-parties. 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.
Pending environmental matters, particularly with respect to FPU’s site in West Palm Beach, Florida, may have a materially adverse effect on our Company and our results of operations.
We have participated in the investigation, assessment or remediation of environmental matters with respect to certain of our properties and we believe our Company has certain exposures at six former MGP sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland. The Key West, Pensacola, Sanford and West Palm Beach sites are related to FPU, for which we assumed any existing and future contingencies in the merger with FPU.
The site with the most potential exposure is the former West Palm Beach MGP. In November 2010, we presented a new proposed strategy with an aggressive remedial action plan to expedite remediation of this site, and the Florida Department of Environmental Protection (the “FDEP”) agreed with the proposal to implement a phased approach. In February 2011, FDEP approved the interim Remedial Action Plan (“RAP”) for the east parcel of this site, contingent upon certain conditions, and we are currently implementing the plan. Our current estimate of total remediation costs and expenses for the West Palm Beach site based on the most recently proposed remedial action plan is between $5.1 million and $13.3 million. This estimate does not include any costs associated with relocation of our operations from the site, which is necessary to implement the remedial action, and any potential costs associated with re-development of the properties. Actual costs may also be higher or lower than the range of current estimate based upon the final remedy required by FDEP.
As of December 31, 2010, we had recorded $358,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Winter Haven, Florida, representing our estimate of the future costs associated with those sites. We had recorded approximately $1.3 million in assets for future recovery of environmental costs to be received from our customers through our approved rates. As of December 31, 2010, we had recorded approximately $11.6 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily related to the West Palm Beach site. Such amount represents our estimate as of December 31, 2010, of the future costs associated with those sites, although FPU is approved to recover its environmental costs up to $14.0 million from insurance and customers through approved rates. Of the approximately $11.6 million recorded as environmental liabilities related to FPU’s MGP sites in Florida as of December 31, 2010, we have recovered approximately $7.8 million of environmental costs from insurance and customers through rates, and have recorded approximately $6.2 million in assets for future recovery of environmental costs to be received from FPU’s customers through approved rates.

 

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The costs and expenses we incur to address environmental issues at our sites may have a material adverse effect on our results of operations and earnings to the extent that such costs and expenses exceed the amounts we have accrued as environmental reserves or that we are otherwise permitted to recover from customers through rates. At present, we believe that the amounts accrued as environmental reserves and that we are otherwise permitted to recover from customers through rates are sufficient to fund the pending environmental liabilities previously described.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
(a) General
We own offices and operate facilities in the following locations: Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; Lecanto, Virginia; and West Palm Beach, DeBary, Inglis, Indiantown, Marianna, Lantana, Lauderhill, Fernandina Beach and Winter Haven, Florida. We rent office space in Dover, Ocean View, and South Bethany, Delaware; Fernandina and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton, Maryland; Honey Brook 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 over 1,127 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 operations, including Chesapeake’s Florida division and FPU in its service areas, own 2,451 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
ESNG owns and operates approximately 396 miles of transmission pipeline, extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania; Honey Brook, Pennsylvania; and Hockessin, Delaware, to approximately 80 delivery points in southeastern Pennsylvania, Delaware and the Eastern Shore of Maryland.
PIPECO owns and operates approximately eight miles of transmission pipeline in Suwanee County, Florida.
(d) Electric Distribution
The Company’s electric distribution operation owns and operates 20 miles of electric transmission line located in northeast Florida and 1,128 miles of electric distribution line located in northeast and northwest Florida.
(e) Propane Distribution and Wholesale Marketing
Our Delmarva-based propane distribution operation owns bulk propane storage facilities, with an aggregate capacity of approximately 2.4 million gallons, at 42 plant facilities in Delaware, Maryland, Pennsylvania and Virginia, located on real estate that is either owned or leased by our Company. Our Florida-based propane distribution operation owns 24 bulk propane storage facilities with a total capacity of 642,000 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 and Fernandina Beach, Florida. FPU’s natural gas distribution operation owns 1,659 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 1,128 miles of electric distribution line located in northeast and northwest Florida. FPU’s propane distribution operation owns 24 bulk propane storage facilities with a total capacity of 642,000 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 Q, “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 P, Environmental Commitments and Contingencies.”
Item 4. Removed and Reserved
Item 4A. Executive Officers of the Registrant.
Set forth below are the names, ages, and positions of executive officers of the registrant 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
    52     President and Chief Executive Officer
Beth W. Cooper
    44     Senior Vice President and Chief Financial Officer
Stephen C. Thompson
    50     Senior Vice President and President, ESNG
Joseph Cummiskey
    39     Vice President and President, PESCO
Elaine B. Bittner
    41     Vice President of Strategic Development
Michael P. McMasters is President and Chief Executive Officer of Chesapeake. Mr. McMasters assumed the role of Chief Executive Officer effective January 1, 2011 and was appointed as President on March 1, 2010. Prior to these appointments, Mr. McMasters served as Chief Operating Officer since 2008, Senior Vice President since 2004 and Chief Financial Officer of Chesapeake since 1996. He has previously held the positions of Vice President, Treasurer, Director of Accounting and Rates, and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company.
Beth W. Cooper was appointed as Senior Vice President and Chief Financial Officer in September 2008 in addition to her duties as Treasurer and Corporate Secretary. Prior to this appointment, Ms. Cooper served as Vice President and Corporate Secretary of Chesapeake Utilities Corporation since July 2005. She has served as Treasurer of Chesapeake since 2003. She previously served as Assistant Treasurer and Assistant Secretary, Director of Internal Audit, Director of Strategic Planning, Planning Consultant, Accounting Manager for Non-regulated Operations and Treasury Analyst. Prior to joining Chesapeake, she was employed as an auditor with Ernst & Young’s Entrepreneurial Services Group.

 

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Stephen C. Thompson is Senior Vice President of Chesapeake and President of ESNG. Prior to becoming Senior Vice President in 2004, he served as Vice President of Chesapeake. He has also served as Vice President, Director of Gas Supply and Marketing, Superintendent of ESNG and Regional Manager for the Florida distribution operations.
Joseph Cummiskey was appointed as Vice President of Chesapeake and President of PESCO in December 2009. Mr. Cummiskey joined Chesapeake in December 2005 as the Director of Propane Supply and Wholesale Marketing. In 2008 and 2009, he served as the Director of Strategic Planning/Corporate Development and Director of Propane Operations. Prior to joining Chesapeake, Mr. Cummiskey was employed as a Natural Gas Liquids Regional Director for Ferrell North America. In that position, he was responsible for the purchasing and distribution of Ferrell’s propane supply.
Elaine B. Bittner was appointed as Vice President of Strategic Development in June 2010. Prior to this appointment, Ms. Bittner served as Vice President of ESNG since 2005. She previously served as Director of ESNG, Director of Customer Services and Regulatory Affairs for ESNG, Director of Environmental Affairs for Chesapeake, Manager of Environmental Affairs and Environmental Engineer. Prior to joining Chesapeake, 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.
Part II
Item 5.  
Market for the Registrant’s 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 the years 2010 and 2009 were as follows:
                                     
                                Dividends  
                                Declared  
    Quarter Ended   High     Low     Close     Per Share  
2010
                                   
 
  March 31   $ 32.25     $ 28.22     $ 29.80     $ 0.315  
 
  June 30     32.20       28.01       31.40       0.330  
 
  September 30     36.93       30.24       36.22       0.330  
 
  December 31     42.20       35.00       41.52       0.330  
 
                                   
2009
                                   
 
  March 31   $ 32.36     $ 22.02     $ 30.48     $ 0.305  
 
  June 30     34.55       27.62       32.53       0.315  
 
  September 30     35.00       29.24       30.99       0.315  
 
  December 31     32.67       29.53       32.05       0.315  
Holders
At December 31, 2010, there were 2,482 holders of record of Chesapeake common stock.

 

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Dividends
We have paid a cash dividend to common stock shareholders for 50 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 2010 and 2009, totaling $1.305 per share and $1.250 per share, respectively.
Indentures to the long-term debt of the Company 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, 2010, Chesapeake’s cumulative consolidated net income base was $128.9 million, offset by Restricted Payments of $76.2 million, leaving $52.7 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 provided 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, 2010, FPU had a cumulative net income base of $65.9 million, offset by restricted payments of $37.6 million, leaving $28.3 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 2010 that were not registered under the Securities Act of 1933, as amended.
(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, 2010.
                                 
    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, 2010 through October 31, 2010 (1)
    258     $ 37.58              
November 1, 2010 through November 30, 2010
                       
December 1, 2010 through December 31, 2010
                       
 
                       
Total
    258     $ 37.58              
 
                       
(1)  
Chesapeake purchased shares of 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 Note N to the Consolidated Financial Statements. During the quarter, 258 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 compensation plans of Chesapeake and its subsidiaries, 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, 2011, in connection with the Company’s Annual Meeting to be held on or about May 4, 2011 and, is incorporated herein by reference.

 

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(c) Chesapeake Utilities Corporation Common Stock Performance Graph
The following Stock Performance graph compares cumulative total shareholder return on a hypothetical investment in our common stock during the five fiscal years ended December 31, 2010, with the cumulative total shareholder 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 11 of the companies in the current Edward Jones Natural Gas Distribution Group, a published listing of selected gas distribution utilities’ results. The Compensation Committee utilizes the Edward Jones Natural Gas Distribution Group as our peer group to which our performance is compared for purposes of determining the level of long-term performance awards earned by our named executives.
The eleven companies in the Edward Jones Natural Gas Distribution Group industry index include: AGL Resources, Inc., Atmos Energy Corporation, Delta Natural Gas Company, Inc., Gas Natural, Inc., The Laclede Group, Inc., New Jersey Resources Corporation, Northwest Natural Gas Company, Piedmont Natural Gas Co., Inc., RGC Resources, Inc., South Jersey Industries, Inc, and WGL Holdings, Inc.
The comparison assumes $100 was invested on December 31, 2005 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.
(PERFORMANCE GRAPH)
                                                 
    2005     2006     2007     2008     2009     2010  
Chesapeake
  $ 100     $ 103     $ 111     $ 114     $ 121     $ 161  
Industry Index
  $ 100     $ 119     $ 123     $ 132     $ 136     $ 155  
S&P 500 Index
  $ 100     $ 116     $ 122     $ 77     $ 97     $ 112  

 

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Item 6. Selected Financial Data
                         
For the Years Ended December 31,   2010     2009(2)     2008  
Operating(1)                        
(in thousands)                        
Revenues
                       
Regulated Energy
  $ 269,934     $ 139,099     $ 116,468  
Unregulated Energy
    146,793       119,973       161,290  
Other
    10,819       9,713       13,685  
 
                 
Total revenues
  $ 427,546     $ 268,785     $ 291,443  
 
                       
Operating income
                       
Regulated Energy
  $ 43,509     $ 26,900     $ 24,733  
Unregulated Energy
    7,908       8,158       3,781  
Other
    513       (1,322 )     (35 )
 
                 
Total operating income
  $ 51,930     $ 33,736     $ 28,479  
 
                       
Net income from continuing operations
  $ 26,056     $ 15,897     $ 13,607  
 
                       
Assets                        
(in thousands)
                       
Gross property, plant and equipment
  $ 584,385     $ 543,905     $ 381,689  
Net property, plant and equipment
  $ 462,757     $ 436,587     $ 280,671  
Total assets
  $ 670,993     $ 615,811     $ 385,795  
Capital expenditures (1)
  $ 46,955     $ 26,294     $ 30,844  
 
                       
Capitalization                        
(in thousands)
                       
Stockholders’ equity
  $ 226,239     $ 209,781     $ 123,073  
Long-term debt, net of current maturities
    89,642       98,814       86,422  
 
                 
Total capitalization
  $ 315,881     $ 308,595     $ 209,495  
                         
Current portion of long-term debt
    9,216       35,299       6,656  
Short-term debt
    63,958       30,023       33,000  
 
                 
Total capitalization and short-term financing
  $ 389,055     $ 373,917     $ 249,151  
 
                 
(1)  
These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company closed its distributed energy operation in 2007. All assets of all 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 (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. These amounts may not be indicative of future results due to the inclusion of merger effects. See Item 8 under the heading “Notes to the Consolidated Financial Statements - Note B, Acquisitions and Dispositions” for additional discussions and presentation of pro forma results.
 
(3)  
SFAS No. 123R (now codified within FASB ASC 718, 505 and 260 ) and SFAS No. 158 (codified within FASB ASC 715) were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 27


Table of Contents

 
 
                                                     
2007     2006 (3)     2005     2004     2003     2002     2001  
                                                     
                                                     
                                                     
$ 128,850     $ 124,631     $ 124,563     $ 98,139     $ 92,079     $ 82,098     $ 87,444  
  115,190       94,320       90,995       67,607       59,197       40,728       56,970  
  14,246       12,249       13,927       12,209       12,292       12,430       13,992  
                                       
$ 258,286     $ 231,200     $ 229,485     $ 177,955     $ 163,568     $ 135,256     $ 158,406  
                                                     
                                                     
$ 21,809     $ 18,593     $ 16,248     $ 16,258     $ 16,219     $ 14,867     $ 14,060  
  5,174       3,675       4,197       3,197       4,310       1,158       1,259  
  1,131       1,064       1,476       722       1,050       580       902  
                                       
$ 28,114     $ 23,332     $ 21,921     $ 20,177     $ 21,579     $ 16,605     $ 16,221  
                                                     
$ 13,218     $ 10,748     $ 10,699     $ 9,686     $ 10,079     $ 7,535     $ 7,341  
                                                     
                                                     
                                                     
$ 352,838     $ 325,836     $ 280,345     $ 250,267     $ 234,919     $ 229,128     $ 216,903  
$ 260,423     $ 240,825     $ 201,504     $ 177,053     $ 167,872     $ 166,846     $ 161,014  
$ 381,557     $ 325,585     $ 295,980     $ 241,938     $ 222,058     $ 223,721     $ 222,229  
$ 30,142     $ 49,154     $ 33,423     $ 17,830     $ 11,822     $ 13,836     $ 26,293  
                                                     
                                                     
                                                     
$ 119,576     $ 111,152     $ 84,757     $ 77,962     $ 72,939     $ 67,350     $ 67,517  
  63,256       71,050       58,991       66,190       69,416       73,408       48,409  
                                       
$ 182,832     $ 182,202     $ 143,748     $ 144,152     $ 142,355     $ 140,758     $ 115,926  
 
                               
  7,656       7,656       4,929       2,909       3,665       3,938       2,686  
  45,664       27,554       35,482       5,002       3,515       10,900       42,100  
                                       
$ 236,152     $ 217,412     $ 184,159     $ 152,063     $ 149,535     $ 155,596     $ 160,712  
                                       

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 28


Table of Contents

                         
For the Years Ended December 31,   2010     2009(3)     2008  
Common Stock Data and Ratios
                       
Basic earnings per share from continuing operations (1)
  $ 2.75     $ 2.17     $ 2.00  
Diluted earnings per share from continuing operations (1)
  $ 2.73     $ 2.15     $ 1.98  
Return on average equity from continuing operations (1)
    11.6 %     11.2 %     11.2 %
Common equity / total capitalization
    71.6 %     68.0 %     58.7 %
Common equity / total capitalization and short-term financing
    58.2 %     56.1 %     49.4 %
 
                       
Book value per share
  $ 23.75     $ 22.33     $ 18.03  
 
                       
Market price:
                       
High
  $ 42.200     $ 35.000     $ 34.840  
Low
  $ 28.010     $ 22.020     $ 21.930  
Close
  $ 41.520     $ 32.050     $ 31.480  
 
                       
Average number of shares outstanding
    9,474,554       7,313,320       6,811,848  
Shares outstanding at year-end
    9,524,195       9,394,314       6,827,121  
Registered common shareholders
    2,482       2,670       1,914  
 
                       
Cash dividends declared per share
  $ 1.31     $ 1.25     $ 1.21  
Dividend yield (annualized) (2)
    3.2 %     3.9 %     3.9 %
Payout ratio from continuing operations (1) (4)
    47.6 %     57.6 %     60.5 %
 
                       
Additional Data
                       
Customers (5)
                       
Natural gas distribution
    120,230       117,887       65,201  
Electric distribution
    30,966       31,030        
Propane distribution
    48,100       48,680       34,981  
 
                       
Volumes(6)
                       
Natural gas deliveries (in Mcfs)
    41,795,438       44,586,158       39,778,067  
Electric Distribution (in MWHs)
    739,656       105,739        
Propane distribution (in thousands of gallons)
    39,612       32,546       27,956  
 
                       
Heating degree-days (Delmarva Peninsula)
                       
Actual HDD
    4,831       4,729       4,431  
10-year average HDD (normal)
    4,528       4,462       4,401  
 
                       
Propane bulk storage capacity (in thousands of gallons)
    3,041       3,042       2,471  
 
                       
Total employees (1) (7)
    734       757       448  
(1)  
These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003.
 
(2)  
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.
 
(3)  
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. These amounts also include the effects of acquisition accounting and issuance of Chesapeake common shares as a result of the merger. These amounts may not be indicative of future results due to the inclusion of merger effects. See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note B, Acquisitions and Dispositions” for additional discussions and presentation of pro forma results.
 
(4)  
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.
 
(5)  
Customer data for 2009 includes 51,536, 31,030 and 13,651 of natural gas distribution, electric distribution and propane distribution customers, respectively, from FPU.
 
(6)  
Volumes data for 2009 includes 1,109,177 Mcfs, 105,739 MWHs and 1.1 million gallons for natural gas distribution, electric distribution and propane distribution, respectively, delivered by FPU from October 28, 2009 through December 31, 2009
 
(7)  
Total employees for 2009 include 332 FPU employees added to the Company upon the merger, effective October 28, 2009.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 29


Table of Contents

                                                     
2007     2006(8)     2005     2004     2003     2002     2001  
                                                     
$ 1.96     $ 1.78     $ 1.83     $ 1.68     $ 1.80     $ 1.37     $ 1.37  
$ 1.94     $ 1.76     $ 1.81     $ 1.64     $ 1.76     $ 1.37     $ 1.35  
  11.5 %     11.0 %     13.2 %     12.8 %     14.4 %     11.2 %     11.1 %
  65.4 %     61.0 %     59.0 %     54.1 %     51.2 %     47.8 %     58.2 %
  50.6 %     51.1 %     46.0 %     51.3 %     48.8 %     43.3 %     42.0 %
                                                     
$ 17.64     $ 16.62     $ 14.41     $ 13.49     $ 12.89     $ 12.16     $ 12.45  
                                                     
                                                     
$ 37.250     $ 35.650     $ 35.780     $ 27.550     $ 26.700     $ 21.990     $ 19.900  
$ 28.000     $ 27.900     $ 23.600     $ 20.420     $ 18.400     $ 16.500     $ 17.375  
$ 31.850     $ 30.650     $ 30.800     $ 26.700     $ 26.050     $ 18.300     $ 19.800  
                                                     
  6,743,041       6,032,462       5,836,463       5,735,405       5,610,592       5,489,424       5,367,433  
  6,777,410       6,688,084       5,883,099       5,778,976       5,660,594       5,537,710       5,424,962  
  1,920       1,978       2,026       2,026       2,069       2,130       2,171  
                                                     
$ 1.18     $ 1.16     $ 1.14     $ 1.12     $ 1.10     $ 1.10     $ 1.10  
  3.7 %     3.8 %     3.7 %     4.2 %     4.2 %     6.0 %     5.6 %
  60.2 %     65.2 %     62.3 %     66.7 %     61.1 %     80.3 %     80.3 %
                                                     
                                                     
                                                     
  62,884       59,132       54,786       50,878       47,649       45,133       42,741  
                                       
  34,143       33,282       32,117       34,888       34,894       34,566       35,530  
                                                     
                                                     
  34,820,050       34,321,160       34,980,939       31,429,494       29,374,818       27,934,715       27,263,542  
                                       
  29,785       24,243       26,178       24,979       25,147       21,185       23,080  
                                                     
                                                     
  4,504       3,931       4,792       4,553       4,715       4,161       4,368  
  4,376       4,372       4,436       4,389       4,409       4,393       4,446  
 
   
  2,441       2,315       2,315       2,045       2,195       2,151       1,958  
 
   
  445       437       423       426       439       455       458  
(8)  
SFAS No. 123R (now codified within FASB ASC 718, 505 and 260 ) and SFAS No. 158 (codified within FASB ASC 715) were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 30


Table of Contents

Management’s Discussion and Analysis
Item 7.  
Management’s 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 on 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 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. Chesapeake’s management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.
In addition, certain information is presented, which, for comparison purposes, includes only FPU’s results of operations or exclude FPU’s results from the consolidated results of operations for the periods from the merger closing (October 28, 2009) to December 31, 2009 and in 2010. Certain other information is presented, which, for comparison purposes, excludes all merger-related costs incurred in connection with the FPU merger. Although the non-GAAP measures are not intended to replace the GAAP measures for evaluation of Chesapeake’s performance, we believe that the portions of the presentation which include only the FPU results, or which exclude FPU’s financial results for the post-merger period and merger-related costs provide a helpful comparative basis for investors to understand Chesapeake’s performance.
The following discussion sometimes refers to “legacy Chesapeake” and words of similar import. Such terms and phrases mean our results, excluding the impacts from the FPU merger and merger-related costs
(a) Introduction
Chesapeake is 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;
 
   
utilizing our expertise across our various businesses to improve overall performance;
 
   
enhancing marketing channels to attract new customers;
 
   
providing reliable and responsive customer service to retain existing customers;
 
   
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 2010 Form 10-K     Page 31


Table of Contents

Management’s Discussion and Analysis
(b) Highlights and Recent Developments
(in thousands except per share)
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
Net income
  $ 26,056     $ 15,897     $ 10,159     $ 15,897     $ 13,607     $ 2,290  
Earnings per common stock — diluted
  $ 2.73     $ 2.15     $ 0.58     $ 2.15     $ 1.98     $ 0.17  
 
                                               
Components of net income:
                                               
Legacy Cheapeake
  $ 17,192     $ 15,303     $ 1,889     $ 15,303     $ 14,299     $ 1,004  
FPU
    9,339       1,829       7,510       1,829             1,829  
Merger-related costs
    (475 )     (1,235 )     760       (1,235 )     (692 )     (543 )
 
                                   
Total
  $ 26,056     $ 15,897     $ 10,159     $ 15,897     $ 13,607     $ 2,290  
 
                                   
 
                                               
Components of EPS — diluted
                                               
Legacy Chesapeake (1)
  $ 2.44     $ 2.20     $ 0.24     $ 2.20     $ 2.08     $ 0.12  
FPU(2)
  $ 0.34     $ 0.12     $ 0.22     $ 0.12     $ 0.00     $ 0.12  
Merger-related costs
  $ (0.05 )   $ (0.17 )   $ 0.12     $ (0.17 )   $ (0.10 )   $ (0.07 )
 
                                   
Total
  $ 2.73     $ 2.15     $ 0.58     $ 2.15     $ 1.98     $ 0.17  
 
                                   
     
(1)  
Calculated based on weighted average common shares outstanding for the period, which excludes the shares issued in the FPU merger.
 
(2)  
Represents the additional EPS generated by FPU’s results since the merger.
On October 28, 2009, we completed a merger with FPU. The merger increased our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing natural gas and propane distribution operations in Florida. We also now serve approximately 31,000 electric distribution customers in northwest and northeast Florida as a result of the merger. FPU’s results have been included in our consolidated results since the completion of the merger.
Excluding the impacts from the FPU merger and merger-related costs, our diluted earnings per share from legacy Chesapeake businesses increased by 11 percent and six percent in 2010 and 2009, respectively, compared to the respective prior year.
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. Since FPU’s results for the period prior to the merger were not included in our results, the year-over-year variances resulting from the factors described below as they relate to FPU are limited to the period after the merger.
   
Weather. We measure weather based on the number of heating degree-days (“HDD”) for the natural gas and propane distribution operations and the number of HDD and the number of cooling degree-days (“CDD”) for the electric distribution operation. We use historical averages as the “normal” weather for this analysis.
 
     
HDD on the Delmarva Peninsula in 2010 increased by 102, or two percent, compared to 2009, and by 303, or seven percent, compared to normal. HDD on the Delmarva Peninsula in 2009 increased by 298, or seven percent, compared to 2008, and by 267, or six percent, compared to normal. We estimate that colder weather contributed approximately $679,000 and $1.6 million in additional gross margin for our Delmarva natural gas and propane distribution operations in 2010 and 2009, respectively, compared to the respective prior year. We also estimate that the effect of the colder-than-normal temperatures on the Delmarva Peninsula in 2010 was increased gross margin of $1.6 million for our Delmarva natural gas and propane distribution operations.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 32


Table of Contents

Management’s Discussion and Analysis
     
The colder temperatures in 2010 in Florida produced average HDD that were 590, or 65 percent, higher than 2009 and 582, or 63 percent, higher than normal. The average HDD in 2009 and 2008 were fairly consistent and did not fluctuate significantly from the normal weather. The warmer temperatures in the summer of 2010 also produced average CDD for the year that were 89, or three percent, higher than the prior year and 141, or five percent, higher than normal. We estimate that colder weather in the winter months and warmer weather in the summer months contributed approximately $1.4 million in additional gross margin for our Florida natural gas and electric distribution operations in 2010, compared to 2009.
 
   
Growth. Despite the continued slowdown in growth and overall economic conditions on the Delmarva Peninsula, our Delmarva natural gas distribution operations achieved two percent growth in average residential customers in both 2010 and 2009, compared to the respective prior year. These growth rates exceeded the industry’s growth rates. In addition to the residential growth, in 2010, our Delmarva natural gas distribution operations added 10 large commercial and industrial customers with total expected annual margin of $748,000, as they were able to convert these customers to natural gas from other energy sources due to the pricing advantage of natural gas and its environmentally-friendly features. In total, customer growth for the Delmarva natural gas distribution operations generated additional margin of $1.1 million and $1.2 million in 2010 and 2009, respectively, compared to the respective prior year. The addition of certain industrial customers in 2010 also positioned us to further extend our natural gas distribution and transmission infrastructure in southern Delaware to serve other potential customers in the same area.
 
     
ESNG continued to expand its infrastructure and add new transportation services. The additional margin generated from the continued expansions and new services, net of the expired services, was $1.1 million and $1.8 million in 2010 and 2009, respectively, compared to the respective prior year. Although not affecting our results in 2010, ESNG completed the eight-mile mainline extension in December 2010 to interconnect with the TETLP pipeline. ESNG commenced its new transportation services to Chesapeake’s Delaware and Maryland divisions in January 2011. The new transportation services have a three-year phase-in from 19,324 Mcfs per day to 38,647 Mcfs per day, providing estimated annualized margin of $2.4 million in 2011, $3.9 million in 2012 and $4.3 million thereafter.
 
     
FPU’s natural gas distribution operation experienced growth in commercial and industrial customers in 2010, which contributed $196,000 in additional margin in 2010. Chesapeake’s Florida natural gas distribution division experienced a slight growth in customers in 2010 after experiencing a net customer loss in 2009, including a loss of three large industrial customers, in Florida in late 2008 and 2009, which decreased its margin by $190,000 in 2009 compared to 2008. Customer growth in the Florida electric and propane distribution operations was flat.
 
   
Rates and Regulatory Matters. On January 14, 2010, new rates for Chesapeake’s Florida natural gas distribution division became effective. The new rates for Chesapeake’s Florida natural gas distribution division represented an annual rate increase of approximately $2.5 million and generated $2.3 million in increased margin in 2010, net of the impact from the interim rates in 2009, compared to 2009. An annual rate increase of approximately $8.0 million for FPU’s natural gas distribution operation pursuant to the settlement agreement also became effective on January 14, 2010. The Florida PSC previously issued an Order in May 2009, approving a rate increase for FPU’s natural gas distribution operation. The subsequent protest by the Office of Public Counsel of Florida led to this settlement agreement between the Office of Public Counsel and FPU, which the Florida PSC approved in December 2009.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 33


Table of Contents

Management’s Discussion and Analysis
     
The merger with FPU and the purchase of the operating assets of IGC resulted in approximately $34.9 million in purchase premium, which we intend to seek the recovery through rates. We also intend to seek the recovery of approximately $2.2 million in merger-related costs attributed to the natural gas operations. Our Florida natural gas distribution operations are required to submit to the Florida PSC by April 29, 2011 data that details benefits, synergies, cost savings and cost increases resulting from the merger. We are currently in the process of discussing with the Office of Public Counsel and the Florida PSC staff the benefits and cost savings resulted from the merger, current and expected operating results of the regulated operations in Florida, and recovery of the purchase premium and merger-related costs. Our results in 2010 reflect an accrual of $750,000 by FPU’s natural gas distribution operation for the regulatory risk associated with its earnings, merger benefits and recovery of purchase premium and merger-related costs. Also reflected in our 2010 results were approximately $75,000 of the costs associated with these discussions, which were expensed in 2010.
 
     
Although not affecting our results in 2010, ESNG filed a proposed rate increase with the FERC on December 30, 2010. ESNG expects this base rate proceeding to be completed in 2011. ESNG expensed approximately $147,000 in costs associated with this filing in 2010.
 
   
Propane Prices. A sharp decline in propane prices in the winter months when our propane inventory is at its highest level exposes us to inventory valuation risk as GAAP requires us to re-value the propane inventory using the “lower-of-cost-or-market” approach. We have implemented various propane supply and inventory strategies to hedge such risk. In late 2008, a sharp decline in propane prices resulted in inventory and swap valuation adjustments of $1.8 million in 2008, which lowered the propane inventory cost of our Delmarva propane distribution operation during the first half of 2009. The absence of similar inventory valuation adjustments in 2009 and increased margin generated from the low propane cost during the first half of 2009, coupled with sustained retail prices, contributed to increased gross margin of $3.5 million in 2009 compared to 2008 for the Delmarva propane distribution operation. Retail margins returned to more normal levels in 2010.
 
     
Continued lack of volatility in wholesale propane prices reduced the opportunities for our propane wholesale marketing subsidiary, Xeron, and decreased its trading volume by 13 percent and 57 percent in 2010 and 2009, respectively, compared to the respective prior year. The lower volumes reduced gross margin by approximately $441,000 and $1.0 million for 2010 and 2009, respectively, over the prior year.
 
   
Natural Gas Spot Sale Opportunities. Our unregulated natural gas marketing subsidiary, PESCO, entered into spot sales in 2009 with a refinery on the Delmarva Peninsula, which contributed significantly to PESCO’s gross margin increase of $1.0 million in 2009. The absence of spot sales opportunities to the same customer in 2010 reduced PESCO’s margin in 2010, compared to 2010. Spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts.
 
   
Interest Rates. We continued to experience low short-term interest rates throughout 2010 and 2009 as our short-term weighted average interest rate approximated 1.77 percent in 2010, 1.28 percent in 2009, and 2.79 percent in 2008. The level of our short-term borrowings in 2010 increased over 2009 as we used a new short-term term loan facility to finance the redemption of $29.1 million of FPU’s 6.85 percent and 4.90 percent secured first mortgage bonds prior to their respective maturities. The level of our short-term borrowings in 2009 was reduced by the placement of $30.0 million of 5.93 percent unsecured senior notes in October 2008 and a decline in working capital requirements due to lower commodity prices, lower trading volume by the propane wholesale marketing subsidiary, lower income tax payments from bonus depreciation and the timing of our capital expenditures.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 34


Table of Contents

Management’s Discussion and Analysis
   
Advanced Information Services. Our advanced information services subsidiary, BravePoint, generated $759,000 in operating income in 2010, compared to an operating loss of $229,000 in 2009. Increased billable consulting hours in 2010 and cost containment actions implemented throughout 2009 contributed to the increased operating results.
(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 discussed with 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,” 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 A, Summary of Accounting Policies,” we have recorded regulatory assets of $23.9 million and regulatory liabilities of $47.8 million, at December 31, 2010. If we were required to terminate application of this Topic, 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 P, Environmental Commitments and Contingencies,” we have completed our responsibilities related to one environmental site and are currently participating in the investigation, assessment or remediation of seven other former MGP sites. Amounts have been recorded as environmental liabilities and associated environmental regulatory assets based on estimates of future costs provided by independent consultants. 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.
Since we believe that recovery of these expenditures, including any litigation costs, is probable through the regulatory process, we have recorded a regulatory asset and corresponding environmental liability. At December 31, 2010, we have recorded environmental regulatory and other assets of $7.5 million and a liability of $12.0 million for environmental costs.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 35


Table of Contents

Management’s Discussion and Analysis
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 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, 2010 and 2009:
   
During 2010 and 2009, 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.
 
   
During 2010 and 2009, the propane distribution operation entered into a put option to protect it from the impact of price decreases on the Pro-Cap (propane price-cap) Plan that we offer to customers. We accounted for the put option on a mark-to-market basis and recorded a loss of $168,000 and $41,000, at December 31, 2010 and 2009, respectively.
 
   
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 Statement of Income as revenue or expense. These contracts generally mature within one year and are almost exclusively for propane commodities. For the years ended December 31, 2010 and 2009, these contracts had net unrealized gains of $284,000 and net unrealized losses of $1.6 million, respectively.
Operating Revenues
Revenues for our natural gas and electric distribution operations are based on rates approved by the PSCs of the jurisdictions in which we operate. The natural gas transmission operation’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 ESNG 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. In connection with this accrual, we must estimate amounts of natural gas and electricity that have not been accounted for on our delivery systems and must 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 our statement of income. For certain propane distribution customers without meters and advanced information services customers, we record revenue in the period the products are delivered and/or services are rendered.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 36


Table of Contents

Management’s Discussion and Analysis
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 purchased 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 purchased fuel costs 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 is 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 experiences, 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.
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 M, 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.
The total pension and other postretirement benefit costs included in operating income were $2.0 million, $892,000 and $537,000, in 2010, 2009 and 2008, respectively. We expect to record pension and postretirement benefit costs of approximately $2.0 million for 2011, of which $455,000 are settlement losses related to lump-sum distributions we expect to make during 2011, from the Chesapeake Pension Plan and the Chesapeake SERP related to the retirement of our former Chief Executive Officer, who retired in January 2011. Actuarial assumptions affecting 2011 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 5.00 percent and 5.25 percent for Chesapeake’s plans and FPU’s plans, respectively. The discount rate for each plan was determined by management considering high quality corporate bond rates based on Moody’s Aa bond index, the Citigroup yield curve, changes in those rates from the prior year, and other pertinent factors, such as the expected lives of the plans and 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 increase in the discount rate could decrease our pension and postretirement costs by approximately $98,000 and a decrease of 0.25 percent could increase our pension and postretirement costs by $123,000. A 0.25 percent increase in the rate of return would decrease our pension cost by approximately $112,000, and a decrease of 0.25 percent could increase our pension cost by approximately $117,000 and will not have an impact on postretirement and SERP plans because these plans are not funded.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 37


Table of Contents

Management’s Discussion and Analysis
Acquisition Accounting
The merger with FPU and other acquisitions were accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in the merger be recognized at their fair value as of the acquisition date. It also establishes that the consideration transferred be measured at the closing date of the merger at the then-current market price. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability and fair value measures for an asset assume the highest and best use by those market participants, rather than our intended use of those assets. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature of the assets and liabilities and the regulatory mechanism for recovery, to which these assets and liabilities are subject, as a factor in determining their appropriate fair value. We also considered the existence of a regulatory process that would allow, or sometimes require, regulatory assets and liabilities to be established to offset the fair value adjustment to certain assets and liabilities subject to rate regulation. If a regulatory asset or liability should be established to offset the fair value adjustment based on the current regulatory process, as was the case for fuel contracts and long-term debt, we did not “gross-up” our balance sheet to reflect the fair value adjustment and corresponding regulatory asset/liability, because such “gross-up” would not have resulted in a change to our value of net assets and future earnings.
The acquisition method of accounting also requires acquisition-related costs to be expensed in the period in which those costs are incurred, rather than including them as a component of consideration transferred. It also prohibits an accrual of certain restructuring costs at the time of the merger for the acquiree. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining proper accounting treatment for the merger-related costs. We deferred a certain portion of the total costs incurred as a regulatory asset, which represents our best estimate of the costs, which we expect to be permitted to recover when we complete the appropriate rate proceedings based on similar proceedings in Florida in the past. The remaining costs have been expensed.
(d)  
Results of Operations
(in thousands except per share)
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
Business Segment:
                                               
Regulated Energy
  $ 43,509     $ 26,900     $ 16,609     $ 26,900     $ 24,733     $ 2,167  
Unregulated Energy
    7,908       8,158       (250 )     8,158       3,781       4,377  
Other
    513       (1,322 )     1,835       (1,322 )     (35 )     (1,287 )
 
                                   
Operating Income
    51,930       33,736       18,194       33,736       28,479       5,257  
 
                                               
Other Income
    195       165       30       165       103       62  
Interest Charges
    9,146       7,086       2,060       7,086       6,158       928  
Income Taxes
    16,923       10,918       6,005       10,918       8,817       2,101  
 
                                   
Net Income
  $ 26,056     $ 15,897     $ 10,159     $ 15,897     $ 13,607     $ 2,290  
 
                                   
 
                                               
Earnings Per Share of Common Stock
                                               
Basic
  $ 2.75     $ 2.17     $ 0.58     $ 2.17     $ 2.00     $ 0.17  
Diluted
  $ 2.73     $ 2.15     $ 0.58     $ 2.15     $ 1.98     $ 0.17  

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 38


Table of Contents

Management’s Discussion and Analysis
2010 compared to 2009
Our net income increased by approximately $10.2 million, or $0.58 per share (diluted) in 2010, compared to 2009. Chesapeake’s legacy businesses, which exclude the FPU business and merger-related costs, generated an increase in net income of $1.9 million, or $0.24 per share (diluted) in 2010. The $0.24 per share increase in diluted earnings per share by Chesapeake’s legacy businesses in 2010, which is calculated based on weighted average common shares outstanding, exclusive of the shares issued in the FPU merger, represents 11-percent growth from 2009. Continued growth and expansions of our natural gas distribution and transmission businesses and propane distribution business on the Delmarva Peninsula, the rate increase in Chesapeake’s Florida natural gas distribution division, favorable weather impact and improved results in our advanced information services business contributed to this increase. These increases were partially offset by a decline in earnings from our natural gas marketing business, due primarily to the absence of spot sales to one industrial customer, and our propane wholesale marketing business. FPU’s results, which have been included in our consolidated results since the completion of the merger on October 28, 2009, added $7.5 million to our consolidated net income in 2010, which generated an increase of $0.22 per share (diluted) in 2010. A decrease in FPU merger-related costs also added $0.12 per share (diluted) to the increase in 2010.
The following table illustrates the effect of the merger on our results for the year ended December 31, 2010 and December 31, 2009.
                                                 
    2010     2009  
    Chesapeake,             Chesapeake     Chesapeake,             Chesapeake  
For the Years Ended December 31,   excluding FPU     FPU     Total     excluding FPU     FPU(1)     Total  
(in thousands)
                                               
 
Operating Income (Loss)
                                               
Regulated Energy
  $ 26,711     $ 16,798     $ 43,509     $ 23,908     $ 2,992     $ 26,900  
Unregulated Energy
    6,335       1,573       7,908       7,605       553       8,158  
Other, including merger-related costs
    513             513       (1,322 )           (1,322 )
 
                                   
Operating Income
    33,559       18,371       51,930       30,191       3,545       33,736  
 
                                               
Other Income, net of expenses
    48       147       195       58       107       165  
Interest Charges
    5,752       3,394       9,146       6,345       741       7,086  
Income Taxes
    11,138       5,785       16,923       9,836       1,082       10,918  
 
                                   
Net Income
  $ 16,717     $ 9,339     $ 26,056     $ 14,068     $ 1,829     $ 15,897  
 
                                   
     
(1)  
FPU operating results are for the period from the merger closing (October 28, 2009) to December 31, 2009
2009 compared to 2008
Our net income increased by approximately $2.3 million, or $0.17 per share (diluted), in 2009, compared to 2008. Excluding FPU’s results and the merger-related costs, Chesapeake’s legacy businesses generated an increase in net income of $1.0 million, or $0.12 per share (diluted) in 2009. This increase in the diluted earnings per share, which is calculated based on weighted average common shares outstanding, exclusive of the shares issued in the FPU merger, represents five-percent growth in 2009. Continued growth and expansions in our natural gas distribution and transmission businesses on the Delmarva Peninsula, and increased retail margins in the propane distribution business, favorable weather impact and spot sale opportunities by our natural gas marketing business contributed to this increase. FPU’s net income included in our consolidated results in 2009, which represents its net income since the completion of the merger, was $1.8 million, generating an additional $0.12 per share (diluted).

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 39


Table of Contents

Management’s Discussion and Analysis
The following table illustrates the effect of the merger on our results for the year ended December 31, 2009 and the results in 2008.
                                                 
    2009     2008  
    Chesapeake,             Chesapeake     Chesapeake,             Chesapeake  
For the Years Ended December 31,   excluding FPU     FPU(1)     Total     excluding FPU     FPU     Total  
(in thousands)
                                               
 
Operating Income (Loss)
                                               
Regulated Energy
  $ 23,908     $ 2,992     $ 26,900     $ 24,733     $ 0     $ 24,733  
Unregulated Energy
    7,605       553       8,158       3,781             3,781  
Other
    (1,322 )           (1,322 )     (35 )           (35 )
 
                                   
Operating Income
    30,191       3,545       33,736       28,479       0       28,479  
 
                                               
Other Income, net of expenses
    58       107       165       103             103  
Interest Charges
    6,345       741       7,086       6,158             6,158  
Income Taxes
    9,836       1,082       10,918       8,817             8,817  
 
                                   
Net Income
  $ 14,068     $ 1,829     $ 15,897     $ 13,607     $ 0     $ 13,607  
 
                                   
     
(1)  
FPU operating results are for the period from the merger closing (October 28, 2009) to December 31, 2009

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 40


Table of Contents

Management’s Discussion and Analysis
Regulated Energy
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
(in thousands)
                                               
 
                                               
Revenue
  $ 269,934     $ 139,099     $ 130,835     $ 139,099     $ 116,468     $ 22,631  
Cost of sales
    144,217       64,803       79,414       64,803       54,789       10,014  
 
                                   
Gross margin
    125,717       74,296       51,421       74,296       61,679       12,617  
 
Operations & maintenance
    56,338       32,569       23,769       32,569       25,369       7,200  
Depreciation & amortization
    17,038       8,866       8,172       8,866       6,694       2,172  
Other taxes
    8,832       5,961       2,871       5,961       4,883       1,078  
 
                                   
Other operating expenses
    82,208       47,396       34,812       47,396       36,946       10,450  
 
                                   
Operating Income
  $ 43,509     $ 26,900     $ 16,609     $ 26,900     $ 24,733     $ 2,167  
 
                                   
Weather and Customer Analysis
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
Delmarva Peninsula
                                               
Actual HDD
    4,831       4,729       102       4,729       4,431       298  
10-year average HDD
    4,528       4,462       66       4,462       4,401       61  
 
                                               
Estimated gross margin per HDD
  $ 1,995     $ 2,429     $ (434 )   $ 2,429     $ 1,937     $ 492  
 
Florida
                                               
Actual HDD
    1,501       911       590       911       851       60  
10-year average HDD
    919       863       56       863       848       15  
 
                                               
Actual CDD
    2,859       2,770       89       2,770       2,553       217  
10-year average CDD
    2,718       2,694       24       2,694       2,687       7  
 
Average number of residential customers
                                               
Delmarva natural gas distribution
    47,638       46,717       921       46,717       45,570       1,147  
Florida natural gas distribution(1)
    61,053       60,048       1,005       60,048       13,373       46,675  
Florida electric distribution (1)
    23,589       23,679       (90 )     23,679             23,679  
 
                                   
Total
    132,280       130,444       1,836       130,444       58,943       71,501  
 
                                   
     
(1)  
Average number of residential customers for FPU are included in 2010 and 2009.
2010 Compared to 2009
Operating income for the regulated energy segment increased by approximately $16.6 million, or 62 percent, in 2010, compared to 2009, which was generated from a gross margin increase of $51.4 million, offset partially by an operating expense increase of $34.8 million. Our 2010 results include 12 months of FPU’s results, whereas 2009 includes only two months.
Gross Margin
Gross margin for our regulated energy segment increased by $51.4 million, or 69 percent. Of the $51.4 million increase, Chesapeake’s legacy regulated energy businesses generated $5.2 million of the increase, or 10 percent. FPU’s natural gas and electric distribution operations contributed $46.2 million of this increase. FPU’s results in 2009 have been included in our results since the completion of the merger on October 28, 2009. Our results for 2010 included FPU’s results for the full year.

 

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Management’s Discussion and Analysis
The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross margin of $1.4 million in 2010. The factors contributing to this increase were as follows:
   
$1.1 million of the gross margin increase was a result of a two-percent increase in residential customers as well as additional growth in commercial and industrial customers on the Delmarva Peninsula. Residential, commercial and industrial growth by our Delaware division generated $525,000, $163,000 and $313,000, respectively, of the gross margin increase, and the customer growth by our Maryland division contributed $97,000 to the gross margin increase. In 2010, our Delmarva natural gas distribution operations also added 10 large commercial and industrial customers with total expected annualized margin of $748,000, of which $196,000 has been reflected in 2010’s results. The addition of certain industrial customers in 2010 also positioned us to further extend our natural gas distribution and transmission infrastructure in southern Delaware to serve other potential customers in the same area.
 
   
Colder weather on the Delmarva Peninsula generated an additional $365,000 to gross margin as heating degree-days increased by 102, or two percent, in 2010, compared to 2009. This increased gross margin is primarily related to our Delaware division, as residential heating rates for our Maryland division are weather-normalized, and we typically do not experience an impact on gross margin from the weather for our residential customers in Maryland.
 
   
A decline in non-weather-related customer consumption, primarily by residential customers of our Delaware division, decreased gross margin by $111,000.
Our Florida natural gas distribution operations experienced an increase in gross margin of $33.5 million in 2010. The factors contributing to this increase were as follows:
   
FPU’s natural gas distribution operation generated $37.1 million in gross margin for 2010, which includes $148,000 of gross margin generated by the purchase of operating assets from IGC whose operating assets were purchased by FPU on August 9, 2010. Included in gross margin from FPU’s natural gas distribution operation in 2009 was $6.4 million. Gross margin from FPU’s natural gas distribution operation in 2010 was positively affected by an annual rate increase of approximately $8.0 million, effective January 14, 2010, colder temperatures in Florida and growth in commercial and industrial customers. Included in gross margin from FPU’s natural gas distribution operation was the impact of a $750,000 accrual related to the regulatory risk associated with its earnings, merger benefits and recovery of purchase premium. FPU is required to detail known benefits, synergies, cost savings and cost increases resulting from the merger and present the information in the “come-back” filing to the Florida PSC by April 29, 2011 (within 18 months of the merger). We are currently in discussions with the Office of Public Counsel and the Florida PSC staff regarding the benefits and cost savings of the merger, current and expected earnings levels as well as the recovery of approximately $34.9 million in purchase premium and $2.2 million in merger-related costs. We recorded this accrual based on our assessment of FPU’s current earnings, the regulatory environment in Florida and progress of the current discussions.
 
   
Gross margin from Chesapeake’s Florida division increased by $2.9 million, primarily as a result of an annual rate increase of approximately $2.5 million, which became effective on January 14, 2010. The colder temperatures in 2010 also generated an additional $247,000 in gross margin in 2010, compared to 2009.

 

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Management’s Discussion and Analysis
The natural gas transmission operations achieved gross margin growth of $952,000 in 2010. The factors contributing to this increase were as follows:
   
New transportation services implemented by ESNG in November 2009, May 2010 and November 2010 as a result of its system expansion projects generated an additional $1.1 million to gross margin in 2010, compared to 2009. These expansion projects added 9,623 Mcfs of service per day with estimated annual gross margin of $1.6 million, of which $1.2 million has been reflected in 2010’s results.
 
   
New firm transportation service for an industrial customer for the period from November 2009 to October 2012 provided an additional 9,662 Mcfs per day for the period January 1, 2010 through February 5, 2010, and an additional 2,705 Mcfs per day for the period February 6, 2010 through October 31, 2010. These new services added $329,000 to gross margin for 2010. Partially offsetting the additional gross margin generated by this new firm transportation service was the margin of $232,000 in 2009 from the temporary interruptible service provided to the same customer. This temporary increase in service did not occur in 2010.
 
   
ESNG changed its rates effective April 2009 to recover specific project costs in accordance with the terms of precedent agreements with certain customers. These rates generated $508,000 and $381,000 in gross margin in 2010 and 2009, respectively. ESNG and the customers agreed to shorten the recovery period, starting in March 2011.
 
   
Offsetting the foregoing increases to gross margin, ESNG received notices from two customers of their intentions not to renew their firm transportation service contracts, which expired in November 2009 and April 2010, decreasing gross margin by $341,000 for 2010.
 
   
Although not affecting our results in 2010, ESNG completed the eight-mile mainline extension in December 2010 to interconnect with the TETLP pipeline. ESNG commenced its new transportation services to Chesapeake’s Delaware and Maryland divisions in January 2011. These new services have a three-year phase-in from 19,324 Mcfs per day to 38,647 Mcfs per day, providing estimated gross margin of $2.4 million in 2011, $3.9 million in 2012 and $4.3 million thereafter.
Our Florida electric distribution operation, which was acquired in the FPU merger, generated gross margin of $18.4 million in 2010, compared to $2.8 million in gross margin generated in 2009. FPU’s results in 2009 were included in our results only after the completion of the merger in 2009. Gross margin from our electric distribution operation was positively affected by colder temperatures in the winter months and warmer temperatures in the summer months in 2010.
Other Operating Expenses
Other operating expenses for the regulated energy segment increased by $34.8 million, or 73 percent, in 2010, of which $32.4 million was related to other operating expenses of FPU. The remaining increase of $2.4 million or a five percent increase from other operating expenses in 2009, exclusive of other operating expenses of FPU, was due primarily to the following factors:
   
Payroll and benefits increased by $705,000 due primarily to annual salary increases and incentive pay as a result of improved performance.
 
   
Depreciation and asset removal costs increased by $518,000 as a result of our increased capital investments made in 2010 and 2009 to support growth.
 
   
Regulatory expenses increased by $349,000 due primarily to costs associated with ESNG’s recent rate case filing and ongoing regulatory discussions involving the merger impact and recovery of the purchase premium in Florida.
 
   
Non-income-taxes increased by $63,000 due primarily to increased gross receipt tax.

 

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Table of Contents

Management’s Discussion and Analysis
2009 Compared to 2008
Operating income for the regulated energy segment increased by approximately $2.2 million, or nine percent, in 2009, compared to 2008, which was generated from a gross margin increase of $12.6 million, offset partially by an operating expense increase of $10.4 million.
Gross Margin
Gross margin for our regulated energy segment increased by $12.6 million, or 20 percent. FPU’s natural gas and electric distribution operations had $9.2 million in gross margin for the period from the merger closing (October 28, 2009) to December 31, 2009, which contributed to this increase.
The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross margin of $1.3 million in 2009. The factors contributing to this increase were as follows:
   
The Delmarva natural gas distribution operations experienced growth in residential, commercial, and industrial customers, which contributed $471,000, $149,000 and $589,000, respectively, to the gross margin increase, in spite of the continued slowdown in the new housing construction and industrial growth in the region. A two-percent residential customer growth experienced by the Delmarva natural gas distribution operation in 2009 was lower than the growth experienced in recent years.
 
   
Colder weather on the Delmarva Peninsula contributed $449,000 to the increased gross margin, as HDD increased by 298, or seven percent, compared to 2008.
 
   
The Delaware division’s new rate structure allows collection of miscellaneous service fees of $256,000, which, although not representing additional revenue, were previously offset against other operating expenses.
 
   
Interruptible sales to industrial customers decreased in 2009 due to a reduction in the price of alternative fuels, which reduced gross margin by $355,000.
 
   
Non-weather related customer consumption decreased in 2009, which reduced gross margin by $187,000.
Chesapeake’s Florida natural gas distribution operation experienced a decrease in gross margin of $333,000, in 2009. This decrease was attributable to reduced consumption by residential and non-residential customers and the loss of three industrial customers, one in 2008 and two in 2009, due to adverse economic conditions in the region. This decrease was partially offset by an increase in gross margin of $99,000 due to implementation of interim natural gas rates in the third quarter of 2009.
The natural gas transmission operations achieved gross margin growth of $2.5 million in 2009. The factors contributing to this increase were as follows:
   
New long-term transmission services implemented by ESNG in November of 2008 and 2009, which provided for an additional 5,459 Mcfs per day and 3,976 Mcfs per day, respectively, added $939,000 to gross margin in 2009.
 
   
New firm transmission services provided to an industrial customer for the period of February 6, 2009 through October 31, 2009, provided for an additional 6,957 Mcfs per day and added $574,000 to gross margin. In addition, ESNG entered into two additional firm transmission service agreements with this customer for: (1) 6,006 Mcfs per day from November 1, 2009 through November 30, 2009, which added $56,000 to gross margin for 2009; and (2) 9,662 Mcfs per day from November 1, 2009 through October 31, 2012, which added $181,000 to gross margin in 2009. These services generate annual gross margin of $1.1 million.
 
   
In April 2009, ESNG changed its rates to recover specific project costs in accordance with the terms of precedent agreements with certain customers. These new rates generated $381,000 in gross margin for 2009 and will contribute $516,000 annually thereafter for a period of 20 years.
 
   
During January 2009, PIPECO, our intrastate pipeline subsidiary in Florida, began to provide natural gas transmission service to a customer under a 20-year contract. This agreement contributed $264,000 to gross margin in 2009.

 

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Table of Contents

Management’s Discussion and Analysis
Other Operating Expenses
Other operating expenses for the regulated energy segment increased by $10.4 million, of which $6.2 million was related to other operating expenses of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009. The remaining increase in other operating expenses was due primarily to the following factors:
   
Depreciation expense, asset removal costs and property taxes, collectively, increased by approximately $1.4 million as a result of our continued capital investments to support customer growth. Depreciation expense for 2008 also includes a $305,000 depreciation credit as a result of the Delaware negotiated rate settlement agreement in the third quarter of 2008, of which $295,000 was related to depreciation for the months of October through December 2007.
 
   
Salaries and incentive compensation increased by $803,000, due primarily to compensation adjustments implemented on January 1, 2009 for non-executive employees, based on a compensation survey completed in the fourth quarter of 2008, and annual salary increases, coupled with a slight increase in the accrual for incentive compensation.
 
   
The allowance for uncollectible accounts in the natural gas operation increased by $176,000 due to growth in customers and the general economic climate.
 
   
Benefit costs increased by $373,000, due primarily to higher pension costs as a result of the decline in the value of pension assets in 2008 and other benefit costs relating to increased payroll costs.
 
   
Increased information technology spending to continuously enhance our information technology infrastructure and level of support generated increased costs of $285,000.
 
   
Corporate overhead allocated to the regulated energy segment increased by approximately $722,000 due to the overall increase in corporate overhead costs. This increase was related primarily to increased payroll and benefits and increased costs associated with investor relations and financial reporting activities.
Unregulated Energy
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
(in thousands)
                                               
 
                                               
Revenue
  $ 146,793     $ 119,973     $ 26,820     $ 119,973     $ 161,290     $ (41,317 )
Cost of sales
    110,680       90,408       20,272       90,408       138,302       (47,894 )
 
                                   
Gross margin
    36,113       29,565       6,548       29,565       22,988       6,577  
 
                                               
Operations & maintenance
    23,140       18,016       5,124       18,016       16,322       1,694  
Depreciation & amortization
    3,433       2,415       1,018       2,415       2,024       391  
Other taxes
    1,632       976       656       976       861       115  
 
                                   
Other operating expenses
    28,205       21,407       6,798       21,407       19,207       2,200  
 
                                   
Operating Income
  $ 7,908     $ 8,158     $ (250 )   $ 8,158     $ 3,781     $ 4,377  
 
                                   
Weather Analysis — Delmarva
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
 
Actual HDD
    4,831       4,729       102       4,729       4,431       298  
10-year average HDD
    4,528       4,462       66       4,462       4,401       61  
 
                                               
Estimated gross margin per HDD
  $ 2,415     $ 3,083     $ (668 )   $ 3,083     $ 2,465     $ 618  

 

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Table of Contents

Management’s Discussion and Analysis
2010 Compared to 2009
Operating income for the unregulated energy segment decreased by approximately $250,000, or three percent, in 2010 compared to 2009, which was attributable to an increase in gross margin of $6.5 million, offset by an increase in other operating expenses of $6.8 million. A decline in operating income for the unregulated energy segment is largely attributable to the natural gas marketing business, which experienced a decrease in gross margin due primarily to the absence of spot sales to one industrial customer.
Gross Margin
Gross margin for our unregulated energy segment increased by $6.5 million, or 22 percent, for 2010, compared to the same period in 2009.
Our Delmarva propane distribution operation generated a gross margin increase of $1.0 million, as a result of the following factors:
   
Retail volumes sold increased by 1.6 million gallons, or seven percent, in 2010, which generated additional gross margin of $1.1 million. The addition of 436 community gas system customers and 1,000 other customers acquired in February 2010 as part of the purchase of the operating assets of a propane distributor serving Northampton and Accomack Counties in Virginia contributed approximately 38% of this increase. The two-percent colder weather in 2010, compared to 2009, generated additional margin of $314,000. Timing of propane deliveries to our bulk customers contributed to the remaining increase in gross margin due to an increase in retail volumes.
 
   
Other fees increased by $340,000 in 2010 driven by increased customer participation in various customer pricing programs.
 
   
Retail margin per gallon decreased in 2010, compared to 2009, and decreased gross margin by $399,000. Retail margin during the first half of 2009 benefited from the inventory valuation adjustment recorded in late 2008 which lowered the propane inventory costs and, therefore, increased retail margins during the first half of 2009. Retail margins for the second half of 2010 returned to more normal levels. Retail margins in the second half of 2010 increased from the same period in 2009, partially offsetting the impact of the decrease in the first half of the year.
Our Florida propane distribution operation generated $9.4 million in 2010, compared to $3.2 million in 2009. The 2009 results include FPU’s results for the two months after the completion of the merger. Also included in the gross margin increase for 2010 was approximately $767,000 in increased merchandise sales from FPU.
Gross margin for Xeron, our propane wholesale marketing operation, decreased by $441,000 in 2010 compared to 2009. Xeron’s trading volumes decreased by 13 percent in 2010 compared to 2009.
In 2010, gross margin for our unregulated natural gas marketing subsidiary, PESCO, decreased by $1.0 million. In 2009, PESCO benefited from increased spot sales on the Delmarva Peninsula. Spot sales decreased in 2010, due primarily to one industrial customer. Spot sales are not predictable and, therefore, are not included in our long-term financial plans or forecasts.
Other Operating Expenses
Total other operating expenses for the unregulated energy segment increased by $6.8 million in 2010. The Florida distribution operation and FPU’s merchandise activities contributed $6.0 million to this increase. Included in other operating expenses for the Florida propane distribution operation in 2010 was approximately $370,000 expensed in the third and fourth quarters of 2010 for the settlement of a class action complaint (See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note Q, “Other Commitments and Contingencies”). The remaining increase of $771,000 in other operating expenses was due primarily to increased payroll and benefit costs, higher non-income taxes due to increased sales taxes and increased propane delivery costs, partially offset by a decrease in bad debt expenses as a result of expanded credit and collection initiatives by PESCO.

 

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Table of Contents

Management’s Discussion and Analysis
2009 compared to 2008
Operating income for the unregulated energy segment increased by approximately $4.4 million in 2009 compared to 2008, which was attributable to a gross margin increase of $6.6 million, offset partially by an operating expense increase of $2.2 million.
Gross Margin
Gross margin for our unregulated energy segment increased by $6.6 million, or 29 percent, in 2009 compared to 2008. FPU’s propane distribution operation contributed $1.8 million to gross margin during the period from the merger closing (October 28, 2009) to December 31, 2009.
PESCO, our natural gas marketing operation, experienced an increase in gross margin of $1.0 million in 2009. PESCO increased its sales volumes by 13 percent in 2009 compared to 2008, as it benefited from increased spot sale opportunities on the Delmarva Peninsula during 2009, which contributed significantly to the gross margin increase. Spot sales are opportunistic and unpredictable, and their future availability is highly dependent upon market conditions.
The propane distribution operation, excluding FPU, increased its gross margin by $4.8 million. The absence of inventory valuation adjustments in 2009 and lower propane costs, coupled with sustained retail prices, contributed $3.5 million of the gross margin increase. A sharp decline in propane prices in late 2008 resulted in a loss associated with the inventory and swap valuation adjustments of $1.8 million in 2008. These inventory adjustments in 2008 and relatively low propane prices during the first half of 2009 enabled the Delmarva propane distribution operation to keep its propane cost low. Colder weather on the Delmarva Peninsula in 2009 increased gross margin by $1.2 million, as temperatures were seven percent colder in 2009, compared to 2008. Gross margin for the Florida propane distribution operation in 2009 remained unchanged from 2008 as increased margins per retail gallon were offset by a decline in residential and non-residential consumption.
The propane wholesale marketing operation experienced a reduction in gross margin of $1.0 million in 2009. The propane wholesale marketing operation typically capitalizes on price volatility by selling at prices above cost and effectively managing the larger spreads between the market (spot) prices and forward prices. Overall lack of volatility in wholesale propane prices in 2009, compared to 2008, reduced such revenue opportunities and its trading volume by 57 percent.
Other Operating Expenses
Total other operating expenses for the unregulated energy segment increased by $2.2 million in 2009, of which $1.2 million was related to other operating expenses of FPU during the period from the merger closing (October 28, 2009) to December 31, 2009. The remaining increase in other operating expenses was due primarily to the following factors:
   
Payroll costs increased by $301,000 in 2009 compared to 2008 due to annual salary increases.
 
   
Benefit costs increased by $167,000, due primarily to increased pension costs in 2009 as a result of the decline in the value of pension plan assets.
 
   
Depreciation expense increased by $249,000 as we continued to make capital investments in the propane distribution operations.
 
   
Additional costs of approximately $115,000 were incurred in 2009 to maintain propane tanks.
 
   
Corporate overhead costs allocated to the unregulated energy segment increased by approximately $568,000 due to the overall increase in administrative payroll and benefits and increased costs associated with investor relations and financial reporting activities.
 
   
These increases were partially offset by lower vehicle-related costs of $176,000, due primarily to a decrease in the cost of fuel.

 

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Table of Contents

Management’s Discussion and Analysis
Other
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2010     2009     (decrease)     2009     2008     (decrease)  
(in thousands)
                                               
 
                                               
Revenue
  $ 13,142     $ 11,998     $ 1,144     $ 11,998     $ 15,373     $ (3,375 )
Cost of sales
    6,316       6,036       280       6,036       8,034       (1,998 )
 
                                   
Gross margin
    6,826       5,962       864       5,962       7,339       (1,377 )
 
                                               
Operations & maintenance
    4,766       4,859       (93 )     4,859       5,206       (347 )
Transaction-related costs
    660       1,478       (818 )     1,478       1,153       325  
Depreciation & amortization
    289       310       (21 )     310       290       20  
Other taxes
    600       640       (40 )     640       728       (88 )
 
                                   
Other operating expenses
    6,315       7,287       (972 )     7,287       7,377       (90 )
 
                                               
Operating Income — Other
    511       (1,325 )     1,836       (1,325 )     (38 )     (1,287 )
Operating Income — Eliminations
    2       3       (1 )     3       3        
 
                                   
Operating Income
  $ 513     $ (1,322 )     1,835     $ (1,322 )   $ (35 )   $ (1,287 )
 
                                   
2010 Compared to 2009
Operating income for the “Other” segment increased by approximately $1.8 million in 2010, compared to 2009. The increase in operating income was attributable to a gross margin increase of $864,000 and a $972,000 decrease in operating expenses.
Gross margin
The period-over-period increase in gross margin of $864,000 for our “Other” segment was generated by our advanced information services subsidiary’s increase in revenue and gross margin from its professional database monitoring and support solution services and higher consulting revenues as a result of a seven-percent increase in the number of billable consulting hours in 2010 compared to 2009.
Operating expenses
Other operating expenses decreased by $972,000 in 2010 compared to 2009. The decrease in operating expenses was attributable primarily to an $818,000 decrease in merger-related costs expensed in 2010 compared to 2009.
2009 compared to 2008
Operating loss for the “Other” segment increased by approximately $1.3 million in 2009 compared to 2008. The increased loss was attributable primarily to the gross margin decrease of $1.4 million in the advanced information services operation.
Gross margin
The period-over-period decrease in gross margin for the “Other” segment was a result of a decrease in consulting revenues by the advanced information services subsidiary due primarily to a 28-percent decrease in the number of billable consulting hours, coupled with a decline in training revenues. The reduction in the number of billable consulting hours was a result of economic conditions. The decrease in consulting revenues was partially offset by an increase of $218,000 from BravePoint’s professional database monitoring and support solution services, and increased product sales of $140,000.

 

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Table of Contents

Management’s Discussion and Analysis
Operating expenses
Other operating expenses decreased by $90,000 in 2009. The decrease in operating expenses was attributable primarily to the cost containment actions, including layoffs and compensation adjustments, implemented by the advanced information services subsidiary in 2009 to reduce costs to offset the decline in revenues. This decrease was offset by the increased merger-related costs.
Other Income
Other income for 2010, 2009 and 2008 was $195,000, $165,000, and $103,000, respectively, which includes interest income, late fees charged to customers and gains or losses from the sale of assets.
Interest Expense
2010 Compared to 2009
Our total interest expense for 2010 increased by approximately $2.1 million, or 29 percent, compared to 2009. The primary drivers of the increased interest expense were related to FPU, including:
   
An increase in long-term interest expense of $1.3 million was related to interest on FPU’s first mortgage bonds.
 
   
Interest expense from a new term loan credit facility during 2010 was $491,000. In January 2010, we redeemed two series of FPU bonds, the 4.9 percent and 6.85 percent series, to achieve interest savings and to maintain compliance with the covenants in our unsecured senior notes. We used $29.1 million of the new term loan facility for the redemptions.
 
   
Additional interest expense of $730,000 is related to interest on deposits from FPU’s customers.
Offsetting the increased interest expense from FPU was lower non-FPU-related interest expense from Chesapeake’s unsecured senior notes, as the principal balances decreased from scheduled payments, and lower additional short-term borrowings as a result of the timing of our capital expenditures and reduced working capital requirements, partially due to the increased bonus depreciation in 2010.
2009 Compared to 2008
Total interest expense for 2009 increased by approximately $928,000, or 15 percent, compared to 2008. Total interest expense for 2009 includes approximately $741,000 in FPU’s interest expense for the period from the merger closing (October 28, 2009) to December 31, 2009, which was primarily related to $610,000 in interest on FPU’s long-term debt and $115,000 in interest on customer deposits. FPU’s weighted average interest rate was 7.41 percent for the period from the merger closing to December 31, 2009.
The remaining increase in interest expense in 2009 was attributable to the following factors:
   
Excluding FPU’s long-term debt, interest expense on long-term debt increased by $990,000 as our average long-term debt balance increased to $92.1 million in 2009 from $76.2 million in 2008. This increase was primarily related to the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008. The weighted average interest rate on our long-term debt remained fairly constant at 6.37 percent in 2009, compared to 6.40 percent in 2008.
 
   
Interest expense on short-term borrowings decreased by $852,000 in 2009, compared to 2008, as our average short-term borrowing balance decreased to $13.0 million in 2009 from $38.3 million in 2008. The $30.0 million long-term placement in October 2008 contributed to this decrease in addition to a decline in working capital requirements in 2009, due to lower capital expenditures, lower income tax payments from bonus depreciation, net tax operating losses carried forward from 2008 and lower commodity costs. The impact from these factors was offset slightly by increased working capital needs as a result of the FPU merger. Also contributing to the decrease in interest expense in short-term borrowings was a decrease in the weighted average short-term interest rate to 1.28 percent in 2009 from 2.79 percent in 2008 as we continued to experience low interest rates throughout 2009.
 
   
Other interest charges increased by $49,000.

 

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Table of Contents

Management’s Discussion and Analysis
Income Taxes
2010 Compared to 2009
Income tax expense was $16.9 million in 2010, compared to $10.9 million in 2009, representing an increase of $6.0 million, as a result of increased taxable income in 2010. During 2009, we expensed approximately $871,000 in merger-related costs that we determined to be non-deductible for income tax purposes. Excluding the impact of these costs, our effective income tax rate for 2010 and 2009 remained unchanged at 39.4 percent.
2009 Compared to 2008
Income tax expense was $10.9 million in 2009, compared to $8.8 million in 2008, representing an increase of $2.1 million. During 2009, we expensed approximately $871,000 in merger-related costs that we determined to be non-deductible for income tax purposes. Excluding the impact of these costs, our effective income tax rate for 2009 and 2008 remained primarily unchanged at 39.4 percent and 39.3 percent, respectively. The increase in income tax expense reflects the increased taxable income in 2009.
(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 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 and propane delivered by our natural gas 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 are one of our largest capital requirements. During 2010, our capital expenditures increased to $47.0 million, from $26.3 million and $30.8 million in 2009 and 2008, respectively, as a result of continued expansions of our natural gas distribution and transmission systems as well as capital expenditures for FPU of $10.9 million and $1.6 million included in our capital expenditures in 2010 and 2009 since the completion of the merger. We have budgeted $51.7 million for capital expenditures during 2011. This amount includes $43.6 million for the regulated energy segment, $3.7 million for the unregulated energy segment and $4.4 million for the “Other” segment. The amount for the regulated energy segment includes estimated capital expenditures for the following: natural gas distribution operation ($25.4 million), natural gas transmission operation ($12.5 million) and electric distribution operation ($5.7 million) for expansion and improvement of facilities. The amount for the unregulated energy segment includes estimated capital expenditures for the propane distribution operations for customer growth and replacement of equipment. The amount for the “Other” segment includes estimated capital expenditures of $245,000 for the advanced information services subsidiary with the remaining balance for other general plant, computer software and hardware. We expect to fund the 2011 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.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 50


Table of Contents

Management’s Discussion and Analysis
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, 2010 and 2009:
                                 
    December 31,             December 31,          
(in thousands)   2010             2009          
 
                               
Long-term debt, net of current maturities
  $ 89,642       28 %   $ 98,814       32 %
Stockholders’ equity
    226,239       72 %     209,781       68 %
 
                       
Total capitalization, excluding short-term debt
  $ 315,881       100 %   $ 308,595       100 %
 
                       
                                 
    December 31,             December 31,          
(in thousands)   2010             2009          
 
                               
Short-term debt
  $ 63,958       17 %   $ 30,023       8 %
Long-term debt, including current maturities
    98,858       25 %     134,113       36 %
Stockholders’ equity
    226,239       58 %     209,781       56 %
 
                       
Total capitalization, including short-term debt
  $ 389,055       100 %   $ 373,917       100 %
 
                       
In consummating the FPU merger, we issued 2,487,910 shares of Chesapeake common stock, valued at approximately $75.7 million, in exchange for all outstanding common stock of FPU. Our balance sheet at the time of the merger also reflected FPU’s long-term debt of $47.8 million as a result of the merger.
Since the consummation of the merger, we have redeemed $29.1 million of FPU’s long-term debt, which was held in the form of first mortgage bonds. We will be refinancing these redeemed bonds with new Chesapeake unsecured senior notes. We have also entered into an arrangement to refinance an additional $7.0 million of FPU’s first mortgage bonds in 2013 with more competitively priced Chesapeake unsecured senior notes. As a result, only $8.0 million of the original $47.8 million of FPU debt as of the merger will be outstanding by 2013 in the form of secured first mortgage bonds.
As of December 31, 2010, 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, 2010, $52.7 million of Chesapeake’s cumulative consolidated net income and $28.3 million of FPU’s cumulated net income were free of such restrictions.

 

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Table of Contents

Management’s Discussion and Analysis
Short-term Borrowings
Our outstanding short-term borrowings at December 31, 2010 and 2009 were $64.0 million and $30.0 million, respectively, at the weighted average interest rates of 1.77 percent and 1.28 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 fund temporarily portions of the capital expenditure program. As of December 31, 2010, 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 $85.0 million of short-term debt, as required, from these unsecured bank lines of credit.
Our outstanding borrowings under these unsecured bank lines of credit at December 31, 2010 and 2009 were $30.8 million and $30.0 million, respectively. During 2010, 2009 and 2008, the average borrowings from these unsecured bank lines of credit were $10.5 million, $13.0 million and $38.3 million, respectively, at weighted average interest rates of 2.40 percent, 1.28 percent and 2.80 percent, respectively. The maximum month-end borrowings from these unsecured bank lines of credit during 2010, 2009 and 2008 were $64.0 million, $33.0 million and $61.2 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, 2010 was $4.1 million representing outstanding checks in excess of funds in deposit, which if presented would be funded through the bank lines of credit.
In addition to the four unsecured bank lines of credit, we entered into a new credit facility for $29.1 million with an existing lender in March 2010. We borrowed $29.1 million under this new credit facility to finance the early redemption of the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds. The interest rate on the borrowing was fixed at 1.88 percent for nine months and on December 16, 2010 the rate was fixed for three months at 1.55 percent. On November 1, 2010 we extended the maturity of this credit facility from March 15, 2011 until October 31, 2011.
On June 29, 2010, we entered into an agreement with an existing senior note holder to issue up to $36 million in uncollateralized senior notes. We expect to use $29 million of the uncollateralized senior notes to permanently finance the early redemption of the 6.85 percent and 4.90 percent series of FPU bonds previously discussed. If refinanced prior to July 8, 2011, these new uncollateralized senior notes will be issued at 5.68 percent and result in annual long-term interest expense of $1.7 million, representing additional interest of $1.2 million, compared to the interest expense of $491,000 on the new short-term loan facility used in 2010. We also expect to use the remaining $7 million to redeem additional FPU secured first mortgage bonds in 2013.
Cash Flows Provided by Operating Activities
Our cash flows provided by operating activities were as follows:
                         
For the Years Ended December 31,   2010     2009     2008  
Net income
  $ 26,056     $ 15,897     $ 13,607  
Non-cash adjustments to net income
    37,364       28,319       22,919  
Changes in assets and liabilities
    (2,415 )     1,583       (7,982 )
 
                 
Net cash from operating activities
  $ 61,005     $ 45,799     $ 28,544  
 
                 
Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income, depreciation, deferred taxes and working capital. Changes in working capital are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 52


Table of Contents

Management’s Discussion and Analysis
We 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 and propane delivered by our natural gas 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.
In 2010, our net cash flow provided by operating activities was $61.1 million, an increase of $15.3 million compared to 2009. The increase was due primarily to the following:
   
Net cash flows from changes in accounts receivable and accounts payable were due primarily to the inclusion of FPU and timing of collections and payments of trading contracts entered into by our propane wholesale and marketing operation;
 
   
Net income increased by $10.2 million. A full year’s results for FPU and organic growth within Chesapeake’s legacy businesses contributed to this increase;
 
   
Non-cash adjustments to net income increased by $12.4 million due primarily to higher depreciation and amortization, changes in deferred income taxes, higher employee benefits and compensation and an increase in share based compensation. Higher depreciation and amortization was due to the inclusion of FPU and an increase in capital investments. The increase in deferred income taxes was a result of bonus depreciation in 2010, which significantly reduced our income tax payment obligations in 2010; and
 
   
The decrease in income tax receivables was due primarily to the receipt of large refunds in 2009 due to higher tax deductions in 2009 and 2008 and a decrease in taxes payable due to bonus depreciation in 2010.
In 2009, our net cash flow provided by operating activities was $45.8 million, an increase of $17.3 million compared to 2008. The increase was due primarily to the following:
   
Net cash flows from changes in accounts receivable and accounts payable, due primarily to the timing of collections and payments of trading contracts entered into by our propane wholesale and marketing operation;
 
   
Timing of payments for the purchase of propane inventory, natural gas purchases injected into storage, and the relative decline in the unit price of these commodities;
 
   
Reduction in regulatory liabilities, which resulted primarily from lower deferred gas cost recoveries in our natural gas distribution operations as the price of natural gas declined in the second half of 2008;
 
   
Reduced payments for income taxes payable as a result of higher tax deductions provided by the 2008 Economic Stimulus Act; and
 
   
Cash flows provided by non-cash adjustments for deferred income taxes. The increase in deferred income taxes was the result of higher book-to-tax timing differences during the period that were generated by the Economic Stimulus Act, which authorized bonus depreciation for certain assets.

 

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Management’s Discussion and Analysis
Cash Flows Used in Investing Activities
In 2010, net cash flows used by investing activities totaled $48.8 million, an increase of $25.7 million compared to 2009. In 2009, net cash flows used by investing activities totaled $23.1 million, a decrease of $8.1 million compared to 2008.
   
Cash utilized for capital expenditures was $45.4 million, $26.6 million and $30.8 million for 2010, 2009, and 2008, respectively.
 
   
We invested $1.6 million in equity securities and paid $1.2 million and $310,000 for the acquisition of Indiantown Gas Company and Virginia LP, respectively, in 2010.
 
   
In 2009, we received $3.5 million in proceeds from an investment account related to future environmental costs, as we transferred the amount to our general account that invests in overnight income-producing securities. We also acquired $359,000 in cash, net of cash paid, in the FPU merger in 2009.
 
   
Environmental expenditures exceeded amounts recovered through rates charged to customers in 2010, 2009 and 2008 by $290,000, $418,000 and $480,000, respectively.
Cash Flows Provided by/Used in Financing Activities
In 2010 and 2009, net cash flows used by financing activities totaled $13.4 million and $21.4 million, respectively, compared to net cash flows provided by financing activities of $1.7 million in 2008. Significant financing activities included the following:
   
During 2010 we entered into a new term loan with an existing lender and we borrowed $29.1 million under this facility in order to temporarily finance the early redemption of the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds prior to their respective maturity.
 
   
During 2010 we increased our short-term borrowing by $1.6 million primarily to support our capital expenditures. During 2009 and 2008, we reduced our short-term debt by $3.8 million and $12.0 million, respectively.
 
   
We repaid $36.9 million, $10.9 million and $7.7 million of long-term debt during 2010, 2009 and 2008 respectively.
 
   
We paid $11.0 million, $8.0 million and $7.8 million in cash dividends in 2010, 2009 and 2008, respectively. An increase in cash dividends paid in each year reflects the growth in the annualized dividend rate. 2010 also reflects dividends on a larger number of shares outstanding, from the FPU shares that were exchanged for Chesapeake shares in the merger.
 
   
In October 2008, we completed the placement of $30.0 million of 5.93 percent Unsecured Senior Notes.

 

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Management’s Discussion and Analysis
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2010:
                                         
    Payments Due by Period  
Contractual Obligations   Less than 1                     More than 5        
(in thousands)   year     1 - 3 years     3 - 5 years     years     Total  
 
Long-term debt (1)
  $ 9,216     $ 16,393     $ 21,656     $ 51,682     $ 98,947  
Operating leases (2)
    803       1,234       470       2,017       4,524  
 
Purchase obligations (3)
                                       
Transmission capacity
    35,051       59,761       37,949       70,293       203,054  
Storage — Natural Gas
    2,615       4,687       1,525       2,063       10,890  
Commodities
    37,179       100                   37,279  
Electric supply
    1,626       26,498       26,498       39,173       93,795  
Forward purchase contracts — Propane (4)
    15,618                         15,618  
Other
    144       109                   253  
Unfunded benefits (5)
    1,132       731       870       5,706       8,439  
Funded benefits (6)
    2,400       150       108       1,228       3,886  
 
                             
Total Contractual Obligations
  $ 105,784     $ 109,663     $ 89,076     $ 172,162     $ 476,685  
 
                             
     
(1)  
Principal payments on long-term debt, see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note J, Long-Term Debt”, for additional discussion of this item. The expected interest payments on long-term debt are $6.6 million, $11.4 million, $8.6 million and $13.3 million, respectively, for the periods indicated above. Expected interest payments for all periods total $40.0 million.
 
(2)  
See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note L, Lease Obligations,” for additional discussion of this item.
 
(3)  
See Item 8 under the heading “Notes to the Consolidated Financial statement — Note Q, Other Commitments and Contingencies,” in the Notes to the Consolidated Financial Statements for further information.
 
(4)  
We have also entered into forward sale contracts. See “Market Risk” of Management’s Discussion and Analysis for further information.
 
(5)  
We have recorded long-term liabilities of $8.4 million at December 31, 2010 for unfunded post-employment and post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assume a retirement age of 62 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations.
 
(6)  
We have recorded long-term liabilities of $16.3 million at December 31, 2010 for two qualified, defined benefit pension plans. The assets funding these plans are in a separate trust and are not considered assets of the Company or included in the Company’s balance sheets. The Contractual Obligations table above includes $1.5 million, reflecting the expected payments the Company will make to the trust funds in 2011. Additional contributions may be required in future years based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note M, Employee Benefit Plans,” for further information on the plans. Additionally, the Contractual Obligations table includes deferred compensation obligations totaling $2.4 million, funded with Rabbi Trust assets in the same amount. The Rabbi Trust assets are recorded under Investments on the Balance Sheet. We assume a retirement age of 65 for purposes of distribution from this account.
Off-Balance Sheet Arrangements
The Board of Directors has authorized the Company $35 million of corporate guarantees on behalf of our subsidiaries and for letters of credit. As of March 2, 2011, the Board increased this limit from $35 million to $45 million.
We have issued corporate guarantees to certain vendors of our subsidiaries, primarily the propane wholesale marketing subsidiary and the natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2010 was $25.6 million, with the guarantees expiring on various dates in 2011.

 

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Management’s Discussion and Analysis
In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $440,625 which expires on December 2, 2011. The letter of credit is provided as security to satisfy the deductibles under our various insurance outstanding policies. As a result of the recent change in our primary insurance company, we have issued an additional letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2011. There have been no draws on these letters of credit as of December 31, 2010. We do not anticipate that the letters of credit will be drawn upon by the counterparties and we expect that the letters of credit will be renewed to the extent necessary in the future.
We provided a letter of credit for $2.0 million to TETLP related to the Precedent Agreement with TETLP. The letter of credit is expected to increase quarterly as TETLP’s pre-service costs increases. The letter of credit will not exceed the three-month reservation charge under the firm transportation service contracts, which we currently estimate to be $2.1 million.
(f) Rate Filings and Other Regulatory Activities
Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by their respective PSC; ESNG is subject to regulation by the FERC; and PIPECO is subject to regulation by the Florida PSC. At December 31, 2010, Chesapeake was involved in rate filings and/or regulatory matters in each of the jurisdictions in which it operates. Each of these rate filings or regulatory matters is fully described in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note O, Rates and Other Regulatory Activities.”
(g) Environmental Matters
We continue to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at seven environmental sites (see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note P, Environmental Commitments and Contingencies” for further detail on each site). We believe that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.
(h) Market Risk
Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes, secured debt and convertible debentures (see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note J, Long-term Debt” for annual maturities of consolidated long-term debt). All of our long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $98.9 million at December 31, 2010, as compared to a fair value of $113.4 million, based on a discounted cash flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average maturities with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.
Our propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. We can store up to approximately six million gallons (including leased storage and rail cars) of propane during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, we have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of our inventory.
Our propane wholesale marketing operation is a party to natural gas liquids forward contracts, primarily propane contracts, with various third-parties. These contracts require that the propane wholesale marketing operation purchase or sell natural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of natural gas liquids to us or the counterparty or “booking out” the transaction. Booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy. The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane.

 

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Table of Contents

Management’s Discussion and Analysis
The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counterparties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at December 31, 2010 and 2009 is presented in the following tables:
                         
    Quantity in     Estimated Market     Weighted Average  
At December 31, 2010   Gallons     Prices     Contract Prices  
Forward Contracts
                       
Sale
    13,523,496     $1.0350 — $1.4100     $ 1.2192  
Purchase
    12,914,496     $1.0150 — $1.3779     $ 1.2093  
 
                       
Other Contract
                       
Put option
    1,470,000     $—     $ 0.1150  
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire by the end of the second quarter of 2011.
                         
    Quantity in     Estimated Market     Weighted Average  
At December 31, 2009   gallons     Prices     Contract Prices  
Forward Contracts
                       
Sale
    11,944,800     $0.6900 — $1.3350     $ 1.1264  
Purchase
    11,256,000     $0.7275 — $1.3350     $ 1.1367  
 
   
Other Contract
                       
Put option
    1,260,000     $—     $ 0.1500  
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in the first quarter of 2010.
At December 31, 2010 and 2009, we marked these forward and other contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:
                 
    December 31,     December 31,  
(in thousands)   2010     2009  
Mark-to-market energy assets
  $ 1,642     $ 2,379  
Mark-to-market energy liabilities
  $ 1,492     $ 2,514  
Our natural gas distribution, electric distribution and natural gas marketing operations have entered into agreements with natural gas and electricity suppliers to purchase natural gas and electricity for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis.

 

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Management’s Discussion and Analysis
(i) Competition
Our natural gas and electric distribution operations and our natural gas transmission operation compete with other forms of energy including natural gas, electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. Our natural gas distribution operations have several large-volume industrial customers that are able to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements, and our interruptible sales volumes may decline. Oil prices, as well as the prices of other fuels, fluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, we use flexible pricing arrangements on both the supply and sales sides of this business to compete with alternative fuel price fluctuations. As a result of the transmission operation’s conversion to open access and Chesapeake’s Florida natural gas distribution division’s restructuring of its services, these businesses have shifted from providing bundled transportation and sales service to providing only transmission and contract storage services. Our electric distribution operation currently does not face substantial competition as the electric utility industry in Florida has not been deregulated. In addition, natural gas is the only viable alternative fuel to electricity in our electric service territories and is available only in a small area.
Our natural gas distribution operations in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, Chesapeake’s Florida natural gas distribution division, Central Florida Gas, extended such service to residential customers. With such transportation service available on our distribution systems, we are competing with third-party suppliers to sell gas to industrial customers. With respect to unbundled transportation services, our competitors include interstate transmission companies, if the distribution customers are located close enough to a transmission company’s pipeline to make connections economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass our existing distribution operations in this manner. In certain situations, our distribution operations may adjust services and rates for these customers to retain their business. We expect to continue to expand the availability of unbundled transportation service to additional classes of distribution customers in the future. We have also established a natural gas marketing operation in Florida, Delaware and Maryland to provide such service to customers eligible for unbundled transportation services.
Our propane distribution operations compete with several other propane distributors in their respective geographic markets, primarily on the basis of service and price, emphasizing responsive and reliable service. Our competitors generally include local outlets of national distributors and local independent distributors, whose proximity to customers entails lower costs to provide service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas served by natural gas pipeline or distribution systems.
The propane wholesale marketing operation competes against various regional and national marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.
Our advanced information services subsidiary faces significant competition from a number of larger competitors having substantially greater resources available to them than does our subsidiary. In addition, changes in the advanced information services business are occurring rapidly, and could adversely affect the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.

 

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Management’s Discussion and Analysis
(j) Inflation
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the regulated natural gas and electric distribution operations, fluctuations in natural gas and electricity prices are passed on to customers through the fuel cost recovery mechanism in our tariffs. To help cope with the effects of inflation on our capital investments and returns, we seek rate increases from regulatory commissions for our regulated operations and closely monitor the returns of our unregulated business operations. To compensate for fluctuations in propane gas prices, we adjust propane selling prices to the extent allowed by the market.
(k) Marianna Franchise
On March 2, 2011, the City of Marianna, Florida filed a declaratory action against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging that FPU breached its obligations under its franchise with the city to provide electric service to customers within and without the city by failing (i) to develop and implement TOU and interruptible rates that were mutually agreed to by the city and FPU; (ii) to have such mutually agreed upon rates in effect by February 17, 2011; and (iii) to have such rates available to all of FPU’s customers located within and without the corporate limits of the city. The city is seeking a declaratory judgment to exercise its option under the franchise agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Commission which would also need to approve the presentation of a referendum to voters in the City of Marianna for approval of the purchase and the operation by the city of an electric distribution facility. If the purchase is approved by the Commission and the voters in the City of Marianna, the closing of the purchase must occur within 12 months after the referendum is approved. If the purchase occurs, FPU would have a gain in the year of the disposition. Additionally, future financial results would be negatively impacted from the loss in earnings generated by FPU under the franchise agreement, however such impact is anticipated to be immaterial. FPU intends to file a response to the City’s complaint and vigorously contest this litigation and intends to oppose the passage of any proposed referendum that is presented to voters to approve the purchase of the FPU property in the City of Marianna.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 59


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Item 7A.  
Quantitative and Qualitative Disclosures About Market Risk.
Information concerning quantitative and qualitative disclosure about market risk is included in Item 7 under the heading “Management’s Discussion and Analysis — Market Risk.”
Item 8.  
Financial Statements and Supplementary Data.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records which in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, Chesapeake’s management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria established in a report entitled “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
On October 28, 2009, the previously announced merger between Chesapeake and FPU was consummated. FPU’s activity is included in Chesapeake’s 2010 evaluation of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See “Notes to the Consolidated Financial Statements — Note B, Acquisitions” for additional information relating to the FPU merger.
Chesapeake’s management has evaluated and concluded that Chesapeake’s internal control over financial reporting was effective as of December 31, 2010.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 60


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Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 8, 2011 expressed an unqualified opinion.
     
/s/ ParenteBeard LLC
 
ParenteBeard LLC
   
Malvern, Pennsylvania
   
March 8, 2011
   

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 61


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Consolidated Statements of Income
                         
For the Years Ended December 31,   2010     2009     2008  
(in thousands, except shares and per share data)
                       
 
Operating Revenues
                       
Regulated Energy
  $ 269,934     $ 139,099     $ 116,468  
Unregulated Energy
    146,793       119,973       161,290  
Other
    10,819       9,713       13,685  
 
                 
Total operating revenues
    427,546       268,785       291,443  
 
                 
 
                       
Operating Expenses
                       
Regulated energy cost of sales
    144,217       64,803       54,789  
Unregulated energy and other cost of sales
    116,098       95,467       145,854  
Operations
    75,335       50,706       43,476  
Transaction-related costs
    660       1,478       1,153  
Maintenance
    7,484       3,430       2,215  
Depreciation and amortization
    20,758       11,588       9,005  
Other taxes
    11,064       7,577       6,472  
 
                 
Total operating expenses
    375,616       235,049       262,964  
 
                 
 
   
Operating Income
    51,930       33,736       28,479  
 
                       
Other income, net of other expenses
    195       165       103  
 
                       
Interest charges
    9,146       7,086       6,158  
 
                 
 
                       
Income Before Income Taxes
    42,979       26,815       22,424  
 
                       
Income taxes
    16,923       10,918       8,817  
 
                 
 
                       
Net Income
  $ 26,056     $ 15,897     $ 13,607  
 
                 
 
                       
Weighted Average Common Shares Outstanding:
                       
Basic
    9,474,554       7,313,320       6,811,848  
Diluted
    9,582,374       7,440,201       6,927,483  
 
                       
Earnings Per Share of Common Stock:
                       
Basic
  $ 2.75     $ 2.17     $ 2.00  
Diluted
  $ 2.73     $ 2.15     $ 1.98  
 
                       
Cash Dividends Declared Per Share of Common Stock
  $ 1.305     $ 1.250     $ 1.210  
The accompanying notes are an integral part of the financial statements.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 62


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Consolidated Statements of Cash Flows
                         
For the Years Ended December 31,   2010     2009     2008  
(in thousands)
                       
 
                       
Operating Activities
                       
Net Income
  $ 26,056     $ 15,897     $ 13,607  
Adjustments to reconcile net income to net operating cash:
                       
Depreciation and amortization
    20,758       11,588       9,005  
Depreciation and accretion included in other costs
    3,133       2,789       2,239  
Deferred income taxes, net
    13,389       10,065       11,442  
Unrealized (gain) loss on commodity contracts
    (116 )     1,606       (1,252 )
Unrealized (gain) loss on investments
    (181 )     (212 )     509  
Employee benefits and compensation
    (757 )     1,217       152  
Share based compensation
    1,155       1,306       820  
Other, net
    (17 )     (40 )     4  
Changes in assets and liabilities:
                       
Purchase of investments
    (297 )     (146 )     (201 )
Accounts receivable and accrued revenue
    (20,467 )     (13,652 )     19,411  
Propane inventory, storage gas and other inventory
    151       2,597       (1,730 )
Regulatory assets
    687       (1,842 )     411  
Prepaid expenses and other current assets
    1,157       (757 )     (1,182 )
Other deferred charges
    (156 )     (83 )     (153 )
Long-term receivables
    286       191       207  
Accounts payable and other accrued liabilities
    15,853       10,185       (15,033 )
Income taxes receivable
    (3,761 )     5,020       (6,155 )
Accrued interest
    (97 )     66       158  
Customer deposits and refunds
    2,038       (75 )     (502 )
Accrued compensation
    1,339       (2,066 )     (175 )
Regulatory liabilities
    665       1,071       (3,107 )
Other liabilities
    187       1,074       69  
 
                 
Net cash provided by operating activities
    61,005       45,799       28,544  
 
                 
 
                       
Investing Activities
                       
Property, plant and equipment expenditures
    (45,411 )     (26,603 )     (30,756 )
Cash acquired in the merger, net of cash paid
          359        
(Purchases of) proceeds from investments
    (3,108 )     3,519        
Environmental expenditures
    (290 )     (418 )     (480 )
 
                 
Net cash used by investing activities
    (48,809 )     (23,143 )     (31,236 )
 
                 
 
                       
Financing Activities
                       
Common stock dividends
    (11,013 )     (7,957 )     (7,810 )
Issuance of stock for Dividend Reinvestment Plan
    568       392       (118 )
Change in cash overdrafts due to outstanding checks
    3,255       835       (684 )
Net borrowing (repayment) under line of credit agreements
    1,579       (3,812 )     (11,980 )
Other short-term borrowing
    29,100             29,961  
Repayment of long-term debt
    (36,860 )     (10,907 )     (7,658 )
 
                 
Net cash provided by (used in) financing activities
    (13,371 )     (21,449 )     1,711  
 
                 
 
   
Net Increase (Decrease) in Cash and Cash Equivalents
    (1,175 )     1,207       (981 )
Cash and Cash Equivalents — Beginning of Period
    2,818       1,611       2,592  
 
                 
Cash and Cash Equivalents — End of Period
  $ 1,643     $ 2,818     $ 1,611  
 
                 
Supplemental Cash Flow Disclosures (see Note D)
The accompanying notes are an integral part of the financial statements.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 63


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Consolidated Balance Sheets
                 
    December 31,     December 31,  
Assets   2010     2009  
(in thousands, except shares and per share data)            
 
               
Property, Plant and Equipment
               
Regulated energy
  $ 500,689     $ 462,061  
Unregulated energy
    61,313       61,334  
Other
    16,989       16,049  
 
           
 
               
Total property, plant and equipment
    578,991       539,444  
Less: Accumulated depreciation and amortization
    (121,628 )     (107,318 )
Plus: Construction work in progress
    5,394       4,461  
 
           
Net property, plant and equipment
    462,757       436,587  
 
           
 
Investments, at fair value
    4,036       1,959  
 
           
 
               
Current Assets
               
Cash and cash equivalents
    1,643       2,818  
Accounts receivable (less allowance for uncollectible accounts of $1,194 and $1,609, respectively)
    88,074       69,773  
Accrued revenue
    14,978       12,838  
Propane inventory, at average cost
    8,876       7,901  
Other inventory, at average cost
    3,084       3,149  
Regulatory assets
    51       448  
Storage gas prepayments
    5,084       6,144  
Income taxes receivable
    6,748       2,614  
Deferred income taxes
    2,191       724  
Prepaid expenses
    4,613       5,853  
Mark-to-market energy assets
    1,642       2,379  
Other current assets
    245       147  
 
           
Total current assets
    137,229       114,788  
 
           
 
               
Deferred Charges and Other Assets
               
Goodwill
    35,613       34,095  
Other intangible assets, net
    3,459       3,951  
Long-term receivables
    155       440  
Regulatory assets
    23,884       20,100  
Other deferred charges
    3,860       3,891  
 
           
Total deferred charges and other assets
    66,971       62,477  
 
           
 
               
Total Assets
  $ 670,993     $ 615,811  
 
           
The accompanying notes are an integral part of the financial statements.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 64


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Consolidated Balance Sheets
                 
  December 31,     December 31,  
Capitalization and Liabilities   2010     2009  
(in thousands, except shares and per share data)            
 
               
Capitalization
               
Stockholders’ equity
               
Common stock, par value $0.4867 per share (authorized 25,000,000 and 12,000,000 shares, respectively)
  $ 4,635     $ 4,572  
Additional paid-in capital
    148,159       144,502  
Retained earnings
    76,805       63,231  
Accumulated other comprehensive loss
    (3,360 )     (2,524 )
Deferred compensation obligation
    777       739  
Treasury stock
    (777 )     (739 )
 
           
Total stockholders’ equity
    226,239       209,781  
 
Long-term debt, net of current maturities
    89,642       98,814  
 
           
Total capitalization
    315,881       308,595  
 
           
 
               
Current Liabilities
               
Current portion of long-term debt
    9,216       35,299  
Short-term borrowing
    63,958       30,023  
Accounts payable
    65,541       51,462  
Customer deposits and refunds
    26,317       25,046  
Accrued interest
    1,789       1,887  
Dividends payable
    3,143       2,959  
Accrued compensation
    6,784       5,341  
Regulatory liabilities
    9,009       8,295  
Mark-to-market energy liabilities
    1,492       2,514  
Other accrued liabilities
    10,393       7,017  
 
           
Total current liabilities
    197,642       169,843  
 
           
 
               
Deferred Credits and Other Liabilities
               
Deferred income taxes
    80,031       66,008  
Deferred investment tax credits
    243       335  
Regulatory liabilities
    3,734       4,393  
Environmental liabilities
    10,587       11,104  
Other pension and benefit costs
    18,199       15,088  
Accrued asset removal cost — Regulatory liability
    35,092       33,214  
Other liabilities
    9,584       7,231  
 
           
Total deferred credits and other liabilities
    157,470       137,373  
 
           
 
               
Other commitments and contingencies (Note P and Q)
               
 
               
Total Capitalization and Liabilities
  $ 670,993     $ 615,811  
 
           
The accompanying notes are an integral part of the financial statements.

 

Chesapeake Utilities Corporation 2010 Form 10-K     Page 65


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Consolidated Stockholders’ Equity
                                                                 
    Common Stock                     Accumulated Other                    
    Number of             Additional Paid-In             Comprehensive     Deferred              
(in thousands, except shares and per share data)   Shares(7)     Par Value     Capital     Retained Earnings     Loss     Compensation     Treasury Stock     Total  
Balances at December 31, 2007
    6,777,410     $ 3,298     $ 65,593     $ 51,538     $ (852 )   $ 1,404     $ (1,404 )   $ 119,577  
Net Income
                            13,607                               13,607  
Other comprehensive income, net of tax:
                                                               
Employee Benefit Plans, net of tax:
                                                               
Amortization of prior service costs (4)
                                    (71 )                     (71 )
Net loss (5)
                                    (2,825 )                     (2,825 )
 
                                                             
 
                                                               
Total comprehensive income
                                                            10,711  
 
                                                             
 
                                                               
Dividend Reinvestment Plan
    9,060       5       269                                       274  
Retirement Savings Plan
    5,260       3       156                                       159  
Conversion of debentures
    10,397       5       171                                       176  
Share based compensation (1) (3)
    24,994       12       442                                       454  
Tax benefit on stock warrants
                    50                                       50  
Deferred Compensation Plan
                                            145       (145 )      
Purchase of treasury stock
    (2,425 )                                             (72 )     (72 )
Sale and distribution of treasury stock
    2,425                                               72       72  
Dividends on stock-based compensation
                            (81 )                             (81 )
Cash dividends (2)
                            (8,247 )                             (8,247 )
 
                                               
Balances at December 31, 2008
    6,827,121       3,323       66,681       56,817       (3,748 )     1,549       (1,549 )     123,073  
Net Income
                            15,897                               15,897  
Other comprehensive income, net of tax:
                                                               
Employee Benefit Plans, net of tax:
                                                               
Amortization of prior service costs (4)
                                    7                       7  
Net Gain (5)
                                    1,217                       1,217  
 
                                                             
 
                                                               
Total comprehensive income
                                                            17,121  
 
                                                             
 
                                                               
Dividend Reinvestment Plan
    31,607       15       921                                       936  
Retirement Savings Plan
    32,375       16       966                                       982  
Conversion of debentures
    7,927       4       131                                       135  
Share based compensation (1) (3)
    7,374       3       1,332                                       1,335  
Deferred Compensation Plan (6)
                                            (810 )     810        
Purchase of treasury stock
    (2,411 )                                             (73 )     (73 )
Sale and distribution of treasury stock
    2,411                                               73       73  
Common stock issued in the merger
    2,487,910       1,211       74,471                                       75,682  
Dividends on stock-based compensation
                            (104 )                             (104 )
Cash dividends (2)
                            (9,379 )                             (9,379 )
 
                                               
Balances at December 31, 2009
    9,394,314       4,572       144,502       63,231       (2,524 )     739       (739 )     209,781  
Net Income
                            26,056                               26,056  
Other comprehensive income, net of tax:
                                                               
Employee Benefit Plans, net of tax:
                                                               
Amortization of prior service costs (4)
                                    8                       8  
Net loss (5)
                                    (844 )                     (844 )
 
                                                             
 
                                                               
Total comprehensive income
                                                            25,220  
 
                                                             
 
                                                               
Dividend Reinvestment Plan
    53,806       26       1,699                                       1,725  
Retirement Savings Plan
    27,795       14       889                                       903  
Conversion of debentures
    11,865       6       196                                       202  
Tax benefit on share based compensation
                    253                                       253  
Share based compensation (1) (3)
    36,415       17       620                                       637  
Deferred Compensation Plan (6)
                                            38       (38 )      
Purchase of treasury stock
    1,144                                               (38 )     (38 )
Sale and distribution of treasury stock
    (1,144 )                                             38       38  
Dividends on stock-based compensation
                            (103 )                             (103 )
Cash dividends (2)
                            (12,379 )                             (12,379 )
 
                                               
Balances at December 31, 2010
    9,524,195     $ 4,635     $ 148,159     $ 76,805     $ (3,360 )   $ 777     $ (777 )   $ 226,239  
 
                                               
     
(1)  
Includes amounts for shares issued for Directors’ compensation.
 
(2)  
Cash dividends declared per share for the periods ended December 31, 2010, 2009 and 2008 were $1.305, $1.250 and $1.210 respectively.
 
(3)  
The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For 2010 and 2008, the Company withheld 17,695 and 12,511 respectively shares for taxes. The Company did not issue any shares for the PIP in 2009.
 
(4)  
Tax expense (benefit) recognized on the prior service cost component of employees benefit plans for the periods ended December 31, 2010, 2009 and 2008 were approximately $5, $5 and ($52) respectively.
 
(5)  
Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended December 31, 2010, 2009 and 2008 were ($541), $794 and ($1,900) respectively.
 
(6)  
In May and November 2009, certain participants of the Deferred Compensation Plan received distributions totaling $883. There were no distributions in 2010 and 2008.
 
(7)  
Includes 29,600, 28,452, and 62,221 shares at December 31, 2010, 2009 and 2008, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.
The accompanying notes are an integral part of the financial statements.

 

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Notes to the Consolidated Financial Statements
A. Summary of Accounting Policies
Nature of Business
Chesapeake, incorporated in 1947 in Delaware, is a diversified utility company engaged in regulated energy, unregulated energy and other unregulated businesses. Our regulated energy business delivers natural gas to approximately 120,000 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida and electricity to approximately 31,000 customers in northeast and northwest Florida. Our regulated energy business also provides natural gas transmission service primarily through a 396-mile interstate pipeline from various points in Pennsylvania and northern Delaware to our natural gas distribution affiliates in Delaware and Maryland as well as to other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland.
Our unregulated energy business includes natural gas marketing, propane distribution and propane wholesale marketing operations. The natural gas marketing operation sells natural gas supplies directly to commercial and industrial customers in Florida, Delaware and Maryland. Through our propane distribution operation, we distribute propane to approximately 48,000 customers in Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania and Florida. The propane wholesale marketing operation markets propane to wholesale customers including large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States.
We also engage in non-energy businesses, primarily through our advanced information services subsidiary, which provides information-technology-related business services and solutions for both enterprise and e-business applications.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Chesapeake and its wholly-owned subsidiaries. As a result of the merger with FPU on October 28, 2009, FPU’s financial position, results of operations and cash flows have been consolidated into our results from the effective date of the merger. We do not have any ownership interests in investments accounted for using the equity method or any variable interests in a variable interest entity. All intercompany transactions have been eliminated in consolidation.
System of Accounts
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC with respect to their rates for service, maintenance of their accounting records and various other matters. ESNG is an open access pipeline regulated by the FERC. Our financial statements are prepared in accordance with GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various regulatory commissions. The unregulated energy and other unregulated businesses are not subject to regulation with respect to rates, service or maintenance of accounting records.
Reclassifications
We reclassified certain amounts in the consolidated balance sheet as of December 31, 2009 and in the consolidated statements of cash flows for the years ended December 31, 2009 and 2008 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.
Use of Estimates
Our financial statements are prepared in conformity with GAAP, which requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates.

 

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Notes to the Consolidated Financial Statements
Property, Plant, Equipment and Depreciation
Property, plant and equipment is stated at original cost less accumulated depreciation or fair value, if impaired. Property, plant and equipment acquired in the merger were stated at fair value at the time of the merger. Costs include direct labor, materials and third-party construction contractor costs, allowance for capitalized interest and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. The provision for depreciation is computed using the straight-line method at rates that amortize the unrecovered cost of depreciable property over the estimated remaining useful life of the asset. Depreciation and amortization expenses for the regulated energy operations are provided at various annual rates, as approved by the regulators.
                     
    December 31,     December 31,      
    2010     2009     Useful Life(1)
(in thousands)                
Plant in service
                   
Mains
  $ 259,672     $ 236,352     27-62 years
Services — utility
    68,349       65,070     12-48 years
Compressor station equipment
    24,952       24,981     42 years
Liquified petroleum gas equipment
    27,623       28,240     5-31 years
Meters and meter installations
    32,850       28,419     Unregulated energy 3-33 years, regulated
energy 14-49 years
Measuring and regulating station equipment
    22,332       17,708     14-54 years
Office furniture and equipment
    15,796       15,532     Unregulated energy 4-7 years,
regulated energy 14-25 years
Transportation equipment
    17,046       16,613     1-20 years
Structures and improvements
    16,290       15,184     3-44 years (2)
Land and land rights
    15,052       12,789     Not depreciable, except certain regulated assets
Propane bulk plants and tanks
    7,967       7,275     12-40 years
Electric transmission lines and transformers
    30,669       29,024     10-41 years
Poles and towers
    9,259       8,434     21-40 years
Other equipment
    9,189       11,147     10-61 years
Various
    21,945       22,676     Various
 
               
Total plant in service
    578,991       539,444      
Plus construction work in progress
    5,394       4,461      
Less accumulated depreciation
    (121,628 )     (107,318 )    
 
               
Net property, plant and equipment
  $ 462,757     $ 436,587      
 
               
(1)  
Certain immaterial account balances may fall outside this range.
 
   
The regulated operations compute depreciation in accordance with rates approved by either the state PSC or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage value.
 
   
The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.
 
(2)  
Includes buildings, structures used in connection with natural gas, electric and propane operations, improvements to those facilities and leasehold improvements.

 

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Notes to the Consolidated Financial Statements
Plant in service includes $1.4 million of assets owned by one of our natural gas transmission subsidiaries, which it uses to provide natural gas transmission service under a contract with a third- party. This contract is accounted for as an operating lease due to exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and provides $264,000 in annual revenues for a term of 20 years. Accumulated depreciation for these assets total $146,000 at December 31, 2010.
Cash and Cash Equivalents
Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.
Inventories
We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.
Regulatory Assets, Liabilities and Expenditures
We account for our regulated operations in accordance with ASC Topic 980, “Regulated Operations.” This Topic includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company for amounts previously collected from customers, and for recovery of costs that are expected to be incurred in the future as regulatory liabilities. If we were to require to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in the statement of income at that time, which could have a material impact to our financial position, result of operation and cash flows.

 

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Notes to the Consolidated Financial Statements
At December 31, 2010 and 2009, the regulated utility operations had recorded the following regulatory assets and liabilities on the Balance Sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.
                 
    December 31,     December 31,  
    2010     2009  
(in thousands)
               
Regulatory Assets
               
Underrecovered purchased fuel costs
  $     $ 368  
Income tax related amounts due from customers
    1,897       2,022  
Deferred post retirement benefits
    8,304       3,636  
Deferred transaction and transition costs
    1,264       1,486  
Deferred conversion and development costs
    2,069       2,720  
Environmental regulatory assets and expenditures
    6,826       7,510  
Acquisition adjustment (1)
    764       795  
Loss on reacquired debt(3)
    1,668       154  
Other
    1,143       1,857  
 
           
Total Regulatory Assets
  $ 23,935     $ 20,548  
 
           
 
               
Regulatory Liabilities
               
Self insurance
  $ 1,265     $ 1,152  
Overrecovered purchased fuel costs
    8,159       6,523  
Shared interruptible margins
          84  
Conservation cost recovery
    320       1,060  
Rate refund(2)
          258  
Income tax related amounts due to customers
    48       74  
Storm reserve
    2,682       2,554  
Accrued asset removal cost
    35,092       33,214  
Other
    269       983  
 
           
Total Regulatory Liabilities
  $ 47,835     $ 45,902  
 
           
(1)  
Net carrying value of goodwill from FPU’s previous acquisition that is allowed to be amortized pursuant to a rate order.
 
(2)  
Refunded to FPU natural gas customers in February 2010.
 
(3)  
Gains and losses resulting from the reacquisition of long-term debt, which are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.
We have deferred certain costs as regulatory assets prior to obtaining specific regulatory approvals. We have deferred $1.3 million and $1.5 million, of FPU merger-related costs at December 31, 2010 and 2009, respectively, as deferred transaction and transition costs above, which represent our estimate, based on similar proceedings in Florida in the past, of the merger-related costs which we expect to be permitted to recover when we complete the appropriate proceedings. We are currently in the process of discussing this recovery with the Office of Public Counsel. Also included in income tax related amounts due from customers are $1.2 million and $838,000 at December 31, 2010 and 2009, respectively, for which we are currently seeking recovery in the rate case. With the exception of purchased fuel costs and deferred conversion and development costs, there are no material regulatory assets for which we have not earned the appropriate rate of return.
We monitor our regulatory and competitive environment to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that provisions of ASC Topic 980 “Regulated Operations” continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.

 

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Notes to the Consolidated Financial Statements
Goodwill and Other Intangible Assets
Goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note H, “Goodwill and Other Intangible Assets,” to the Consolidated Financial Statements for additional discussion of this subject.
Other Deferred Charges
Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.
Pension and Other Postretirement Plans
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. Management annually reviews the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When establishing its discount rates, we consider high quality corporate bond rates based on the Moody’s Aa bond index, the Citigroup yield curve, changes in those rates from the prior year, and other pertinent factors, such as the expected life of each of our plans and their respective payment options.
The expected long-term rates of return on assets are utilized in calculating the expected returns on plan assets component of our annual pension and plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets.
We estimate the assumed health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.
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 increase in the discount rate could decrease our pension and postretirement costs by approximately $98,000 and a decrease of 0.25 percent could increase our pension and postretirement costs by $123,000. A 0.25 percent increase in the rate of return would decrease our pension cost by approximately $112,000, and a decrease of 0.25 percent could increase our pension cost by approximately $117,000 and will not have an impact on postretirement and SERP plans because these plans are not funded.

 

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Notes to the Consolidated Financial Statements
Income Taxes and Investment Tax Credit Adjustments
Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statement bases and tax bases of assets and liabilities and are measured using the enacted tax rates in effect in the years in which the differences are expected to reverse. The portions of our deferred tax liabilities applicable to regulated energy operations, which have not been reflected in current service rates, represent income taxes recoverable through future rates. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
We account for uncertainty in income taxes in the financial statements only if it is “more likely than not” that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the financial statements.
Financial Instruments
Xeron, our propane wholesale marketing operation, engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, our trading contracts are recorded at fair value, net of future servicing costs. The changes in market price are recognized as gains or losses in revenues on the consolidated statements of income in the period of change. There were unrealized gains of $284,000 in 2010 and unrealized losses of $1.6 million in 2009. Trading liabilities are recorded as mark-to-market energy liabilities. Trading assets are recorded as mark-to-market energy assets.
Our natural gas, electric and propane distribution operations and natural gas marketing operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis.
The propane distribution operation may enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. During 2008, we entered into a swap agreement to protect the Company from the impact that propane price increases would have on the Pro-Cap (propane price cap) Plan that the Delmarva propane distribution operation offers to our customers. Propane prices declined significantly in late 2008 and we recorded a mark-to-market loss of approximately $939,000 on the swap agreement in 2008, which increased the cost of propane sales. In January 2009, we terminated the swap agreement. The propane distribution operation may enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. During 2010 and 2009, we purchased a put option related to the Pro-Cap Plan, which we accounted for on a mark-to-market basis, and recorded a loss of $168,000 and $41,000, respectively. At both December 31, 2010 and 2009, the fair value of the put options was $0.

 

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Notes to the Consolidated Financial Statements
Earnings Per Share
Basic earnings per share are computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed by dividing income available for common stockholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities, such as convertible debt and share-based compensation. The calculations of both basic and diluted earnings per share are presented in the following chart.
                         
For the Years Ended December 31,   2010     2009     2008  
(in thousands, except shares and per share data)                        
Calculation of Basic Earnings Per Share:
                       
Net Income
  $ 26,056     $ 15,897     $ 13,607  
Weighted average shares outstanding
    9,474,554       7,313,320       6,811,848  
 
                 
Basic Earnings Per Share
  $ 2.75     $ 2.17     $ 2.00  
 
                 
 
                       
Calculation of Diluted Earnings Per Share:
                       
Reconciliation of Numerator:
                       
Net Income
  $ 26,056     $ 15,897     $ 13,607  
Effect of 8.25% Convertible debentures
    73       79       89  
 
                 
Adjusted numerator — Diluted
  $ 26,129     $ 15,976     $ 13,696  
 
                 
 
                       
Reconciliation of Denominator:
                       
Weighted shares outstanding — Basic
    9,474,554       7,313,320       6,811,848  
Effect of dilutive securities:
                       
Share-based Compensation
    22,550       34,229       12,083  
8.25% Convertible debentures
    85,270       92,652       103,552  
 
                 
Adjusted denominator — Diluted
    9,582,374       7,440,201       6,927,483  
 
                 
 
                       
Diluted Earnings Per Share
  $ 2.73     $ 2.15     $ 1.98  
 
                 
Common stock issued in connection with the FPU merger (See Note B, “Acquisitions,” to the Consolidated Financial Statements) increased weighted average shares outstanding during 2010 and 2009.
Operating Revenues
Revenues for our natural gas and electric distribution operations are based on rates approved by the PSCs of the states in which they operate. The natural gas transmission operation’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 ESNG 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. In connection with this accrual, we must estimate the amount of natural gas and electricity that have not been accounted for on our delivery systems and must 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.

 

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Notes to the Consolidated Financial Statements
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in our consolidated statement of income. For propane distribution 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 FPU natural gas operation and electric distribution operation in Florida has a purchased fuel cost recovery mechanism. This mechanism provides a method of adjusting the billing rates 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 purchased fuel costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. Chesapeake’s Florida natural gas distribution division provides only unbundled delivery service.
We charge flexible rates to our natural gas distribution industrial interruptible customers to compete with prices of alternative fuels, which these customers are able to use. Neither we nor any of our interruptible customers is contractually obligated to deliver or receive natural gas on a firm service basis.
We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.
Cost of Sales
Cost of sales includes the direct costs attributable to the products sold or services we provide for our regulated and unregulated energy segments. These costs include primarily the variable 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 for our advanced information services operation.
Operations and Maintenance Expenses
Operations and maintenance expenses are costs associated with the operation and maintenance of our regulated and unregulated operations. Major cost components include operation and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets, and other administrative expenses.
Depreciation and Accretion Included in Operations Expenses
Depreciation and accretion included in operations expenses consist of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense.
Allowance for Doubtful Accounts
An allowance for doubtful accounts is recorded against amounts due to reduce the net receivables balance to the amount we reasonably expect to collect based upon our collections experiences and management’s assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such 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 when they are deemed to be uncollectible.

 

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Notes to the Consolidated Financial Statements
Acquisition Accounting
The merger with FPU was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in the merger be recognized at their fair value as of the acquisition date. It also establishes that the consideration transferred be measured at the closing date of the merger at the then-current market price. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability and fair value measures for an asset assume the highest and best use by those market participants, rather than the acquirer’s intended use of those assets. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature of the assets and liabilities and the regulatory mechanism for recovery, to which these assets and liabilities are subject, as a factor in determining their appropriate fair value. We also considered the existence of a regulatory process that would allow, or sometimes require, regulatory assets and liabilities to be established for fair value adjustment to certain assets and liabilities subject to rate regulation. If a regulatory asset or liability should be established to offset the fair value adjustment based on the current regulatory process, as was the case for fuel contracts and long-term debt, we did not “gross-up” our balance sheet to reflect the fair value adjustment and corresponding regulatory asset/liability, because such “gross-up” would not have resulted in a change to our value of net assets and future earnings.
Total value of the consideration transferred by Chesapeake in the FPU merger was $75.7 million. Net fair value of the assets acquired and liabilities assumed in the FPU merger was estimated to be $41.5 million. This resulted in a purchase premium of $34.2 million, which was reflected as goodwill. Note B, “Acquisitions,” to the Consolidated Financial Statements describes more fully the purchase price allocation.
Subsequent Events
We have assessed and reported on subsequent events through the date of issuance of these Consolidated Financial Statements.
 
FASB Statements and Other Authoritative Pronouncements
Recent Accounting Amendments Yet to be Adopted by the Company
In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”), a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”). Under the proposed roadmap, we may be required to prepare our financial statements in accordance with IFRS as early as 2015. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. In July 2009, the IASB issued an exposure draft of “Rate-regulated Activities,” which sets out the scope, recognition and measurement criteria, and accounting disclosures for assets and liabilities that arise in the context of cost-of-service regulation, to which our rate-regulated businesses are subject. Throughout 2010, IASB has continued its deliberation on the exposure draft and comments received on the overall concept of the recognition of assets and liabilities arising out of cost-of-service regulation. We will continue to monitor the development of the potential implementation of IFRS.
Other Accounting Amendments Adopted by the Company in 2010
In January 2010, the FASB issued FASB Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires certain new disclosures and clarifies certain existing disclosure requirements about fair value measurement, as set forth in FASB ASC Subtopic 820-10. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and, in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separate information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. We adopted the disclosures required by this ASU in the first quarter of 2010, except for disclosures about purchases, sales, issuances, and settlements in the roll-forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We currently do not have any assets or liabilities that would require Level 3 fair value measurements. Adoption of this ASU did not have an impact on our consolidated financial position and results of operations and cash flows.

 

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Notes to the Consolidated Financial Statements
In April 2010, the FASB issued FASB ASU 2010-12 — Income Taxes (Topic 740), “Accounting for Certain Tax effects of the 2010 Health Care Reform Acts.” This ASU codifies the SEC staff announcement relating to the accounting for the Health Care and Education Reconciliation Act and the Patient Protection and Affordable Care Act, which allows the two Acts to be considered together for accounting purposes. We adopted this ASU in the first quarter of 2010 and have determined that these Acts did not have a material impact on our income tax accounting (see Note M, “Employee Benefit Plans,” to the Consolidated Financial Statements for further discussion).
B. Acquisitions
FPU
On October 28, 2009, we completed a merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes.
The merger increased our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing Florida operations. As a result of the merger, we also now serve approximately 31,000 electric customers in northwest and northeast Florida.
In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at a price per share of $30.42 in exchange for all outstanding common stock of FPU. We also paid approximately $16,000 in lieu of issuing fractional shares in the exchange. There was no contingent consideration in the merger. The total value of consideration transferred by Chesapeake in the merger was approximately $75.7 million.
The assets acquired and liabilities assumed in the merger were recorded at their respective fair values at the completion of the merger. For certain assets acquired and liabilities assumed, such as pension and post-retirement benefit obligations, income taxes and contingencies without readily determinable fair values, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate.

 

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Notes to the Consolidated Financial Statements
The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed at the date of the merger.
         
    October 28, 2009  
(in thousands)
       
Purchase price
  $ 75,699  
 
       
Current assets
    26,761  
Property, plant and equipment
    139,709  
Regulatory assets
    19,899  
Investments and other deferred charges
    3,659  
Intangible assets
    4,019  
 
     
Total assets acquired
    194,047  
 
       
Long term debt
    47,812  
Borrowings from line of credit
    4,249  
Other current liabilities
    17,427  
Pre-merger contingencies
    923  
Other regulatory liabilities
    19,414  
Pension and post retirement obligations
    14,276  
Environmental liabilities
    12,414  
Deferred income taxes
    20,559  
Customer deposits and other liabilities
    15,467  
 
     
Total liabilities assumed
    152,541  
 
     
Net identifiable assets acquired
    41,506  
 
     
Goodwill
  $ 34,193  
 
     
   
During 2010, we adjusted the allocation of the purchase price based on additional information available. The adjustments are related to certain accruals, regulatory assets, deferred and current income tax assets and liabilities, and pre-merger contingencies (see discussion below). These adjustments also resulted in a change in fair value of the propane property, plant and equipment. Goodwill from the merger increased to $34.2 million after incorporating these adjustments, compared to $33.4 million as previously disclosed at December 31, 2009.
   
None of the $34.2 million in goodwill recorded in connection with the merger is deductible for tax purposes. All of the goodwill recorded in connection with the merger is related to the regulated energy segment. We believe the goodwill recognized is attributable to the synergies and opportunities primarily related to FPU’s regulated energy businesses. The intangible assets acquired in connection with the merger are related to propane customer list ($3.5 million) and favorable propane supply contracts ($519,000). The intangible value assigned to FPU’s existing propane customer list is being amortized over a 12-year period based on the expected duration of the benefit arising from the list. The intangible value assigned to FPU’s favorable propane contracts is being amortized over a period ranging from one to 14 months based on contractual terms.
   
Current assets of $26.8 million acquired during the merger included notes receivable of approximately $5.8 million, for which we received full payment in March 2010, and accounts receivable of approximately $3.1 million, $6.0 million and $891,000 for FPU’s natural gas, electric and propane distribution businesses, respectively.
   
The pre-merger contingencies of $923,000 included in the final allocation of the purchase price are primarily related to a pending settlement agreement for a class action complaint against FPU from a propane customer, which is further discussed in Note Q, “Other Commitments and Contingencies” to the Consolidated Financial Statements. The proposed settlement addresses a particular charge by FPU to its propane customers during the period from May 27, 2006 to September 24, 2010, which encompasses both pre-merger and post-merger periods. We used the ratio of the charges assessed to customers during the pre-merger period to the charges assessed to customers during the total settlement period to estimate that $835,000 of the total contingency was related to FPU’s operations prior to the merger with Chesapeake. The portion of the liability related to FPU’s operations after the merger with Chesapeake and any increases to the liability after the measurement date, which totaled to $370,000, was expensed in 2010. Also included in the pre-merger contingencies are liabilities related to FPU’s income taxes for periods prior to the merger.

 

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Notes to the Consolidated Financial Statements
   
The financial position and results of operations and cash flows of FPU from the effective date of the merger are included in our consolidated financial statements. The revenue from FPU for the years December 31, 2010 and 2009, included in our consolidated statements of income, were $180.2 million and $26.4 million, respectively, and the net income from FPU for the years ended December 31, 2010 and 2009, included in our consolidated statements of income, were $9.3 million and $1.8 million, respectively.
   
The following table shows the actual results of combined operations for the year ended December 31, 2010 and pro forma results of combined operations for the year ended December 31, 2009, as if the merger had been completed at January 1, 2009. Since the effects of the merger for the year ended December 31, 2010 were already included in the actual results of our consolidated operations, there is no pro forma adjustment for the year ended December 31, 2010.
                 
For the Years Ended December 31,   2010     2009  
(in thousands, except per share data)                
 
               
Operating revenues
  $ 427,546     $ 394,772  
Operating Income
  $ 51,930     $ 44,382  
Net Income
  $ 26,056     $ 20,872  
 
               
Earnings per share — basic
  $ 2.75     $ 2.23  
Earnings per share — diluted
  $ 2.73     $ 2.20  
Pro forma results are presented for informational purposes only and are not necessarily indicative of what the actual results would have been had the acquisition actually occurred on January 1, 2009.
The acquisition method of accounting requires acquisition-related costs to be expensed in the period in which those costs are incurred, rather than including them as a component of consideration transferred. It also prohibits an accrual of certain restructuring costs at the time of the merger. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining the proper accounting treatment for the merger-related costs. As of December 31, 2010, we incurred approximately $3.3 million in costs to consummate the merger, including the cost associated with merger-related litigation and integrating operations following the merger. This includes $369,000 incurred during the year ended December 31, 2010. We deferred approximately $1.3 million of the total costs incurred as a regulatory asset at December 31, 2010, which represents our best estimate, based on similar proceedings in Florida in the past, of the costs which we expect to be permitted to recover when we complete the appropriate rate proceedings.
Included in the $3.3 million merger-related costs incurred as of December 31, 2010, were approximately $452,000 of severance and other restructuring charges for our efforts to integrate the operations of the two companies.
Virginia LP Gas
On February 4, 2010, Sharp Energy, Inc. (“Sharp”), our propane distribution subsidiary, purchased the operating assets of Virginia LP Gas, Inc., a propane distributor serving approximately 1,000 retail customers in Northampton and Accomack Counties in Virginia. The total consideration for the purchase was $600,000, of which $300,000 was paid at the closing and the remaining $300,000 will be paid over 60 months. Based on our valuation, we allocated $188,000 of the purchase price to intangible assets, which consist of customer lists and non-compete agreements. These intangible assets are being amortized over a seven-year period. There was no goodwill recorded in connection with this acquisition. The revenue and net income from this acquisition which were included in our consolidated statement of income for the year ended December 31, 2010 were not material.

 

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Notes to the Consolidated Financial Statements
Indiantown Gas Company
On August 9, 2010, FPU purchased the natural gas operating assets of IGC, which provides natural gas distribution services to approximately 700 customers including two large industrial customers in Indiantown, Florida. FPU paid approximately $1.2 million for these assets. FPU recorded $742,000 in goodwill in connection with this acquisition, all of which is deductible for income tax purposes. There was no intangible asset recorded in connection with this acquisition. The revenue and net income from this acquisition which were included in our consolidated statement of income for the year ended December 31, 2010 were not material.
C. Segment Information
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise of three operating segments:
   
Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of ESNG.
   
Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services.
   
Other. The “Other” segment consists primarily of the advanced information services subsidiary, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

 

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Notes to the Consolidated Financial Statements
The following table presents information about our reportable segments.
                         
For the Years Ended December 31,   2010     2009     2008  
(in thousands)                        
Operating Revenues, Unaffiliated Customers
                       
Regulated Energy
  $ 268,830     $ 137,847     $ 115,544  
Unregulated Energy
    146,430       119,719       161,287  
Other
    12,286       11,219       14,612  
 
                 
Total operating revenues, unaffiliated customers
  $ 427,546     $ 268,785     $ 291,443  
 
                 
 
                       
Intersegment Revenues (1)
                       
Regulated Energy
  $ 1,104     $ 1,252     $ 924  
Unregulated Energy
    363       254       3  
Other
    856       779       761  
 
                 
Total intersegment revenues
  $ 2,323     $ 2,285     $ 1,688  
 
                 
 
                       
Operating Income
                       
Regulated Energy
  $ 43,509     $ 26,900     $ 24,733  
Unregulated Energy
    7,908       8,158       3,781  
Other
    513       (1,322 )     (35 )
 
                 
Operating Income
    51,930       33,736       28,479  
 
Other income
    195       165       103  
Interest charges
    9,146       7,086       6,158  
Income taxes
    16,923       10,918       8,817  
 
                 
Net income from continuing operations
  $ 26,056     $ 15,897     $ 13,607  
 
                 
 
                       
Depreciation and Amortization
                       
Regulated Energy
  $ 17,038     $ 8,866     $ 6,694  
Unregulated Energy
    3,433       2,415       2,024  
Other and eliminations
    287       307       287  
 
                 
Total depreciation and amortization
  $ 20,758     $ 11,588     $ 9,005  
 
                 
 
                       
Capital Expenditures
                       
Regulated Energy
  $ 41,898     $ 22,917     $ 25,386  
Unregulated Energy
    2,764       1,873       3,417  
Other
    2,293       1,504       2,041  
 
                 
Total capital expenditures
  $ 46,955     $ 26,294     $ 30,844  
 
                 
(1)  
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
                 
At December 31,   2010     2009  
(in thousands)
               
 
Identifiable Assets
               
Regulated Energy
  $ 520,192     $ 481,606  
Unregulated Energy
    113,039       99,642  
Other
    37,762       34,286  
 
           
Total identifiable assets
  $ 670,993     $ 615,534  
 
           

 

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Notes to the Consolidated Financial Statements
Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions with foreign companies, located primarily in Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.
D. Supplemental Cash Flow Disclosures
Cash paid for interest and income taxes during the years ended December 31, 2010, 2009 and 2008 were as follows:
                         
For the Years Ended December 31,   2010     2009     2008  
(in thousands)                        
Cash paid for interest
  $ 8,751     $ 6,703     $ 5,835  
Cash paid for income taxes
  $ 10,168     $ 1,111     $ 3,885  
Non-cash investing and financing activities during the years ended December 31, 2010, 2009, and 2008 were as follows:
                         
For the Years Ended December 31,   2010     2009     2008  
(in thousands)                        
Capital property and equipment acquired on account, but not paid as of December 31
  $ 1,064     $ 1,151     $ 696  
Merger/acquisitions
  $ 300     $ 75,682     $  
Retirement Savings Plan
  $ 902     $ 982     $ 159  
Dividend Reinvestment Plan
  $ 1,182     $ 692     $ 208  
Conversion of Debentures
  $ 202     $ 135     $ 177  
Performance Incentive Plan
  $ 719     $     $ 568  
Director Stock Compensation Plan
  $ 297     $ 214     $ 181  
Tax benefit on stock warrants and share-based compensation
  $ 253     $     $ 50  
E. Derivative Instruments
We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas and propane. Our natural gas and propane distribution operations have entered into agreements with suppliers to purchase natural gas and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of December 31, 2010, our natural gas and propane distribution operations did not have any outstanding derivative contracts.

 

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Notes to the Consolidated Financial Statements
Xeron, our propane wholesale and marketing operation, engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the trading contracts are recorded at fair value and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income in the period of change. As of December 31, 2010, we had the following outstanding trading contracts which we accounted for as derivatives:
                         
    Quantity in     Estimated Market     Weighted Average  
At December 31, 2010   Gallons     Prices     Contract Prices  
Forward Contracts
                       
Sale
    13,523,496     $1.0350 — $1.4100     $ 1.2192  
Purchase
    12,914,496     $1.0150 — $1.3779     $ 1.2093  
 
                       
Other Contract
                       
Put option
    1,470,000     $—     $ 0.1150  
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire by the end of the second quarter of 2011.
The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.
Fair values of the derivative contracts recorded in the Consolidated Balance Sheets as of December 31, 2010 and 2009, are the following:
                         
            Asset Derivatives  
            Fair Value  
            December 31,     December 31,  
(in thousands)   Balance Sheet Location   2010     2009  
Derivatives not designated as hedging instruments:
                       
Forward contracts
  Mark-to-market energy assets   $ 1,642     $ 2,379  
Put Option(1) (2)
  Mark-to-market energy assets            
 
                   
Total asset derivatives
          $ 1,642     $ 2,379  
 
                   
                         
            Liability Derivatives  
            Fair Value  
            December 31,     December 31,  
(in thousands)   Balance Sheet Location   2010     2009  
Derivatives not designated as hedging instruments:
                       
Forward contracts
  Mark-to-market energy liabilities   $ 1,492     $ 2,514  
 
                   
Total liability derivatives
          $ 1,492     $ 2,514  
 
                   
(1)  
We purchased a put option for the Pro-Cap (propane price cap) Plan in October 2010. The put option which expires in January and February 2011 had a fair value of $0 at December 31, 2010.
 
(2)  
We purchased a put option for the Pro-Cap Plan in September 2009. The put option, which expired on March 31, 2010, had a fair value of $0 at December 31, 2009.

 

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Notes to the Consolidated Financial Statements
The effects of gains and losses from derivative instruments on the Consolidated Statement of Income are the following:
                             
        Amount of Gain (Loss) on Derivatives:  
    Location of Gain   For the Years Ended December 31,  
(in thousands)   (Loss) on Derivatives   2010     2009     2008  
Derivatives designated a fair value hedges:
                           
Propane swap agreement(1)
  Cost of Sales   $     $ (42 )   $ 1,476  
 
                           
Derivatives not designated as hedging instruments:
                           
Put Option(2)
  Cost of Sales     (168 )            
Put Option(3)
  Revenue           (41 )      
Unrealized gain (loss) on forward contracts
  Revenue     284       (1,565 )     1,357  
 
                     
Total
      $ 116     $ (1,648 )   $ 2,833  
 
                     
(1)  
Our propane distribution operation entered into a propane swap agreement to protect it from the impact that wholesale propane price increases would have on the Pro-Cap (propane price cap) Plan that was offered to customers. We terminated this swap agreement in January 2009.
 
(2)  
We purchased a put option for the Pro-Cap Plan in October 2010. The put option, which expires in January and February 2011, had a fair value of $0 at December 31, 2010.
 
(3)