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EX-14.2 - EXHIBIT 14.2 - CHESAPEAKE UTILITIES CORPc97091exv14w2.htm
EX-10.25 - EXHIBIT 10.25 - CHESAPEAKE UTILITIES CORPc97091exv10w25.htm
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, 2009
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 $.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 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, 2009, 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 $223.5 million.
As of February 28, 2010, 9,436,558 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2010 Annual Meeting of Stockholders are incorporated by reference in Part III.
 
 

 

 


 

Chesapeake Utilities Corporation

Form 10-K
YEAR ENDED DECEMBER 31, 2009
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 Exhibit 10.24
 Exhibit 10.25
 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 new wholly-owned subsidiary of Chesapeake, effective October 28, 2009
OnSight  
Chesapeake OnSight Services, LLC, a wholly-owned subsidiary of Chesapeake
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 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
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
Chesapeake Utilities Corporation 2009 Form 10-K      Page 1

 

 


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Other
     
AOCI  
Accumulated Other Comprehensive Income
DSCP  
Directors Stock Compensation Plan
GSR  
Gas sales service rates
HDD  
Heating degree-days
Mcf  
Thousand Cubic Feet
MWH  
Megawatt Hour
MGP  
Manufactured Gas Plant
NYSE  
New York Stock Exchange
PIP  
Performance Incentive Plan
S&P 500 Index  
Standard & Poor’s 500 Index
SFAS  
Statement of Financial Accounting Standards
Accounting Standards
     
ASC  
FASB Accounting Standards Codification TM(Codification)
ASU  
FASB Accounting Standards Update
FSP  
Financial Accounting Standards Board Staff Position
GAAP  
Generally Accepted Accounting Principles
Page 2      Chesapeake Utilities Corporation 2009 Form 10-K

 

 


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 “Risks 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 or other hostilities or other external factors over which we have no control;
 
   
changes in environmental and other laws and regulations to which we are subject;
 
   
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;
 
   
the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses; and
 
   
the effect of competition on our businesses.
Chesapeake Utilities Corporation 2009 Form 10-K      Page 3

 

 


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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 in 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 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 propane wholesale marketing operation through Xeron, Inc. (“Xeron”). We also have an advance information services subsidiary, BravePoint, Inc. (“BravePoint”).
(b) Operating Segments
As a result of the merger with FPU, we changed our operating segments to better align with how the chief operating decision maker (our Chief Executive Officer) views the various operations of the Company. Our three operating segments are now composed of the following:
   
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 and net property, plant and equipment:
                                 
                    Net Property, Plant  
(in thousands)   Operating Income     & Equipment  
Regulated Energy
  $ 26,900       80 %   $ 387,022       89 %
Unregulated Energy
    8,158       24 %     37,900       8 %
Other
    (1,322 )     -4 %     11,506       3 %
 
                       
Total
  $ 33,736       100 %   $ 436,428       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.”
Page 4     Chesapeake Utilities Corporation 2009 Form 10-K

 

 


Table of Contents

(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
Our Delaware and Maryland natural gas distribution divisions serve 51,736 residential and commercial customers and 155 industrial customers in central and southern Delaware and Maryland’s Eastern Shore. For the year ended December 31, 2009, operating revenues and deliveries by customer class for our Delaware and Maryland distribution divisions were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Residential
  $ 51,309       58 %     2,747,162       36 %
Commercial
    31,942       36 %     2,693,724       35 %
Industrial
    3,696       4 %     1,827,153       24 %
 
                       
Subtotal
    86,947       98 %     7,268,039       95 %
Interruptible
    977       1 %     373,825       5 %
Other (1)
    1,291       1 %            
 
                       
Total
  $ 89,215       100 %     7,641,864       100 %
 
                       
 
                               
     
(1)  
Operating revenues from “Other” sources include unbilled revenue, rental of gas properties, and other miscellaneous charges.
Chesapeake’s Florida natural gas distribution division provides unbundled natural gas distribution services (the delivery of natural gas separated from the sale of the commodity) to 13,268 residential and 1,176 commercial and industrial customers in 14 counties in Florida. For the year ended December 31, 2009, operating revenues and deliveries by customer class for our Florida distribution division were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Residential
  $ 3,682       30 %     318,420       2 %
Commercial
    3,043       25 %     1,151,071       8 %
Industrial
    4,260       34 %     13,271,503       90 %
Other(1)
    1,377       11 %            
 
                       
Total
  $ 12,362       100 %     14,740,994       100 %
 
                       
     
(1)  
Operating revenues from “Other” sources include unbilled revenue, conservation revenue, fees for billing services provided to third-parties and other miscellaneous charges.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 5

 

 


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Our recent merger with FPU provides 51,536 additional residential, commercial and industrial natural gas distribution customers in seven counties in Florida, which have significantly expanded our existing natural gas distribution operations in Florida. For the period from the merger closing (October 28, 2009) to December 31, 2009, operating revenues and deliveries by customer class for these new customers added through the merger were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Residential
  $ 3,028       27 %     180,572       16 %
Commercial
    4,722       43 %     496,183       45 %
Industrial
    1,346       12 %     320,680       29 %
 
                       
Subtotal
    9,096       82 %     997,435       90 %
Other(1)
    2,045       18 %     111,742       10 %
 
                       
Total
  $ 11,141       100 %     1,109,177       100 %
 
                       
     
(1)  
Operating revenues from “Other” sources include unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges and adjustments for pass-through taxes.
FPU’s total natural gas deliveries in the full calendar year 2009, including deliveries for the period prior to the merger, were 1,157,100 Mcfs, 2,942,800 Mcfs and 1,784,500 Mcfs for residential, commercial and industrial customers, respectively.
Electric Distribution
Electric distribution is a new regulated energy business added to the Company as a result of the FPU merger. FPU distributes electricity to 31,030 customers in five counties in northeast and northwest Florida. For the period from the merger closing (October 28, 2009) to December 31, 2009, operating revenues and deliveries by customer class for FPU’s electric distribution services were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (MWHs)  
Residential
  $ 6,140       50 %     43,435       41 %
Commercial
    6,273       52 %     50,033       47 %
Industrial
    1,004       8 %     9,700       10 %
 
                       
Subtotal
    13,417       110 %     103,168       98 %
Other(1)
    (1,174 )     -10 %     2,572       2 %
 
                       
Total
  $ 12,243       100 %     105,740       100 %
 
                       
     
(1)  
Operating revenues from “Other” sources include unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges and adjustments for pass-through taxes.
FPU’s total deliveries of electricity in the full calendar year 2009, including deliveries for the period prior to the merger, were 316,306 MWHs, 316,412 MWHs and 64,950 MWHs for residential, commercial and industrial customers, respectively.
Page 6     Chesapeake Utilities Corporation 2009 Form 10-K

 

 


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Natural Gas Transmission
ESNG operates a 384-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, 2009, operating revenues and deliveries by customer class for ESNG were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Local distribution companies
  $ 19,699       76 %     9,941,436       38 %
Industrial
    4,907       19 %     14,471,109       55 %
Commercial
    1,336       5 %     1,809,970       7 %
Other (1)
    35       0 %            
 
                       
Subtotal
    25,977       100 %     26,222,515       100 %
Less: affiliated local distribution companies
    (12,709 )     (49) %     (5,578,918 )     (21) %
 
                       
Total non-affiliated
  $ 13,268       51 %     20,643,597       79 %
 
                       
     
(1)  
Operating revenues from “Other” sources are from rental of gas properties.
In 2005, we formed PIPECO to operate an intrastate pipeline to provide natural gas transportation services to industrial customers in Florida. In December 2007, the Florida Public Service Commission (“Florida PSC”) approved PIPECO’s natural gas transmission pipeline tariff, which established its operating rules and regulations. In January 2009, PIPECO began providing natural gas transmission services to a customer for a period of 20 years at a fixed monthly charge, through an 8-mile pipeline located in Suwanee County, Florida, which PIPECO owns. For the year ended December 31, 2009, PIPECO had $264,000 in operating revenues under the contract.
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
Our Delaware and Maryland natural gas distribution divisions have both firm and interruptible transportation service contracts with four 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 Corporation (“Transco”), Columbia Gas Transmission Corporation (“Columbia”) and Columbia Gulf Transmission Company (“Gulf”). The Transco and Columbia 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. 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 the spot market purchases.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 7

 

 


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The following table shows the firm transmission 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 transmission            
    capacity maximum     Firm storage      
    peak-day daily     capacity maximum      
    deliverability     peak-day daily      
Pipeline   (Mcfs)     withdrawal (Mcfs)     Expiration
Transco
    20,699       6,190     Various dates between 2010 and 2028
Columbia
    17,836       7,946     Various dates between 2011 and 2020
Gulf
    850           Expires in 2014
ESNG
    63,482       4,006     Various dates between 2010 and 2024
Maryland
                     
    Firm transmission            
    capacity maximum     Firm storage      
    peak-day daily     capacity maximum      
    deliverability     peak-day daily      
Pipeline   (Mcfs)     withdrawal (Mcfs)     Expiration
Transco
    5,921       2,373     Various dates between 2010 and 2012
Columbia
    6,473       3,539     Various dates between 2011 and 2018
Gulf
    570           Expires in 2014
ESNG
    19,834       2,228     Various dates between 2010 and 2023
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. They also have contracts for firm peaking gas supplies to be delivered to their systems in order to meet the differential between their capacities on the ESNG pipeline and capacities on pipelines upstream of ESNG. These supply contracts provide a maximum firm daily entitlement of 13,237 Mcfs and 2,029 Mcfs for the Delaware and Maryland divisions, respectively, delivered on the Transco, Columbia, and/or Gulf systems to ESNG for redelivery to these divisions under firm transmission contracts. These gas supply contracts have various expiration dates, and quantities may vary from day to day and month to month.
Chesapeake’s Florida natural gas distribution division has firm transmission service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a program approved by the Florida PSC, all of the capacity under these agreements has been released to various third-parties, 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, 2010, for daily firm transmission capacity of 22,901 Mcfs for the months of November through April, capacity of 19,594 Mcfs for the months of May through September, and 21,524 Mcfs for October; and (b) a contract for daily firm transmission capacity of 974 Mcfs daily, which expires in 2015. Chesapeake’s contract with Gulfstream is for daily firm transmission capacity of 9,737 Mcfs and expires in 2022.
Page 8     Chesapeake Utilities Corporation 2009 Form 10-K

 

 


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FPU has firm transmission service contracts with FGT and firm transportation contracts with Florida City Gas (“FCG”) and Indiantown Gas Company (“IGC”). The additional contracts with FGT include (a) a contract which expires on July 2020, for daily firm transmission capacity of 26,500 Mcfs for the months of November through March, 22,411 Mcfs for the month of April, 9,211 Mcfs for the months of May through September and 9,314 Mcfs for the month of October; (b) a contract which expires in 2015 for daily firm transmission capacity of 10,286 Mcfs for the months of November through April and 4,360 Mcfs for the months of May through October; (c) a contract which expires in July 2020 for daily firm transmission capacity of 2,147 Mcfs for the months of November through March, 1,745 Mcfs for the month of April, 470 Mcfs for the months of May through September, and 896 Mcfs for the month of October; and (d) a contract for daily firm transmission capacity of 1,774 Mcfs with various partial expiration dates between 2016 and 2023. The contract with FCG, which expires in 2013, provides daily firm transportation capacity of 292 Mcfs on its Pioneer Pipeline. The contract with IGC, which expires in 2016, provides daily firm transportation capacity of 487 Mcfs on its distribution system.
FPU uses gas marketers and producers to procure all 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 service(s).
Electric Distribution
Our electric distribution operation through FPU purchases all of its wholesale electricity from two suppliers: Gulf Power Company and JEA (formerly known as Jacksonville Electric Authority). Both of these contracts are all requirements contracts that expire in December 2017. The JEA contract provides generation, transmission and distribution service to northeast Florida. The Gulf Power Company contract provides generation, transmission and distribution service to northwest Florida.
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 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 transmission and storage services. PIPECO is subject to regulation by the Florida PSC.
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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 Current Rates   Rate of 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.
Management monitors the achieved rates of return of each of our regulated energy operations in order to ensure timely filing of rate cases.
Regulatory Proceedings
See discussion of regulatory activities in Item 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.
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(ii)  Unregulated Energy
Our unregulated energy segment provides natural gas marketing, propane distribution and propane wholesale marketing services to customers.
Natural Gas Marketing
Our natural gas marketing subsidiary, PESCO, provides natural gas supply and supply management services to 2,123 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, 2009, PESCO’s operating revenues and deliveries were as follows:
                                 
    Operating Revenues     Deliveries  
    (in thousands)     (Mcfs)  
Florida
  $ 41,117       72 %     7,066,144       71 %
Delmarva
    16,386       28 %     2,818,844       29 %
 
                       
Total
  $ 57,503       100 %     9,884,988       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 of 2010. 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.
Included in PESCO’s operating revenue on the Delmarva Peninsula for 2009 was approximately $10.6 million of various natural gas spot sales and services to Valero Energy Corporation (“Valero”) for its Delaware City refinery operation. We previously reported on November 25, 2009 in a Form 8-K that Valero announced its intention to permanently shut down its Delaware City refinery. Spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
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.
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Sharp, our propane distribution subsidiary, serves 33,088 customers throughout Delaware, the Eastern Shore of Maryland and Virginia and southeastern Pennsylvania. Sharp’s Florida operation offers propane distribution services to 1,941 customers in parts of Florida. After the merger with FPU, 1,642 customers previously served by Sharp’s Florida propane distribution operation are now being served by FPU’s propane distribution operation in an effort to integrate operations. For the year ended December 31, 2009, operating revenues and total gallons sold by Sharp’s Delmarva and Florida propane distribution operations were as follows:
                                 
    Operating Revenues     Total Gallons Sold  
    (in thousands)     (in thousands)  
Delmarva
  $ 54,850       96 %     30,635       97 %
Florida
    2,357       4 %     853       3 %
 
                       
Total
  $ 57,207       100 %     31,488       100 %
 
                       
FPU has 13,651 propane distribution customers, including the customers previously served by Sharp’s propane distribution operation in Florida as previously discussed, which increased our propane customer base in Florida. For the period from the merger closing (on October 28, 2009) to December 31, 2009, operating revenue and total gallons delivered to these new customers were $3.0 million and 1.1 million gallons. FPU’s total propane deliveries in the full calendar year 2009, including the deliveries for the period prior to the merger, were 5.7 million gallons.
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 the propane wholesale price volatility and supply levels. In 2009, Xeron had operating revenues totaling approximately $2.3 million, net of the associated cost of propane sold. For further discussion on 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.
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.
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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 registered in Delaware.
(c) Other 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, 2009, we had a total of 757 employees, including 332 employees who joined the Company as a result of the recent merger with FPU, 162 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 2010.
(iii) Financial Information about Geographic Areas
All of our material operations, customers, and assets occur and 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.
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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 Blvd., 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 1, 2009 that, as of that date, he was unaware of any violation by Chesapeake of the NYSE’s corporate governance listing standards.
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. Achieving these synergies, cost savings and operating efficiencies cannot be assured and failure to achieve these benefits will adversely affect expected future performance of the Company. In addition, the regulatory agencies that have jurisdiction over our regulated energy businesses and operations may require us to pass on some, or all, of the achieved cost savings to ratepayers.
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. The turmoil experienced in the credit markets in 2008 and 2009 and its potential impact on the liquidity of major financial institutions may have an adverse effect on our customers and our ability to fund our business strategy through borrowings, under either existing or newly created arrangements in the public or private markets on terms we believe to be reasonable. 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.
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Unsound financial institutions could adversely affect the Company.
Our businesses have exposure to different industries and counterparties, and may periodically execute transactions with counterparties in the financial services industry, including brokers and dealers, commercial banks, investment banks and other institutional clients. These transactions may expose us to credit risk in the event of default of a counterparty or client. There can be no assurance that any such losses or impairments would not materially and adversely affect our businesses and results of operations.
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.
The continuation of recent economic conditions could adversely affect our customers and negatively impact our financial results.
The slowdown in the U.S. economy, 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. 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.
Further changes in economic conditions and interest rates may adversely affect our results of operations and cash flows.
A continued downturn in the economies of the regions in which we operate might adversely affect our ability to increase our customer base and cash flows at historical rates. Further, 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, and to temporarily finance capital expenditures.
Inflation may impact our results of operations, cash flows and financial position.
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. To help cope with the effects of inflation on our capital investments and returns, we seek rate increases from regulatory commissions for regulated operations and closely monitor the returns of our unregulated operations. There can be no assurance that we will be able to obtain adequate and timely rate increases to offset the effects of inflation. To compensate for fluctuations in propane gas prices, we adjust our propane selling prices to the extent allowed by the market. There can be no assurance, however, that we will be able to increase propane sales prices sufficiently to compensate fully for such fluctuations in the cost of propane gas to us.
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Our operations are exposed to market risks, beyond our control, which could adversely affect our financial results and capital requirements.
Our natural gas marketing operation and propane wholesale marketing operation 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 the Company declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.
Current market conditions have had an adverse impact on the return on plan assets for our pension plans, which may require significant additional funding and adversely affect the Company’s 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 declined by $2.4 million and $2.8 million, respectively, 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. The difficulties of combining the companies’ operations include, among other things:
   
the necessity of coordinating geographically separated organizations, systems and facilities;
   
combining the best practices of the two companies, including operations, financial and administrative functions; and
   
integrating personnel with diverse business backgrounds and different contractual terms and conditions of employment.
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The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses and the loss of key personnel. We will be subject to employee workforce factors, including loss of employees, availability of qualified personnel, collective bargaining agreements with unions and work stoppages that could affect our business and financial condition. Our management team comprised of key personnel from both Chesapeake and FPU has dedicated substantial efforts to integrating the businesses. Such efforts could divert management’s focus and resources from other strategic opportunities during the integration process. The diversion of management’s attention and any delays or difficulties encountered in connection with the merger and the integration of the two companies’ operations 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 weather sensitive than natural gas and propane sales, 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.
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 both 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, all of FPU’s natural gas is transported 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.
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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/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.
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.
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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 will compete against 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 operation depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services, on a timely basis, and by keeping pace with technological developments and emerging industry standards. There is no assurance that we will be able to keep up with technological advancements to the degree necessary to keep our products and services competitive.
Our use of derivative instruments may adversely affect our results of operations.
Fluctuating commodity prices may affect our earnings and financing costs because our propane distribution and wholesale marketing operations use derivative instruments, including forwards, futures, swaps and puts, to hedge price risk. In addition, we have utilized in the past, and may decide, after further evaluation, to continue to utilize derivative instruments to hedge price risk. While we have 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 fuel sources. Slowdowns in these markets have and will continue to 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.
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Our facilities and operations could be targets of acts of terrorism.
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, which could adversely affect our results of operations, financial position and cash flows.
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. The occurrence of any of these events could adversely affect our results of operations, cash flows and financial condition.
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.
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Regulatory and Legal Risks
Regulation of the 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.
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 $50 million covering general liabilities of the 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.
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 resulted in approximately $33.4 million in purchase premium which is currently recorded as goodwill. We also incurred approximately $3.0 million in merger-related costs, $1.5 million of which was deferred as a regulatory asset. We will be seeking regulatory approval to include these amounts 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 achieve the anticipated benefits of the merger, the future regulatory environment in Florida and the future 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.
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.
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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.
We may be exposed to certain regulatory and financial risks related to climate change.
Climate change is receiving ever increasing attention from scientists, legislators and regulators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs, including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
   
result in increased costs associated with our operations;
   
increase other costs to our business;
   
affect the demand for natural gas, electricity and propane; and
   
impact the prices we charge our customers.
Any action taken by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows.
Pending environmental matters, particularly with respect to FPU’s site in West Palm Beach, Florida, may have a materially adverse effect on the 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 the 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.
Pursuant to a consent order that FPU entered into with the Florida Department of Environmental Protection (the “FDEP”) prior to our merger with FPU, FPU is obligated to assess and remediate environmental impacts to soil and groundwater resulting from operation of the former West Palm Beach MGP. Following completion of the assessment task, FPU retained a consultant to perform a feasibility study to evaluate appropriate remedies for the site to respond to the reported environmental impacts. The feasibility study was performed and subsequently revised as a result of additional testing conducted at the site and extensive discussions with FDEP. The revised feasibility study evaluates several alternative remedies for the site. Discussions with FDEP are continuing, regarding selection of an appropriate remedy for the West Palm Beach site. Our current estimate of total remediation costs and expenses, including legal and consulting expenses, for the West Palm Beach site based on the likely remedy we believe will be approved by FDEP is between $7.8 million and $19.4 million; however, actual costs may be higher or lower than such range based upon the final remedy required by FDEP.
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As of December 31, 2009, we had recorded $531,000 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 $1.7 million in assets for future recovery of environmental costs to be received from our customers through our approved rates. As of December 31, 2009, we had recorded approximately $12.3 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, 2009, 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 $12.3 million recorded as environmental liabilities related to FPU’s MGP sites in Florida as of December 31, 2009, we have recovered approximately $5.7 million of environmental costs from insurance and customers through rates, and have recorded approximately $6.6 million in assets for future recovery of environmental costs to be received from FPU’s customers through approved rates.
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 described above.
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, Marianna, Lantana, Lauderhill, Fernandina Beach and Winter Haven, Florida. We rent office space in Dover, Ocean View, and South Bethany, Delaware; Jupiter, 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 1,102 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 2,404 miles of natural gas distribution mains (and related equipment). Additionally, 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 384 miles of transmission pipeline, extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, 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 1,125 miles of electric distribution line located in northeast and northwest Florida.
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(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 the Company. Our Florida-based propane distribution operation owns 21 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.
(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: DeBary, Inglis, Marianna, Lantana, Lauderhill and Fernandina, Florida. FPU’s natural gas distribution operation owns 1,637 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 1,125 miles of electric distribution line located in northeast and northwest Florida. FPU’s propane distribution operation owns 18 bulk propane storage facilities with a total capacity of 576,000 gallons located in south and central Florida.
Item 3. Legal Proceedings.
(a) General
The Company and its subsidiaries are currently involved in various legal actions and claims arising in the normal course of business. The Company is 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 the Company’s consolidated financial position and results of operations.
(b) Environmental
See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note O, Environmental Commitments and Contingencies.”
Item 4. Submission of Matters to a Vote of Security Holders.
A special meeting of the shareholders of the Company was held on October 22, 2009, to consider and vote upon the following proposals:
  (1)  
A proposal related to adoption of the merger agreement and approval of the merger with Florida Public Utilities Company;
  (2)  
A proposal relating to the issuance of Chesapeake common stock in the merger; and
  (3)  
A proposal to approve adjournments or postponements of the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the end of the time in the special meeting to approve the above proposals.
The proposals were approved as follows:
                         
    Votes     Votes Against        
    For     or Withheld     Abstentions  
Adoption of the merger agreement and approval of the merger
    5,186,617       85,243       27,204  
Issuance of Chesapeake common stock in the merger
    5,186,617       85,243       27,204  
Approve adjournment or postponement
    4,846,740       411,960       40,365  
There were no broker non-votes.
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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
John R. Schimkaitis     62    
Vice Chairman and Chief Executive Officer
Michael P. McMasters     51    
President and Chief Operating Officer
Beth W. Cooper     43    
Senior Vice President and Chief Financial Officer
Stephen C. Thompson     49    
Senior Vice President and President, ESNG
Joseph Cummiskey     38    
Vice President and President, PESCO
John R. Schimkaitis is Vice Chairman and Chief Executive Officer of Chesapeake and its subsidiaries. Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. Mr. Schimkaitis previously served as President, Chief Operating Officer, Executive Vice President, Senior Vice President, Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer and Assistant Secretary of Chesapeake.
Michael P. McMasters is President and Chief Operating Officer of Chesapeake. Mr. McMasters assumed the role of President effective March 1, 2010. He has served as Chief Operating Officer since September of 2008. Prior to these appointments, Mr. McMasters served as 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.
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.
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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:
The Company’s common stock is listed on the NYSE under the symbol “CPK.” The high, low and closing prices of the Company’s common stock and dividends declared per share for each calendar quarter during the years 2009 and 2008 were as follows:
                                 
                            Dividends  
                            Declared  
Quarter Ended   High     Low     Close     Per Share  
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  
 
                       
 
                               
2008
                               
March 31
  $ 33.60     $ 27.21     $ 29.64     $ 0.295  
June 30
    31.88       25.02       25.72       0.305  
September 30
    34.84       24.65       33.21       0.305  
December 31
    34.66       21.93       31.48       0.305  
 
                       
Holders
At December 31, 2009, there were 2,670 holders of record of Chesapeake common stock.
Dividends
We have paid a cash dividend to common stock shareholders for 49 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. No securities were sold during the year 2009 that were not registered under the Securities Act of 1933, as amended.
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, 2009, Chesapeake’s cumulative consolidated net income base was $102.8 million, offset by Restricted Payments of $63.8 million, leaving $39.0 million of cumulative net income free of restrictions.
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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 2031, 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 2001. As of December 31, 2009, FPU had the cumulative net income base of $32.7 million, offset by restricted payments of $22.1 million, leaving $10.6 million of cumulative net income of FPU free of restrictions based on this covenant. In January 2010, this series of first mortgage bonds were redeemed prior to their maturities. The second most restricted covenant of this type is included in 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. This covenant provided FPU with the cumulative net income base of $56.0 million, offset by restricted payments of $37.6 million, leaving $18.4 million of cumulative net income of FPU free of restrictions as of December 31, 2009.
(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, 2009.
                                 
    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, 2009
                               
through October 31, 2009 (1)
    587     $ 30.14              
November 1, 2009
                               
through November 30, 2009
                       
December 1, 2009
                               
through December 31, 2009
                       
 
                       
Total
    587     $ 30.14              
 
                       
     
(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, 587 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, 2010, in connection with the Company’s Annual Meeting to be held on or about May 5, 2010 and, is incorporated herein by reference.
(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, 2009, 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 Performance Graph for the previous year included all but one of these same companies. Our 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., Energy 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.
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The comparison assumes $100 was invested on December 31, 2004 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)
                                                 
    2004     2005     2006     2007     2008     2009  
Chesapeake
  $ 100     $ 120     $ 124     $ 133     $ 137     $ 145  
Industry Index
  $ 100     $ 105     $ 125     $ 129     $ 139     $ 143  
S&P 500 Index
  $ 100     $ 105     $ 121     $ 128     $ 81     $ 102  
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Item 6. Selected Financial Data
                         
For the Years Ended December 31,   2009(3)     2008     2007  
Operating (1)
(in thousands)
                       
Revenues
                       
Regulated Energy
  $ 139,099     $ 116,468     $ 128,850  
Unregulated Energy
    119,973       161,290       115,190  
Other
    9,713       13,685       14,246  
 
                 
Total revenues
  $ 268,785     $ 291,443     $ 258,286  
 
                       
Operating income
                       
Regulated Energy
  $ 26,900     $ 24,733     $ 21,809  
Unregulated Energy
    8,158       3,781       5,174  
Other
    (1,322 )     (35 )     1,131  
 
                 
Total operating income
  $ 33,736     $ 28,479     $ 28,114  
 
                       
Net income from continuing operations
  $ 15,897     $ 13,607     $ 13,218  
 
                       
Assets
(in thousands)
                       
Gross property, plant and equipment
  $ 543,746     $ 381,689     $ 352,838  
Net property, plant and equipment (2)
  $ 436,428     $ 280,671     $ 260,423  
Total assets (2)
  $ 617,102     $ 385,795     $ 381,557  
Capital expenditures (1)
  $ 26,294     $ 30,844     $ 30,142  
 
                       
Capitalization
(in thousands)
                       
Stockholders’ equity
  $ 209,781     $ 123,073     $ 119,576  
Long-term debt, net of current maturities
    98,814       86,422       63,256  
 
                 
Total capitalization
  $ 308,595     $ 209,495     $ 182,832  
 
                       
Current portion of long-term debt
    35,299       6,656       7,656  
Short-term debt
    30,023       33,000       45,664  
 
                 
Total capitalization and short-term financing
  $ 373,917     $ 249,151     $ 236,152  
 
                 
     
(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)  
SFAS No. 143 (now codified within FASB ASC 360 and 410) was adopted in the year 2001; therefore, it was not applicable for the years prior to 2001.
 
(3)  
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 addition discussions and presentation of pro forma results.
 
(4)  
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.
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2006 (4)     2005     2004     2003     2002     2001     2000  
                                                     
                                                     
                                                     
$ 124,631     $ 124,563     $ 98,139     $ 92,079     $ 82,098     $ 87,444     $ 82,490  
  94,320       90,995       67,607       59,197       40,728       56,970       50,428  
  12,249       13,927       12,209       12,292       12,430       13,992       12,259  
                                       
$ 231,200     $ 229,485     $ 177,955     $ 163,568     $ 135,256     $ 158,406     $ 145,177  
                                                     
                                                     
$ 18,593     $ 16,248     $ 16,258     $ 16,219     $ 14,867     $ 14,060     $ 12,672  
  3,675       4,197       3,197       4,310       1,158       1,259       2,261  
  1,064       1,476       722       1,050       580       902       1,152  
                                       
$ 23,332     $ 21,921     $ 20,177     $ 21,579     $ 16,605     $ 16,221     $ 16,085  
                                                     
$ 10,748     $ 10,699     $ 9,686     $ 10,079     $ 7,535     $ 7,341     $ 7,665  
                                                     
                                                     
                                                     
$ 325,836     $ 280,345     $ 250,267     $ 234,919     $ 229,128     $ 216,903     $ 192,925  
$ 240,825     $ 201,504     $ 177,053     $ 167,872     $ 166,846     $ 161,014     $ 131,466  
$ 325,585     $ 295,980     $ 241,938     $ 222,058     $ 223,721     $ 222,229     $ 211,764  
$ 49,154     $ 33,423     $ 17,830     $ 11,822     $ 13,836     $ 26,293     $ 22,057  
                                                     
                                                     
                                                     
$ 111,152     $ 84,757     $ 77,962     $ 72,939     $ 67,350     $ 67,517     $ 64,669  
  71,050       58,991       66,190       69,416       73,408       48,409       50,921  
                                       
$ 182,202     $ 143,748     $ 144,152     $ 142,355     $ 140,758     $ 115,926     $ 115,590  
                                                     
  7,656       4,929       2,909       3,665       3,938       2,686       2,665  
  27,554       35,482       5,002       3,515       10,900       42,100       25,400  
                                       
$ 217,412     $ 184,159     $ 152,063     $ 149,535     $ 155,596     $ 160,712     $ 143,655  
                                       
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For the Years Ended December 31,   2009(3)     2008     2007  
Common Stock Data and Ratios
                       
Basic earnings per share from continuing operations (1)
  $ 2.17     $ 2.00     $ 1.96  
Diluted earnings per share from continuing operations (1)
  $ 2.15     $ 1.98     $ 1.94  
 
                       
Return on average equity from continuing operations (1)
    11.2 %     11.2 %     11.5 %
 
                       
Common equity / total capitalization
    68.0 %     58.7 %     65.4 %
Common equity / total capitalization and short-term financing
    56.1 %     49.4 %     50.6 %
 
                       
Book value per share
  $ 22.33     $ 18.03     $ 17.64  
 
                       
Market price:
                       
High
  $ 35.000     $ 34.840     $ 37.250  
Low
  $ 22.020     $ 21.930     $ 28.000  
Close
  $ 32.050     $ 31.480     $ 31.850  
 
                       
Average number of shares outstanding
    7,313,320       6,811,848       6,743,041  
Shares outstanding at year-end
    9,394,314       6,827,121       6,777,410  
Registered common shareholders
    2,670       1,914       1,920  
 
Cash dividends declared per share
  $ 1.25     $ 1.21     $ 1.18  
Dividend yield (annualized) (2)
    3.9 %     3.9 %     3.7 %
Payout ratio from continuing operations (1) (4)
    57.6 %     60.5 %     60.2 %
 
                       
Additional Data
                       
Customers (5)
                       
Natural gas distribution
    117,887       65,201       62,884  
Electric distribution
    31,030              
Propane distribution
    48,680       34,981       34,143  
 
                       
Volumes(6)
                       
Natural gas deliveries (in Mcfs)
    44,586,158       39,778,067       34,820,050  
Electric Distribution (in MWHs)
    105,739              
Propane distribution (in thousands of gallons)
    32,546       27,956       29,785  
 
                       
Heating degree-days (Delmarva Peninsula)
                       
Actual HDD
    4,729       4,431       4,504  
10-year average HDD (normal)
    4,462       4,401       4,376  
 
                       
Propane bulk storage capacity (in thousands of gallons)
    3,042       2,471       2,441  
 
                       
Total employees (1) (7)
    757       448       445  
     
(1)  
These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Companyclosed 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 addition 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.
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2006 (8)     2005     2004     2003     2002     2001     2000  
                                                     
$ 1.78     $ 1.83     $ 1.68     $ 1.80     $ 1.37     $ 1.37     $ 1.46  
$ 1.76     $ 1.81     $ 1.64     $ 1.76     $ 1.37     $ 1.35     $ 1.43  
                                                     
  11.0 %     13.2 %     12.8 %     14.4 %     11.2 %     11.1 %     12.2 %
                                                     
  61.0 %     59.0 %     54.1 %     51.2 %     47.8 %     58.2 %     55.9 %
  51.1 %     46.0 %     51.3 %     48.8 %     43.3 %     42.0 %     45.0 %
                                                     
$ 16.62     $ 14.41     $ 13.49     $ 12.89     $ 12.16     $ 12.45     $ 12.21  
                                                     
                                                     
$ 35.650     $ 35.780     $ 27.550     $ 26.700     $ 21.990     $ 19.900     $ 18.875  
$ 27.900     $ 23.600     $ 20.420     $ 18.400     $ 16.500     $ 17.375     $ 16.250  
$ 30.650     $ 30.800     $ 26.700     $ 26.050     $ 18.300     $ 19.800     $ 18.625  
                                                     
  6,032,462       5,836,463       5,735,405       5,610,592       5,489,424       5,367,433       5,249,439  
  6,688,084       5,883,099       5,778,976       5,660,594       5,537,710       5,424,962       5,297,443  
  1,978       2,026       2,026       2,069       2,130       2,171       2,166  
                                                     
$ 1.16     $ 1.14     $ 1.12     $ 1.10     $ 1.10     $ 1.10     $ 1.07  
  3.8 %     3.7 %     4.2 %     4.2 %     6.0 %     5.6 %     5.8 %
  65.2 %     62.3 %     66.7 %     61.1 %     80.3 %     80.3 %     73.3 %
                                                     
                                                     
                                                     
  59,132       54,786       50,878       47,649       45,133       42,741       40,854  
                                       
  33,282       32,117       34,888       34,894       34,566       35,530       35,563  
                                                     
                                                     
  34,321,160       34,980,939       31,429,494       29,374,818       27,934,715       27,263,542       30,829,509  
                                       
  24,243       26,178       24,979       25,147       21,185       23,080       28,469  
                                                     
                                                     
  3,931       4,792       4,553       4,715       4,161       4,368       4,730  
  4,372       4,436       4,389       4,409       4,393       4,446       4,356  
                                                     
  2,315       2,315       2,045       2,195       2,151       1,958       1,928  
                                                     
  437       423       426       439       455       458       471  
     
(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.
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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 and 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, 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 above, “Risk Factors.” They should be considered in connection with evaluating 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 excludes for comparison purposes, result of operations of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009 and 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 excludes 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.
(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 through expansion 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;
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maintaining a capital structure that enables us to access capital as needed;
   
maintaining a consistent and competitive dividend for shareholders; and
   
creating and maintaining diversified customer base, energy portfolio and utility foundation.
(b) Highlights and Recent Developments
On October 28, 2009, we completed the previously announced merger with FPU. As a result of the merger, FPU became a wholly-owned subsidiary of Chesapeake. The merger allowed us to become a larger energy company serving approximately 200,000 customers in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. 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. It also introduces us to the electric distribution business as it incorporates FPU’s approximately 31,000 electric customers in northwest and northeast Florida.
Total consideration paid by Chesapeake in the merger was approximately $75.7 million, which included approximately $16,000 paid in cash and 2,487,910 shares of common stock issued at a price per share of $30.42. Net fair value of the assets acquired and liabilities assumed in the merger was estimated at $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. All of the purchase premium paid in the merger was related to the regulated energy segment. Chesapeake also incurred approximately $3.0 million in merger-related costs related to consummating the merger, merger-related litigation costs and costs incurred in integrating operations of the two companies. As we intend to seek recovery through future rates of the premium paid and merger-related costs we incurred, we have deferred approximately $1.5 million of the merger-related costs as a regulatory asset as of December 31, 2009.
Our net income for 2009 was $15.9 million, or $2.15 per share (diluted), compared to $13.6 million, or $1.98 per share (diluted), for 2008. These results include approximately $1.5 million in costs expensed in 2009 and $1.2 million in costs related to our initial merger discussions with FPU, which were terminated in 2008. The 2009 results also include approximately $1.8 million in net income contributed by FPU for the period from the merger closing (October 28, 2009) to December 31, 2009. Excluding these merger-related items and net income contributed by FPU, our net income would have been $15.3 million and $14.3 million, or $2.20 per share (diluted) and $2.08 per share (diluted), in 2009 and 2008, respectively.
The following is a summary of key factors affecting our businesses and their impacts on our 2009 results. More detailed discussion and analysis are provided in the “Results of Operations” section.
   
Weather. Weather in 2009 was seven percent colder than 2008 and six percent colder than normal on the Delmarva Peninsula. We estimate that colder weather contributed approximately $1.6 million in additional gross margin for our regulated energy and unregulated energy operations on the Delmarva Peninsula in 2009 compared to 2008.
   
Growth. Customer growth continued to be affected by current economic conditions. Despite the slowdown in growth in the region, our Delaware and Maryland natural gas distribution divisions achieved customer growth in 2009 compared to 2008, which contributed $1.2 million in gross margin for the year. Chesapeake’s Florida natural gas distribution division experienced a net customer loss in 2009, which resulted in a gross margin decrease of $190,000. A loss of three large industrial customers in Florida in late 2008 and 2009 contributed primarily to this gross margin decrease. Our natural gas transmission subsidiary, ESNG, experienced continued growth in 2009 through new transmission services and new expansion facilities. New firm services to an industrial customer in 2009 contributed $811,000 to ESNG’s gross margin in 2009 and are expected to contribute approximately $1.1 million to its gross margin in 2010. New system expansions in November 2008 and 2009 also contributed $939,000 to its gross margin growth in 2009.
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Propane Prices. A sharp decline in propane prices in late 2008 resulted in inventory and swap valuation adjustments of $1.8 million in 2008, but allowed our Delmarva propane distribution operation to keep its propane cost low 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. Overall lack of volatility in wholesale propane prices reduced opportunities for our propane wholesale marketing subsidiary, Xeron, and decreased its trading volume by 57 percent in 2009 compared to 2008, which reduced its gross margin by approximately $1.0 million.
   
Natural Gas Spot Sale Opportunities. Our unregulated natural gas marketing subsidiary, PESCO, was able to identify various spot sale opportunities in 2009, which contributed significantly to the overall gross margin increase of $1.0 million in 2009. During 2009, PESCO sold natural gas and services of $10.6 million to Valero for its Delaware City refinery operation. Late in 2009, Valero announced its intention to permanently shut down that refinery. While PESCO’s sale to Valero in 2009 represented approximately 19 percent of PESCO’s total revenue for the year, spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
   
Rates and Regulatory Matters. In July 2009, Chesapeake’s Florida natural gas distribution division filed with the Florida PSC its petition for a rate increase. In August 2009, the Florida PSC approved an interim rate increase of approximately $418,000. In December 2009, the Florida PSC approved a permanent rate increase of approximately $2.5 million, applicable to all meters read on or after January 14, 2010. In December 2009, FPU’s natural gas distribution operation settled its request for a permanent rate increase, which had been approved by the Florida PSC in May 2009; however in June 2009, certain parts of the order approving the increase were protested by the Office of Public Counsel. The settlement allows an annual rate increase of approximately $8.0 million for FPU’s natural gas distribution operations.
   
Information Technology Spending. The state of the economy continued to affect overall information technology spending in 2009. Our advanced information services subsidiary, BravePoint, continued to experience lower consulting revenues as billable consulting hours declined by 28 percent in 2009 compared to 2008. We implemented cost-containment actions, including layoffs and compensation adjustments, which reduced operating costs in 2009 by $1.0 million. BravePoint’s professional database monitoring and support solution services, added $218,000 to its gross margin in 2009.
   
Interest Rates. We continued to experience low short-term interest rates throughout 2009 as our short-term weighted average interest rate decreased to 1.28 percent in 2009, compared to 2.79 percent in 2008. 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.
(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.
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Regulatory Assets and Liabilities
As a result of the ratemaking process, we record certain assets and liabilities in accordance with 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 $21.1 million and regulatory liabilities of $46.3 million, at December 31, 2009. 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 O, 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 manufactured gas plant 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, 2009, we have recorded an environmental regulatory asset of $7.5 million and a liability of $12.8 million for environmental costs.
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, 2009 and 2008:
   
During 2009 and 2008, our natural gas distribution, electric distribution, propane distribution and natural gas marketing operations entered into physical contracts for 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 the accrual basis of accounting.
   
During 2008, the propane distribution operation entered into a swap agreement to protect it from the impact of price increases on the Pro-Cap (propane price-cap) Plan that we offer to customers. The propane prices declined significantly in late 2008 and we recorded a mark-to-market adjustment of approximately $939,000, which increased our cost of propane sales in 2008. In January 2009, we terminated this swap agreement. During 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 $41,000.
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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, 2009 and 2008, these contracts had net unrealized losses of $1.6 million and net unrealized gains of $1.4 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 a recourse 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 income statement. 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.
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 the Company nor its 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.
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Pension and Other Postretirement Benefits
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, 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 $892,000, $537,000, and $370,000 in 2009, 2008 and 2007, respectively.  The Company expects to record pension and postretirement benefit costs in the range of $900,000 to $1.0 million for 2010 of which $275,000 is attributed to FPU’s pension and medical plans.   Actuarial assumptions affecting 2010 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 5.25 percent and 5.50 percent for Chesapeake’s plan and FPU’s plan, 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.
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 our intended use of those assets. Many of these fair value measurements can be highly subjective and it is also possible that others applying reasonable judgment to the same facts and circumstances could develop and support a range of alternative estimated amounts. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature and impact of regulations on those assets and liabilities 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 the value of net assets and future earnings of the Company.
Total consideration paid by Chesapeake in the merger was $75.7 million. Net fair value of the assets acquired and liabilities assumed in the merger was estimated to be $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. Item 8 under the heading “Notes to the Consolidated Financial Statements – Note B, Acquisitions and Dispositions” describes more fully the purchase price allocation.
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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. During 2009, we incurred approximately $3.0 million to consummate the merger, including the cost associated with merger-related litigation, and to integrate operations following the merger. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at December 31, 2009, 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. The remaining $1.5 million in costs have been expensed in our 2009 results.
(d) Results of Operations
                                                 
(in thousands except per share)                   Increase                     Increase  
For the Years Ended December 31,   2009     2008     (decrease)     2008     2007     (decrease)  
Business Segment:
                                               
Regulated Energy
  $ 26,900     $ 24,733     $ 2,167     $ 24,733     $ 21,809     $ 2,924  
Unregulated Energy
    8,158       3,781       4,377       3,781       5,174       (1,393 )
Other
    (1,322 )     (35 )     (1,287 )     (35 )     1,131       (1,166 )
 
                                   
Operating Income
    33,736       28,479       5,257       28,479       28,114       365  
 
                                               
Other Income
    165       103       62       103       291       (188 )
Interest Charges
    7,086       6,158       928       6,158       6,590       (432 )
Income Taxes
    10,918       8,817       2,101       8,817       8,597       220  
 
                                   
Net Income from Continuing Operations
    15,897       13,607       2,290       13,607       13,218       389  
Loss from Discontinued Operations
                            (20 )     20  
 
                                   
Net Income
  $ 15,897     $ 13,607     $ 2,290     $ 13,607     $ 13,198     $ 409  
 
                                   
Diluted Earnings (Loss) Per Share
                                               
Continuing operations
  $ 2.15     $ 1.98     $ 0.17     $ 1.98     $ 1.94     $ 0.04  
Discontinued operations
                                   
 
                                   
Diluted Earnings Per Share
  $ 2.15     $ 1.98     $ 0.17     $ 1.98     $ 1.94     $ 0.04  
 
                                   
As a result of the merger with FPU in 2009, we changed our operating segments to better align with how the chief operating decision maker (our Chief Executive Officer) views the various operations of the Company. We revised the segment information for all periods presented to reflect the new operating segments. Also during 2009, we decided not to allocate merger-related costs to our operating segments for the purpose of reporting their operating profitability, because such costs are not directly attributable to their operations. Consequently, all of the $1.5 million and $1.2 million of merger-related costs expensed in 2009 and 2008, respectively, are included in “Other” segment.
2009 compared to 2008
Our net income increased by approximately $2.3 million in 2009 compared to 2008. Net income was $15.9 million, or $2.15 per share (diluted), for 2009, compared to $13.6 million, or $1.98 per share (diluted), for 2008. Our 2009 results include approximately $1.8 million in net income from FPU for the period from the merger closing (October 28, 2009) to December 31, 2009. Our 2009 results also include approximately $1.5 million of merger-related costs expensed by the Company, compared to $1.2 million in merger-related costs expensed in 2008. Absent the effect of the merger and merger-related costs, we estimate that net income would have been $15.3 million, or $2.20 per share (diluted), in 2009, compared to $14.3 million, or $2.08 per share (diluted), in 2008.
During 2009, Chesapeake incurred approximately $3.0 million related to consummating the merger, merger-related litigation costs and costs of integrating operations of the two companies. New accounting standards applicable to acquisitions, which became effective in 2009, require companies to expense merger-related costs in the periods in which they are incurred. Under the previous accounting standards, most of these merger-related costs would have been considered a part of purchase price or liabilities assumed at the merger and thus not expensed. In accounting for our merger-related costs, we also considered the potential impact of the future regulatory process as we intend to seek recovery in future rates of the premium paid and merger-related costs incurred. Similar recovery treatment has been pursued successfully by other regulated utilities. As we account for our regulated operations in accordance with ASC Topic 980, “Regulated Operations,” certain costs that would otherwise have been expensed by unregulated enterprises may be deferred to reflect the potential impact of the regulatory and rate-making actions. With regard to the $3.0 million in merger-related costs incurred in 2009, we deferred approximately $1.5 million as a regulatory asset, which represents our estimate, based on similar proceedings in Florida in the past, of the costs that we expect to be permitted to recover when we complete the appropriate rate proceedings.
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During 2008, we incurred and expensed approximately $1.2 million in merger-related costs. These costs were related to our initial merger discussions with FPU, which were terminated in the second quarter of 2008.
Our operating income increased by $5.3 million in 2009 compared to 2008. Included in operating income for 2009 and 2008 are the $1.5 million and $1.2 million merger-related costs expensed in 2009 and 2008, respectively, which are included in the “Other” segments. Operating income from our regulated energy segment increased by $2.2 million in 2009. This increase is attributed to $3.0 million of FPU operating income for the period after the merger and an increase in operating income from the natural gas transmission operations through continued growth and new services. Offsetting those increases was a decrease in operating income from Chesapeake’s Florida natural gas distribution operation as a result of lower-than-expected customer growth and loss of industrial customers. Operating income for our unregulated energy segment increased by $4.4 million, which includes $553,000 in operating income from FPU after the merger. The Delmarva propane distribution operation contributed most of the increase in operating income by this segment. Delmarva propane distribution operation recorded $1.8 million in unfavorable propane inventory and swap valuation adjustments in 2008, which did not recur in 2009. These adjustments to the inventory costs in late 2008 and relatively low propane prices during the first half of 2009 allowed the Delmarva propane distribution operation to maintain low propane inventory costs while sustaining its retail margins. Operating income for the “Other” segment decreased by $1.3 million, primarily due to lower operating results by the advanced information services operation and higher merger-related costs expensed in 2009. The operating results of the advanced information services operation continued to be negatively affected by the lower levels of information technology spending experienced in the economy at large.
During 2009, we recognized increased corporate overhead costs of $1.2 million compared to 2008, which were allocated to all of our segments. Payroll and benefits costs in corporate overhead increased by $961,000 and $225,000, respectively, due to higher incentive compensation based on improved operating results and increased costs associated with filling several key corporate positions in 2008 and 2009. Also contributing to the increase were additional costs associated with investor relations and financial reporting activities and increased pension costs as a result of a decline in the value of pension investments in late 2008.
An increase of $928,000 in interest charges in 2009 compared to 2008 partially offset the increased operating results. This increase reflects primarily the interest expense on FPU’s long-term debt and customer deposits and the placement of the $30 million Unsecured Senior Notes in October 2008.
We continued to invest in property, plant and equipment in 2009 to support current and future growth opportunities, expending $26.3 million for such purposes.
2008 Compared to 2007
Our net income from continuing operations increased by $389,000 in 2008 compared to 2007. Net income from continuing operations was $13.6 million, or $1.98 per share (diluted), for 2008, compared to $13.2 million, or $1.94 per share (diluted), in 2007. Our 2008 results include a charge of $1.2 million for merger-related costs that were expensed in the second quarter of 2008 when our initial merger discussions with FPU were terminated. Absent the charge for the unconsummated acquisition, the Company estimates that period-over-period net income would have increased by $1.1 million in 2008 to $14.3 million, or $2.08 per share (diluted).
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During 2007, we decided to close the distributed energy services company, Chesapeake OnSight Services, LLC (“OnSight”), which consistently experienced operating losses since 2004. The results of operations for OnSight were classified to discontinued operations and shown net of tax. The discontinued operations experienced a net loss of $20,000 for 2007.
Our operating income increased by $365,000 in 2008 compared to 2007, including $1.2 million in merger-related costs expensed in 2008, which are included in the “Other” segment. Operating income from recurring operations increased by $1.5 million in 2008 compared to 2007. Our regulated energy segment achieved an increase of $2.9 million in operating income from new services provided by the natural gas transmission operation, four-percent customer growth for Chesapeake’s natural gas distribution operations and the successful completion of the Delaware rate proceedings. Our unregulated energy segment experienced a decrease in operating income of $1.4 million, primarily as a result of recording $1.8 million in unfavorable propane inventory and swap valuation adjustments for the Delmarva propane distribution operations in the second half of 2008. The propane inventory valuation adjustments were recorded to adjust the value of propane inventory and price swap agreements to current market prices as propane prices declined significantly during the second half of 2008. Operating income for the “Other” segment decreased by $1.2 million due to the merger-related costs.
During 2008, we experienced increased corporate overhead costs, which were allocated to all of our segments. The increase of $519,000 in corporate overhead costs in 2008 compared to 2007 resulted primarily from increased payroll and benefit costs of $132,000 and $83,000, respectively, as several key corporate positions that were vacant in 2007 were filled in 2008 and increased outside services of $263,000 were incurred primarily for consulting costs relating to an independent third-party compensation survey, strategic planning and growth initiatives.
A decrease of $432,000 in interest charges in 2008 compared to 2007 also contributed to the overall increase in net income in 2008. Even though banks were tightening their lending in response to the financial crisis, we were able to firm up our credit lines during this volatile period by increasing our total committed short-term borrowing capacity from $15.0 million to $55.0 million. In addition, on October 31, 2008, we executed a $30.0 million long-term debt placement of 5.93 percent Unsecured Senior Notes.
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We continued to invest in property, plant and equipment in 2008 to support current and future growth opportunities, expending $30.8 million for such purposes.
Regulated Energy
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2009     2008     (decrease)     2008     2007     (decrease)  
(in thousands)                                                
 
                                               
Revenue
  $ 139,099     $ 116,468     $ 22,631     $ 116,468     $ 128,850     $ (12,382 )
Cost of sales
    64,803       54,789       10,014       54,789       70,861       (16,072 )
 
                                   
Gross margin
    74,296       61,679       12,617       61,679       57,989       3,690  
 
                                               
Operations & maintenance
    32,569       25,369       7,200       25,369       25,061       308  
Depreciation & amortization
    8,866       6,694       2,172       6,694       6,918       (224 )
Other taxes
    5,961       4,883       1,078       4,883       4,201       682  
 
                                   
Other operating expenses
    47,396       36,946       10,450       36,946       36,180       766  
 
                                   
 
Operating Income
  $ 26,900     $ 24,733     $ 2,167     $ 24,733     $ 21,809     $ 2,924  
 
                                   
Heating Degree-Day (HDD) and Customer Analysis
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2009     2008     (decrease)     2008     2007     (decrease)  
Heating degree-day data — Delmarva
                                               
Actual HDD
    4,729       4,431       298       4,431       4,504       (73 )
10-year average HDD
    4,462       4,401       61       4,401       4,376       25  
 
                                               
Estimated gross margin per HDD
  $ 2,429     $ 1,937     $ 492     $ 1,937     $ 1,937     $ 0  
 
                                               
Estimated dollars per residential customer added:
                                               
Gross margin
  $ 375     $ 375     $ 0     $ 375     $ 372     $ 3  
Other operating expenses
  $ 100     $ 103     $ (3 )   $ 103     $ 106     $ (3 )
 
                                               
Average number of residential customers
                                               
Delmarva
    46,717       45,570       1,147       45,570       43,485       2,085  
Florida
    13,268       13,373       (105 )     13,373       13,250       123  
 
                                   
Total
    59,985       58,943       1,042       58,943       56,735       2,208  
 
                                   
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 are as follows:
   
Despite the continued slowdown in the new housing construction and industrial growth in the region, 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. 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 and we expect that trend to continue in the near future.
   
Colder weather on the Delmarva Peninsula contributed $449,000 to the increased gross margin, as heating degree days increased by 298, or seven percent, compared to 2008.
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The Delaware division’s new rate structure allows collection of miscellaneous service fees of $256,000, which, although not representing additional revenue, had previously been 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. The decrease in consumption is a result of conservation primarily by residential customers.
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 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 to gross margin of $99,000 due to implementation of interim 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 are 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: (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 and will contribute $1.1 million in gross margin in 2010.
   
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 intra-state 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.
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 is 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 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.
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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 factors previously discussed.
Other Developments
The following developments, which are not discussed above, may affect the future operating results of the regulated energy segment:
   
ESNG received notice from a customer of its intention not to renew two firm transmission service contracts, one of which expired in October 2009 and the other is expiring in March 2010. If these contracts are not renewed, or equivalent firm service capacity is not contracted to other customers, gross margin could be reduced by approximately $427,000 in 2010. ESNG also received notice from a smaller customer that it does not intend to renew its firm transmission service contract, which expires in April 2010. Revenue from this contract provides annualized gross margin of approximately $54,000.
   
In December 2009, the Florida PSC approved a permanent rate increase of approximately $2.5 million for Chesapeake’s Florida natural gas distribution division, applicable to all meters read on or after January 14, 2010. Also in December 2009, FPU’s natural gas distribution operation settled its request for a permanent rate increase, which was approved by the Florida PSC in May 2009; however, in June 2009, certain parts of the order were protested by the Office of Public Counsel. The settlement provides for an annual rate increase of approximately $8.0 million. As a result of the settlement, FPU refunded approximately $290,000 to its customers in February 2010, which represents revenues in excess of the amounts provided by the settlement agreement that had been billed to customers from June 4, 2009 to January 13, 2010.
   
The Delaware division is currently involved in a regulatory proceeding regarding the price it charged for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. The Hearing Examiner recommended, among others, a refund to our Delaware firm customers, which could be up to approximately $700,000, exclusive of any interest, as of December 31, 2009. We disagree with the Hearing Examiner’s recommendations and filed exceptions to those recommendations. We have not recorded a liability for this contingency based on our current assessment of the case. We anticipate a ruling by the Delaware PSC in March 2010. Item 8 under the heading, “Notes to the Consolidated Financial Statements – Note P, Other Commitments and Contingencies” provides further discussions on this matter.
2008 Compared to 2007
Operating income for the regulated energy segment increased by approximately $2.9 million in 2008 compared to 2007, which was attributable to a gross margin increase of $3.7 million, offset partially by an operating expense increase of $766,000.
Gross Margin
Gross margin for our regulated segment increased by $3.7 million, or six percent, of which $2.0 million was attributable to the natural gas distribution operations and $1.7 million to the natural gas transmission operation.
The Delmarva natural gas distribution operations generated an increase to gross margin of $1.8 million due to the following factors:
   
The average number of residential customers on the Delmarva Peninsula increased by 2,085, or five percent, for 2008, and we estimate that these additional residential customers contributed approximately $850,000 to gross margin in 2008.
   
Growth in commercial and industrial customers contributed $473,000 and $89,000, respectively, to gross margin in 2008.
   
Interruptible services revenue, net of required margin-sharing, increased by $307,000 as customers took advantage of lower natural gas prices compared to prices for alternative fuels.
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We estimate that weather contributed $122,000 to gross margin, despite temperatures on the Delmarva Peninsula being two percent warmer in 2008, compared to 2007.
   
Partially offsetting these increases to gross margin was the negative impact of lower consumption per customer in 2008 compared to 2007. We estimate that lower consumption per customer reduced gross margin by $118,000. The lower consumption reflects customer conservation efforts in light of higher energy costs, more energy-efficient housing, and current economic conditions.
Gross margin for the Florida natural gas distribution operation increased by $200,000 in 2008, compared to 2007. The higher gross margin for the period was attributable primarily to a one-percent growth in residential customers, an increase in non-residential customer volumes, and higher revenues from third-party natural gas marketers.
The natural gas transmission operation achieved gross margin growth of $1.7 million in 2008, $1.2 million of which was attributable to new transmission capacity contracts implemented in November 2007 and 2008. In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $439,000 to gross margin in 2008. The remaining $61,000 increase to gross margin was attributable primarily to higher interruptible sales revenue, net of required margin-sharing.
Other Operating Expenses
Other operating expenses for the regulated energy segment increased by approximately $766,000, due primarily to the following factors:
   
Payroll and benefit costs increased by $486,000 and $152,000, respectively, reflecting annual compensation increases and increased staff to support compliance with new federal pipeline integrity regulations and to serve the additional growth.
   
Depreciation expense and asset removal costs decreased by approximately $1.5 million, primarily as a result of our Delaware distribution operation’s rate proceedings in 2008 and ESNG’s rate settlement in September 2007, which provided for lower depreciation and asset removal cost allowances. Higher depreciation expense from the increased level of capital investment partially offset this decrease in 2008.
   
Property taxes increased by approximately $609,000 due to the higher level of capital investment and adjusted property assessments by various jurisdictions.
   
Vehicle-related costs increased by $132,000 due to higher fuel and depreciation charges.
   
Information technology costs increased by approximately $517,000 as a result of higher spending to improve the infrastructure, including system performance, disaster recovery and support.
   
Corporate overhead costs allocated to the regulated energy segment increased by approximately $385,000 as previously discussed.
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Unregulated Energy
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2009     2008     (decrease)     2008     2007     (decrease)  
(in thousands)                                                
 
Revenue
  $ 119,973     $ 161,290     $ (41,317 )   $ 161,290     $ 115,190     $ 46,100  
Cost of sales
    90,408       138,302       (47,894 )     138,302       91,727       46,575  
 
                                   
Gross margin
    29,565       22,988       6,577       22,988       23,463       (475 )
 
                                               
Operations & maintenance
    18,016       16,322       1,694       16,322       15,559       763  
Depreciation & amortization
    2,415       2,024       391       2,024       1,842       182  
Other taxes
    976       861       115       861       888       (27 )
 
                                   
Other operating expenses
    21,407       19,207       2,200       19,207       18,289       918  
 
                                   
 
Operating Income
  $ 8,158     $ 3,781     $ 4,377     $ 3,781     $ 5,174     $ (1,393 )
 
                                   
Propane Heating Degree-Day (HDD) Analysis — Delmarva
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2009     2008     (decrease)     2008     2007     (decrease)  
Heating degree-days
                                               
Actual
    4,729       4,431       298       4,431       4,504       (73 )
10-year average
    4,462       4,401       61       4,401       4,376       25  
 
                                               
Estimated gross margin per HDD
  $ 3,083     $ 2,465     $ 618     $ 2,465     $ 1,974     $ 491  
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 volume 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 allowed 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.
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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 is 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 in compliance with United States Department of Transportation standards.
   
Corporate overhead allocated to the unregulated energy segment increased by approximately $568,000 as previously discussed.
   
These increases were partially offset by lower vehicle-related costs of $176,000, primarily due to a decrease in the cost of fuel.
Other Developments
The following developments, which are not discussed above, may affect the future operating results of the unregulated energy segment:
   
On November 20, 2009, Valero announced that it was permanently shutting down its refinery operation located in Delaware City, Delaware. During 2009, PESCO sold natural gas and services for $10.6 million to Valero. PESCO’s natural gas sales to Valero were on a spot sale basis. PESCO’s sale to Valero represented 19 percent of its total sales in 2009. Spot sales are not predictable, and therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
   
In February 2010, Sharp, our Delmarva propane distribution subsidiary, purchased the operating assets of a regional propane distributor serving approximately 1,000 retail customers in Northampton and Accomack, Virginia.
2008 Compared to 2007
Operating income for the unregulated energy segment decreased by approximately $1.4 million, or 27 percent, in 2008 compared to 2007, which was attributable to a gross margin decline of $475,000 and an operating expense increase of $918,000.
Gross Margin
The period-over-period decrease in gross margin of $475,000, or two percent, for the unregulated energy segment was due to $2.9 million in decreased gross margin for the propane distribution operations, which was offset by the increase to gross margin of $901,000 for the propane wholesale marketing operation and $1.5 million for the natural gas marketing operation.
The Delmarva propane distribution operation’s decrease in gross margin of $3.1 million resulted from the following:
   
Gross margin decreased by $1.1 million in 2008, compared to 2007, primarily because of a $0.04 decrease in the average gross margin per retail gallon attributable to inventory write-downs of approximately $800,000 during 2008 in response to market prices below the Company’s inventory price per gallon.
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Wholesale propane prices rose dramatically during the spring of 2008, when they traditionally fall. In efforts to protect the Company from the impact that additional price increases would have on our Pro-Cap (propane price cap) Plan, the propane distribution operation entered into a swap agreement. By the end of the period, the market price of propane had plummeted well below the unit price in the swap agreement. As a result, we marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales by $939,000 in 2008. In January 2009, we terminated this swap agreement.
   
Non-weather-related volumes sold in 2008 decreased by 1.2 million gallons, or five percent. This decrease in gallons sold reduced gross margin by approximately $867,000 for the Delmarva propane distribution operation. Factors contributing to this decrease in gallons sold included customer conservation and the timing of propane deliveries.
   
Margins per gallon on the Pro-Cap Plan for the last four months of 2008 recovered to a level just $113,000 below the prior year’s levels, despite realizing a charge to cost of sales of $494,000 as the December gallons related to this plan were valued at current market prices.
   
Temperatures on the Delmarva Peninsula were two percent warmer in 2008 compared to 2007, which contributed to a decrease of 248,000 gallons sold, or one percent. We estimated that the warmer weather and decreased volumes sold had a negative impact of approximately $180,000 on gross margin for the Delmarva propane distribution operation.
   
Gross margin from miscellaneous fees, including items such as tank and meter rentals and marketing pricing programs, increased by $271,000.
The Florida propane distribution operation experienced an increase in gross margin of $181,000 in 2008, compared to 2007. The higher gross margin resulted from increases of four percent and 10 percent in the number of gallons sold to residential and commercial customers, respectively, combined with a higher average gross margin per retail gallon.
Gross margin for the propane wholesale marketing operation increased by $901,000 in 2008, compared to 2007. This increase reflects the operation capitalizing on a larger number of market opportunities that arose in 2008 due to price volatility in the propane wholesale market. This volatility created an opportunity for the operation to capture larger price-spreads between sales contracts and purchase contracts in addition to larger spreads between the market (spot) prices and forward propane prices.
Gross margin for the natural gas marketing operation increased by $1.5 million for 2008, compared to 2007. The increase in gross margin was due to enhanced sales contract terms, margins on spot sales of approximately $600,000 and 26-percent growth in its customer base. The increased customer base contributed to a 41-percent increase in volumes sold in 2008.
Other Operating Expenses
Other operating expenses for the unregulated energy segment increased by $918,000 due primarily to the following factors:
   
Payroll and benefit costs decreased by $186,000, due primarily to lower accrual for incentive compensation as a result of lower operating results in 2008.
   
Vehicle-related costs increased by $207,000 as a result of higher fuel costs and continued maintenance of our delivery trucks.
   
Depreciation and amortization expense increased by $182,000 as a result of an increase in our capital investments, primarily in Community Gas Systems.
   
The allowance for uncollectible accounts increased by $436,000 due to increased revenue.
   
Maintenance expense decreased by $193,000, due primarily to additional costs in 2007 associated with propane tank recertifications and maintenance to comply with the Department of Transportation standards.
   
Information technology costs increased by approximately $153,000 as a result of higher spending to improve the infrastructure, including system performance, disaster recovery and support.
   
Corporate overhead costs increased by approximately $204,000 as previously discussed.
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Other
                                                 
                    Increase                     Increase  
For the Years Ended December 31,   2009     2008     (decrease)     2008     2007     (decrease)  
(in thousands)                                                
 
                                               
Revenue
  $ 11,998     $ 15,373     $ (3,375 )   $ 15,373     $ 15,721     $ (348 )
Cost of sales
    6,036       8,034       (1,998 )     8,034       8,260       (226 )
 
                                   
Gross margin
    5,962       7,339       (1,377 )     7,339       7,461       (122 )
 
                                               
Operations & maintenance
    4,859       5,206       (347 )     5,206       5,333       (127 )
Transaction-related costs
    1,478       1,153       325       1,153             1,153  
Depreciation & amortization
    310       290       20       290       304       (14 )
Other taxes
    640       728       (88 )     728       697       31  
 
                                   
Other operating expenses
    7,287       7,377       (90 )     7,377       6,334       1,043  
 
                                               
Operating Income — Other
    (1,325 )     (38 )     (1,287 )     (38 )     1,127       (1,165 )
Operating Income — Eliminations
    3       3             3       4       (1 )
 
                                   
 
Operating Income
  $ (1,322 )   $ (35 )   $ (1,287 )   $ (35 )   $ 1,131     $ (1,166 )
 
                                   
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 operation 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 is a result of current economic conditions in which information technology spending has not rebounded. The decrease in consulting revenues was partially offset with an increase of $218,000 from BravePoint’s professional database monitoring and support solution services, and increased product sales of $140,000. While there have been some improvement in recent months, we do not expect customers’ information technology spending to return to historical levels in the foreseeable future given the current economic climate.
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 service operation in 2009 to reduce costs to offset the decline in revenues. This decrease was offset by the increased merger-related costs.
2008 Compared to 2007
Operating income for the “Other” segment decreased by approximately $1.2 million in 2008 compared to 2007, which was attributable to a gross margin decrease of $122,000 and an operating expense increase of $1.0 million.
Gross margin
Our advanced information services operation contributed most of the gross margin for the “Other” segment. Gross margin for our advanced services operation declined by approximately $152,000, which was attributable to a decrease of $610,000 in consulting revenues as higher average billing rates were not able to overcome a nine-percent decrease in the number of billable consulting hours. The reduction in the number of billable hours was a result of economic conditions in which information technology spending broadly declined. The decrease in consulting revenues was partially offset with increased product sales and training revenues of $403,000 and $47,000, respectively.
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The increase in other operating expenses in 2008 was primarily related to $1.2 million in merger-related costs in 2008 that were expensed in the second quarter of 2008 when initial discussions with FPU regarding a potential merger were terminated. Other operating expenses for our advanced information services operation remained relatively unchanged in 2008 compared to 2007.
Other Income
Other income for 2009, 2008 and 2007 was $163,000, $103,000 and $291,000, respectively, which includes interest income, late fees charged to customers and gains or losses from the sale of assets.
Interest Expense
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 is 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 unchanged at 6.37 percent in 2009, compared to 6.40 percent in 2008.
   
Interest expense in short-term borrowing 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 as well as a decrease in working capital requirements in 2009, compared to 2008, 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 the increased working capital needs as a result of the FPU merger. Also contributing to the decrease in interest expense in short-term borrowing 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.
In January 2010, we redeemed $28.7 million of the secured first mortgage bonds with a carrying value of $27.2 million to increase financial flexibility by reducing the amount of the FPU secured long-term debt and maintaining compliance with the covenants in our unsecured senior notes.
2008 Compared to 2007
Total interest expense for 2008 decreased by approximately $432,000, or seven percent, compared to 2007. The lower interest expense is primarily the result of the following:
   
Interest on long-term debt decreased by $263,000 in 2008, compared to 2007, as we reduced our average long-term debt balance and weighted average interest rate. Our average long-term debt balance during 2008 was $76.2 million, with a weighted average interest rate of 6.40 percent, compared to $76.5 million, with a weighted average interest rate of 6.71 percent, for the same period in 2007.
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Other interest charges decreased by $127,000 as higher amounts of interest capitalized were partially offset by interest accrued on pending customer refunds.
   
Interest on short-term borrowings decreased by $42,000 in 2008 compared to 2007, as the weighted average interest rate was nearly 2.7 percentage points lower in 2008 offsetting a $17.7 million increase in our average short-term borrowing balance. Our average short-term borrowing during 2008 was $38.3 million, with a weighted average interest rate of 2.79 percent, compared to $20.6 million, with a weighted average interest rate of 5.46 percent, for 2007.
Income Taxes
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 were 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.
2008 Compared to 2007
Income tax expense was $8.8 million in 2008, compared to $8.6 million in 2007, representing an increase of $200,000. Our effective income tax rate for 2008 and 2007 remained primarily unchanged at 39.3 percent and 39.4 percent, respectively. The increase in income tax expense reflects the increased taxable income in 2008.
Discontinued Operations
During 2007, we decided to close the distributed energy services subsidiary, OnSight, which had experienced operating losses since its inception in 2004. The results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. The discontinued operations experienced a net loss of $20,000 for 2007. We did not have any discontinued operations in 2008 and 2009.
(e) Liquidity and Capital Resources
Our capital requirements reflect the capital-intensive nature of our business and are principally attributable to investment in new plant and equipment and retirement of outstanding debt. We rely on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures.
During 2009, net cash provided by operating activities was $45.8 million, cash used in investing activities was $23.1 million, and cash used in financing activities was $21.4 million. Cash provided during 2009 includes approximately $359,000 of net cash acquired in the merger with FPU.
During 2008, net cash provided by operating activities was $28.5 million, cash used by investing activities was $31.2 million, and cash provided by financing activities was $1.7 million.
During 2007, net cash provided by operating activities was $25.7 million, cash used by investing activities was $31.3 million, and cash provided by financing activities was $3.7 million.
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As of December 31, 2009, we had four unsecured bank lines of credit with two financial institutions, for a total of $90.0 million, none of which requires compensating balances. In January 2010, the total unsecured bank lines of credit increased to $100.0 million, none of which requires compensating balances. These bank lines are available 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. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these short-term lines of credit. In response to the instability and volatility of the financial markets during 2008, we solidified our lines of credit by converting $40.0 million of available credit under uncommitted lines to committed lines of credit. Currently, two of the bank lines, totaling $60.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The outstanding balance of short-term borrowing at December 31, 2009 and 2008 was $30.0 million and $33.0 million, respectively. The level of short-term debt was reduced in late 2008 and throughout 2009 with funds provided from the placement of $30 million of 5.93 percent Unsecured Senior Notes in October 2008. This reduction was offset in late 2009 by the increased working capital requirements after the FPU merger.
We have budgeted $53.9 million for capital expenditures during 2010. This amount includes $49.2 million for the regulated energy segment, $3.3 million for the unregulated energy segment and $1.4 million for the “Other” segment. The amount for the regulated energy segment includes estimated capital expenditures for the following: natural gas distribution operation ($20.2 million), natural gas transmission operation ($25.4 million) and electric distribution operation ($3.6 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 an estimated capital expenditure of $288,000 for the advanced information services operation with the remaining balance for other general plant, computer software and hardware. We expect to fund the 2010 capital expenditures program from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure 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.
Capital Structure
In consummating the FPU merger, Chesapeake issued 2,487,910 shares of its common stock, valued at approximately $75.7 million, in exchange for all outstanding common stock of FPU. We also became subject to FPU’s long-term debt of $47.8 million as a result of the merger. The following presents our capitalization as of December 31, 2009 and 2008:
                                 
    December 31,     December 31,  
(in thousands)   2009     2008  
 
                               
Long-term debt, net of current maturities
  $ 98,814       32 %   $ 86,422       41 %
Stockholders’ equity
    209,781       68 %     123,073       59 %
 
                       
Total capitalization, excluding short-term debt
  $ 308,595       100 %   $ 209,495       100 %
 
                       
As of December 31, 2009, common equity represented 68 percent of total capitalization, compared to 59 percent at December 31, 2008. As of December 31, 2009, we classified as a current portion of long-term debt two series of FPU’s secured first mortgage bonds in the amount of approximately $27.2 million because we redeemed them in January 2010 prior to their stated maturities in order to maintain increased financial flexibility and compliance with the covenants in our Unsecured Senior Notes. We used the short-term borrowing to finance the redemption of these bonds.
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The following presents our capitalization as of December 31, 2009 and 2008, if short-term borrowing and the current portion of long-term debt were included in capitalization:
                                 
    December 31,     December 31,  
(in thousands)   2009     2008  
 
Short-term debt
  $ 30,023       8 %   $ 33,000       13 %
Long-term debt, including current maturities
    134,113       36 %     93,078       38 %
Stockholders’ equity
    209,781       56 %     123,073       49 %
 
                       
Total capitalization, including short-term debt
  $ 373,917       100 %   $ 249,151       100 %
 
                       
Excluding $75.7 million of the value of Chesapeake’s common stock issued in the merger and $47.8 million of FPU’s long-term debt included in our Consolidated Balance Sheet at December 31, 2009, total capitalization increased by $1.3 million in 2009.
We remain 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.
Cash Flows Provided by Operating Activities
Our cash flows provided by operating activities were as follows:
                         
For the Years Ended December 31,   2009     2008     2007  
(in thousands)                        
Net income
  $ 15,897     $ 13,607     $ 13,198  
Non-cash adjustments to net income
    28,319       22,919       15,829  
Changes in assets and liabilities
    1,593       (7,982 )     (3,346 )
 
                 
Net cash from operating activities
  $ 45,809     $ 28,544     $ 25,681  
 
                 
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.
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.
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In 2009, our net cash flow provided by operating activities was $45.8 million, an increase of $17.3 million compared to 2008. This increase includes $4.7 million in net cash flow provided by the operating activities of FPU after the merger. The remaining increase was due primarily to the following:
   
Net cash flows from the change in income taxes receivable and non-cash adjustments for deferred income taxes were related to continued higher tax deductions provided by bonus depreciation, which resulted in net federal income tax refunds received in 2009 and continued to create higher book-to-tax timing differences;
   
Net cash flows from changes in accounts receivable and accounts payable were due primarily to the timing of collections and payments of trading contracts entered into by our propane wholesale marketing operation; and
   
Net cash flows from the increase in regulatory liabilities were due primarily to higher over-collection of purchased gas costs by our Delmarva natural gas distribution operation.
In 2008, our net cash flow provided by operating activities was $28.5 million, an increase of $2.9 million compared to 2007. The increase was due primarily to the following:
   
Net cash flows from changes in accounts receivable and accounts payable were 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 is 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.
Cash Flows Used in Investing Activities
In 2009, net cash flows used by investing activities totaled $23.1 million, a decrease of $8.1 million compared to 2008. In 2008, net cash flows used by investing activities totaled $31.2 million, which remained relatively unchanged from net cash flows used by investing activities of $31.3 million in 2007.
   
We acquired $359,000 in cash, net of cash paid, in the merger with FPU in 2009.
   
We received $3.5 million in proceeds from an investment account related to future environmental costs, which was previously included as a non-current investment, as we transferred the amount to our general account that invests in overnight income-producing securities. Our general account is considered cash equivalent.
   
Cash utilized for capital expenditures was $26.6 million, $30.8 million and $31.3 million for 2009, 2008, and 2007, respectively.
   
Environmental expenditures exceeded amounts recovered through rates charged to customers in 2009, 2008 and 2007 by $418,000, $480,000 and $228,000, respectively.
   
Sales of property, plant, and equipment generated $205,000 of cash in 2007.
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Cash Flows Provided by Financing Activities
In 2009, net cash flows used by financing activities totaled $21.4 million, compared to net cash flow provided by financing activities of $1.7 million and $3.7 million in 2008 and 2007, respectively. Significant financing activities included the following:
   
During 2009 and 2008, we reduced our short-term debt by $3.8 million and $12.0 million, respectively. During 2007, net borrowing of short-term debt increased by $18.7 million, primarily to support our capital investments.
   
In October 2008, we completed the placement of $30.0 million of 5.93 percent Unsecured Senior Notes.
   
We repaid $10.9 million of long-term debt during 2009, compared to $7.7 million of long-term debt repaid during each of 2008 and 2007.
   
We paid $8.0 million, $7.8 million and $7.0 million in cash dividends in 2009, 2008 and 2007, respectively. An increase in cash dividends paid in each year reflects the growth in the annualized dividend rate.
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2009:
                                         
    Payments Due by Period  
    Less than 1                     More than 5        
Contractual Obligations   year     1 - 3 years     3 - 5 years     years     Total  
(in thousands)                                        
 
                                       
Long-term debt (1)
  $ 36,765     $ 17,293     $ 20,793     $ 60,818     $ 135,669  
 
                                       
Operating leases (2)
    866       1,449       865       2,031       5,211  
 
                                       
Purchase obligations (3)
                                       
Transmission capacity
    11,133       38,589       20,447       63,028       133,197  
Storage — Natural Gas
    530       6,600       2,001       968       10,099  
Commodities
    54,802       341                   55,143  
Electric supply
    574       1,149       1,149       2,298       5,170  
Forward purchase contracts — Propane (4)
    12,570                         12,570  
Other
    1,557       16                   1,573  
Unfunded benefits (5)
    371       1,504       847       4,926       7,648  
Funded benefits (6)
    2,090       79       670       1,170       4,009  
 
                             
Total Contractual Obligations
  $ 121,258     $ 67,020     $ 46,772     $ 135,239     $ 370,289  
 
                             
     
(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 $7.5 million, $12.6 million, $10.1 million and $17.3 million, respectively, for the periods indicated above. Expected interest payments for all periods total $47.6 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 P, 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 the Management’s Discussion and Analysis for further information.
 
(5)  
We have recorded long-term liabilities of $7.6 million at December 31, 2009 for unfunded post-employment and post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes 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 $12.7 million at December 31, 2009 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 $2.0 million, reflecting the expected payments the Company will make to the trust funds in 2010. 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 $2.0 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.
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Off-Balance Sheet Arrangements
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, 2009 was $22.7 million, with the guarantees expiring on various dates in 2010.
In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $725,000, which expires on August 31, 2010. The letter of credit is provided as security to satisfy the deductibles under our various insurance policies. There have been no draws on this letter of credit as of December 31, 2009.
(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, 2009, 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 P, Other Commitments and Contingencies.”
(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 O, 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 $134.1 million at December 31, 2009, as compared to a fair value of $145.5 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 four 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.
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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 counter-party 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.
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 counter-parties, 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, 2009 and 2008 is presented in the following tables.
                     
    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.
                     
    Quantity in     Estimated Market   Weighted Average  
At December 31, 2008   gallons     Prices   Contract Prices  
Forward Contracts
                   
Sale
    10,626,000     $0.5450 — $1.9100   $ 0.9984  
Purchase
    9,949,800     $0.7000 — $1.9600   $ 1.0233  
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expired in 2009.
At December 31, 2009 and 2008, 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)   2009     2008  
Mark-to-market energy assets
  $ 2,379     $ 4,482  
Mark-to-market energy liabilities
  $ 2,514     $ 3,052  
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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.
(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 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.
The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them than does the Company. 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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(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.
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 that, 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. Chesapeake is in the process of integrating FPU’s operations and has not included FPU’s activity in its 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 and Dispositions” for additional information relating to the FPU merger. FPU’s operations constituted approximately 30 percent of total assets (excluding goodwill and other intangible assets) as of December 31, 2009, and 10 percent of operating revenues for the year then ended. FPU’s operations will be included in Chesapeake’s assessment as of December 31, 2010.
Chesapeake’s management has evaluated and concluded that Chesapeake’s internal control over financial reporting was effective as of December 31, 2009.
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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 as of December 31, 2009 and 2008, 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, 2009. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009 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, 2009, 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, 2010 expressed an unqualified opinion.
 
 
     
/s/ ParenteBeard LLC
 
ParenteBeard LLC
   
Malvern, Pennsylvania
   
March 8, 2010
   
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Consolidated Statements of Income
                         
For the Years Ended December 31,   2009     2008     2007  
(in thousands, except shares and per share data)                        
 
                       
Operating Revenues
                       
Regulated Energy
  $ 139,099     $ 116,468     $ 128,850  
Unregulated Energy
    119,973       161,290       115,190  
Other
    9,713       13,685       14,246  
 
                 
Total operating revenues
    268,785       291,443       258,286  
 
                 
 
                       
Operating Expenses
                       
Regulated energy cost of sales
    64,803       54,789       70,861  
Unregulated energy cost of sales
    95,467       145,854       99,987  
Operations
    50,706       43,476       42,243  
Transaction-related costs
    1,478       1,153        
Maintenance
    3,430       2,215       2,236  
Depreciation and amortization
    11,588       9,005       9,060  
Other taxes
    7,577       6,472       5,785  
 
                 
Total operating expenses
    235,049       262,964       230,172  
 
                 
 
                       
Operating Income
    33,736       28,479       28,114  
Other income, net of other expenses
    165       103       291  
Interest charges
    7,086       6,158       6,590  
 
                 
 
Income Before Income Taxes
    26,815       22,424       21,815  
Income taxes
    10,918       8,817       8,597  
 
                 
 
Net Income from continuing operations
    15,897       13,607       13,218  
Loss from discontinued operations, net of tax benefit of $0, $0 and $11
                (20 )
 
                 
Net Income
  $ 15,897     $ 13,607     $ 13,198  
 
                 
 
                       
Weighted Average Common Shares Outstanding:
                       
Basic
    7,313,320       6,811,848       6,743,041  
Diluted
    7,440,201       6,927,483       6,854,716  
 
Earnings Per Share of Common Stock:
                       
Basic
                       
From continuing operations
  $ 2.17     $ 2.00     $ 1.96  
From discontinued operations
                 
 
                 
Net Income
  $ 2.17     $ 2.00     $ 1.96  
 
                 
Diluted
                       
From continuing operations
  $ 2.15     $ 1.98     $ 1.94  
From discontinued operations
                 
 
                 
Net Income
  $ 2.15     $ 1.98     $ 1.94  
 
                 
 
                       
Cash Dividends Declared Per Share of Common Stock
  $ 1.250     $ 1.210     $ 1.175  
 
                 
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 61

 

 


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Consolidated Statements of Cash Flows
                         
For the Years Ended December 31,   2009     2008     2007  
(in thousands)                        
 
                       
Operating Activities
                       
Net Income
  $ 15,897     $ 13,607     $ 13,198  
Adjustments to reconcile net income to net operating cash:
                       
Depreciation and amortization
    11,588       9,005       9,060  
Depreciation and accretion included in other costs
    2,789       2,239       3,337  
Deferred income taxes, net
    10,065       11,442       1,831  
Gain on sale of assets
                (205 )
Unrealized (gain) loss on commodity contracts
    1,606       (1,252 )     (65 )
Unrealized (gain) loss on investments
    (212 )     509       (123 )
Employee benefits and compensation
    1,217       152       1,004  
Share based compensation
    1,306       820       990  
Other, net
    (40 )     4        
Changes in assets and liabilities:
                       
Sale (purchase) of investments
    (146 )     (201 )     229  
Accounts receivable and accrued revenue
    (13,652 )     19,411       (28,189 )
Propane inventory, storage gas and other inventory
    2,597       (1,730 )     1,193  
Regulatory assets
    (1,842 )     411       (345 )
Prepaid expenses and other current assets
    (747 )     (1,182 )     (1,186 )
Other deferred charges
    (83 )     (153 )     (2,478 )
Long-term receivables
    191       207       84  
Accounts payable and other accrued liabilities
    10,185       (15,033 )     22,024  
Income taxes receivable
    5,020       (6,155 )     (159 )
Accrued interest
    66       158       33  
Customer deposits and refunds
    (75 )     (502 )     2,535  
Accrued compensation
    (2,066 )     (175 )     946  
Regulatory liabilities
    1,071       (3,107 )     2,124  
Other liabilities
    1,074       69       (157 )
 
                 
Net cash provided by operating activities
    45,809       28,544       25,681  
 
                 
 
Investing Activities
                       
Property, plant and equipment expenditures
    (26,603 )     (30,756 )     (31,277 )
Proceeds from sale of assets
                205  
Proceeds from investments
    3,519              
Cash acquired in the merger, net of cash paid
    359              
Environmental expenditures
    (418 )     (480 )     (228 )
 
                 
Net cash used by investing activities
    (23,143 )     (31,236 )     (31,300 )
 
                 
 
Financing Activities
                       
Common stock dividends
    (7,957 )     (7,810 )     (7,030 )
Issuance of stock for Dividend Reinvestment Plan
    392       (118 )     299  
Change in cash overdrafts due to outstanding checks
    835       (684 )     (541 )
Net borrowing (repayment) under line of credit agreements
    (3,812 )     (11,980 )     18,651  
Proceeds from issuance of long-term debt
          29,961        
Repayment of long-term debt
    (10,907 )     (7,658 )     (7,656 )
 
                 
Net cash provided by (used in) financing activities
    (21,449 )     1,711       3,723  
 
                 
 
Net Increase (Decrease) in Cash and Cash Equivalents
    1,217       (981 )     (1,896 )
Cash and Cash Equivalents — Beginning of Period
    1,611       2,592       4,488  
 
                 
Cash and Cash Equivalents — End of Period
  $ 2,828     $ 1,611     $ 2,592  
 
                 
Supplemental Cash Flow Disclosures (see Note D)
The accompanying notes are an integral part of the financial statements.
Page 62     Chesapeake Utilities Corporation 2009 Form 10-K

 

 


Table of Contents

Consolidated Balance Sheets
                 
    December 31,     December 31,  
Assets   2009     2008  
(in thousands, except shares and per share data)  
 
Property, Plant and Equipment
               
Regulated energy
  $ 463,856     $ 316,125  
Unregulated energy
    61,360       51,827  
Other
    16,054       12,255  
 
           
Total property, plant and equipment
    541,270       380,207  
Less: Accumulated depreciation and amortization
    (107,318 )     (101,018 )
Plus: Construction work in progress
    2,476       1,482  
 
           
Net property, plant and equipment
    436,428       280,671  
 
           
 
               
Investments
    1,959       1,601  
 
           
 
               
Current Assets
               
Cash and cash equivalents
    2,828       1,611  
Accounts receivable (less allowance for uncollectible accounts of $1,609 and $1,159, respectively)
    70,029       52,905  
Accrued revenue
    12,838       5,168  
Propane inventory, at average cost
    7,901       5,711  
Other inventory, at average cost
    3,149       1,479  
Regulatory assets
    1,205       826  
Storage gas prepayments
    6,144       9,492  
Income taxes receivable
    2,614       7,443  
Deferred income taxes
    1,498       1,578  
Prepaid expenses
    5,843       4,679  
Mark-to-market energy assets
    2,379       4,482  
Other current assets
    147       147  
 
           
Total current assets
    116,575       95,521  
 
           
 
               
Deferred Charges and Other Assets
               
Goodwill
    34,095       674  
Other intangible assets, net
    3,951       164  
Long-term receivables
    343       533  
Regulatory assets
    19,860       2,806  
Other deferred charges
    3,891       3,825  
 
           
Total deferred charges and other assets
    62,140       8,002  
 
           
 
               
Total Assets
  $ 617,102     $ 385,795  
 
           
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 63

 

 


Table of Contents

Consolidated Balance Sheets
                 
    December 31,     December 31,  
Capitalization and Liabilities   2009     2008  
(in thousands, except shares and per share data)                
 
               
Capitalization
               
Stockholders’ equity
               
Common stock, par value $0.4867 per share (authorized 12,000,000 shares)
  $ 4,572     $ 3,323  
Additional paid-in capital
    144,502       66,681  
Retained earnings
    63,231       56,817  
Accumulated other comprehensive loss
    (2,524 )     (3,748 )
Deferred compensation obligation
    739       1,549  
Treasury stock
    (739 )     (1,549 )
 
           
Total stockholders’ equity
    209,781       123,073  
 
               
Long-term debt, net of current maturities
    98,814       86,422  
 
           
Total capitalization
    308,595       209,495  
 
           
 
               
Current Liabilities
               
Current portion of long-term debt
    35,299       6,656  
Short-term borrowing
    30,023       33,000  
Accounts payable
    51,948       40,202  
Customer deposits and refunds
    24,960       9,534  
Accrued interest
    1,887       1,024  
Dividends payable
    2,959       2,082  
Accrued compensation
    3,445       3,305  
Regulatory liabilities
    8,882       3,227  
Mark-to-market energy liabilities
    2,514       3,052  
Other accrued liabilities
    8,683       2,970  
 
           
Total current liabilities
    170,600       105,052  
 
           
 
               
Deferred Credits and Other Liabilities
               
Deferred income taxes
    66,923       37,720  
Deferred investment tax credits
    193       235  
Regulatory liabilities
    4,154       875  
Environmental liabilities
    11,104       511  
Other pension and benefit costs
    17,505       7,335  
Accrued asset removal cost — Regulatory liability
    33,214       20,641  
Other liabilities
    4,814       3,931  
 
           
Total deferred credits and other liabilities
    137,907       71,248  
 
           
 
               
Other commitments and contingencies (Note P)
               
 
               
Total Capitalization and Liabilities
  $ 617,102     $ 385,795  
 
           
The accompanying notes are an integral part of the financial statements.
Page 64     Chesapeake Utilities Corporation 2009 Form 10-K

 

 


Table of Contents

Consolidated Statements of Stockholders’ Equity
                                                                 
    Common Stock                     Accumulated Other                    
    Number of             Additional Paid-In             Comprehensive     Deferred              
(in thousands, except per share and share data)   Shares (7)     Par Value     Capital     Retained Earnings     Loss     Compensation     Treasury Stock     Total  
Balances at December 31, 2006
    6,688,084     $ 3,255     $ 61,960     $ 46,271     $ (334 )   $ 1,119     $ (1,119 )   $ 111,152  
Net Income
                            13,198                               13,198  
Other comprehensive income, net of tax:
                                                               
Employee Benefit Plans, net of tax:
                                                               
Amortization of prior service costs (4)
                                    (3 )                     (3 )
Net loss (5)
                                    (515 )                     (515 )
 
                                                             
Total comprehensive income
                                                            12,680  
 
                                                             
Dividend Reinvestment Plan
    35,333       17       1,121                                       1,138  
Retirement Savings Plan
    29,563       14       935                                       949  
Conversion of debentures
    8,106       4       135                                       139  
Share based compensation (1) (3)
    16,324       8       1,442                                       1,450  
Deferred Compensation Plan
                                            285       (285 )      
Purchase of treasury stock
    (971 )                                             (30 )     (30 )
Sale and distribution of treasury stock
    971                                               30       30  
Cash dividends (2)
                            (7,931 )                             (7,931 )
 
                                               
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  
 
                                               
     
(1)  
Includes amounts for shares issued for Directors’ compensation.
 
(2)  
Cash dividends per share for the periods ended December 31, 2009, 2008 and 2007 were $1.250, $1.210 and $1.175 respectively.
 
(3)  
The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For 2008 and 2007, the Company withheld 12,511 and 2,420 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, 2009, 2008 and 2007 were approximately $5, ($52) and ($2) respectively.
 
(5)  
Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended December 31, 2009, 2008 and 2007 were $794, ($1,900) and ($340) respectively.
 
(6)  
In May and November 2009, certain participants of the Deferred Compensation Plan received distributions totaling $883. There were no distributions in 2008 and 2007.
 
(7)  
Includes 28,452, 62,221 and 57, 309 shares at December 31, 2009, 2008 and 2007, 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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 65

 

 


Table of Contents

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. On October 28, 2009, we completed a merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. Our regulated energy business delivers natural gas to approximately 118,000 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 384-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. The propane distribution operation provides distribution service to 49,000 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 the Company 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.
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 of unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of property of 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.
Page 66     Chesapeake Utilities Corporation 2009 Form 10-K

 

 


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    December 31,     December 31,        
(In thousands)   2009     2008     Useful Life (1)  
 
Plant in service
                       
Mains
  $ 237,133     $ 184,125     27-62 years
Services — utility
    61,803       37,947     12-48 years
Compressor station equipment
    24,981       24,981     42 years
Liquefied petroleum gas equipment
    30,211       26,304     5-31 years
Meters and meter installations
    28,419       19,479     Unregulated energy 3-33 years, regulated energy 14-49 years
Measuring and regulating station equipment
    19,131       15,092     14-54 years
Office furniture and equipment
    15,587       12,536     Unregulated energy 4-7 years, regulated energy14-25 years
Transportation equipment
    16,805       11,267     1-20 years
Structures and improvements
    15,007       10,602     3-44 years (2)
Land and land rights
    12,789       7,901     Not depreciable, except certain regulated assets
Propane bulk plants and tanks
    12,181       6,296     12-40 years
Electric transmission lines and transformers
    29,736           10-41 years
Poles and towers
    8,752           21-40 years
Various
    28,735       23,677     Various
 
                   
Total plant in service
    541,270       380,207          
Plus construction work in progress
    2,476       1,482          
Less accumulated depreciation
    (107,318 )     (101,018 )        
 
                   
Net property, plant and equipment
  $ 436,428     $ 280,671          
 
                   
     
(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.
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 $74,000 at December 31, 2009.
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.
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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.
At December 31, 2009 and 2008, 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,  
(in thousands)   2009     2008  
 
Regulatory Assets
               
Underrecovered purchased gas costs
  $ 1,149     $ 651  
Income tax related amounts due from customers
    1,783       1,285  
Deferred post retirement benefits
    3,636       83  
Deferred transaction and transition costs
    1,486        
Deferred piping and conversion costs
    1,061        
Deferred development costs
    1,698        
Environmental regulatory assets and expenditures
    7,510       779  
Acquisition adjustment (1)
    795        
Loss on reacquired debt
    154        
Other
    1,793       834  
 
           
Total Regulatory Assets
  $ 21,065     $ 3,632  
 
           
 
               
Regulatory Liabilities
               
Self insurance
  $ 982     $ 912  
Overrecovered purchased gas costs
    7,304       1,542  
Shared interruptible margins
    84       232  
Conservation cost recovery
    1,035       744  
Rate refund(2)
    258        
Income tax related amounts due to customers
    729       125  
Storm reserve
    2,554        
Accrued asset removal cost
    33,214       20,641  
Other
    90       547  
 
           
Total Regulatory Liabilities
  $ 46,250     $ 24,743  
 
           
     
(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.
Included in the regulatory assets listed above is $1.5 million related to deferred merger-related costs at December 31, 2009 for which we intend to seek recovery in future rates in Florida. Also included in the regulatory assets listed above are $838,000 and $711,000 at December 31, 2009 and 2008, respectively, in other costs primarily related to income tax related amounts, for which we are awaiting regulatory approval from various jurisdictions for recovery. For certain regulatory assets, such as under-recovered purchased fuel costs, deferred rate case costs and development costs, only recovery of the deferred costs is allowed in rates and we do not earn a return on those regulatory assets.
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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.
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 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.
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Income Taxes and Investment Tax Credit Adjustments
Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements 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 income statement in the period of change. There were unrealized losses of $1.6 million in 2009 and unrealized gains of $1.4 million in 2008. Trading liabilities are recorded in mark-to-market energy liabilities. Trading assets are recorded in mark-to-market energy assets.
Our natural gas, electric and propane distribution 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. During 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 $41,000. At December 31, 2009 and 2008, we had $0 in fair value of the put agreement and $(105,000) in fair value of the swap agreement, respectively.
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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 shareholders 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,   2009     2008     2007  
(in thousands, except shares and per share data)                        
 
Calculation of Basic Earnings Per Share:
                       
Net Income
  $ 15,897     $ 13,607     $ 13,198  
Weighted average shares outstanding
    7,313,320       6,811,848       6,743,041  
 
                 
Basic Earnings Per Share
  $ 2.17     $ 2.00     $ 1.96  
 
                 
 
                       
Calculation of Diluted Earnings Per Share:
                       
Reconciliation of Numerator:
                       
Net Income
  $ 15,897     $ 13,607     $ 13,198  
Effect of 8.25% Convertible debentures
    79       89       96  
 
                 
Adjusted numerator — Diluted
  $ 15,976     $ 13,696     $ 13,294  
 
                 
 
                       
Reconciliation of Denominator:
                       
Weighted shares outstanding — Basic
    7,313,320       6,811,848       6,743,041  
Effect of dilutive securities:
                       
Share-based Compensation
    34,229       12,083        
8.25% Convertible debentures
    92,652       103,552       111,675  
 
                 
Adjusted denominator — Diluted
    7,440,201       6,927,483       6,854,716  
 
                 
 
Diluted Earnings Per Share
  $ 2.15     $ 1.98     $ 1.94  
 
                 
Common stock issued in connection with the FPU merger (See Note B, “Acquisitions and Dispositions,” to the Consolidated Financial Statements) increased weighted average shares outstanding during 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 a recourse 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.
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.
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Each of our natural gas distribution operations in Delaware and Maryland, bundled natural gas distribution service in Florida 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.
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 the Company nor any of its interruptible customers is contractually obligated to deliver or receive natural gas on a firm service basis.
Cost of Sales
Cost of sales includes the direct costs attributable to the products sold or services provided by the Company for its 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 retirement 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.
Certain Risks and Uncertainties
Our financial statements are prepared in conformity with GAAP, which require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Note O, “Environmental Commitments and Contingencies,” and Note P, “Other Commitments and Contingencies,” to the Consolidated Financial Statements for significant estimates). These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond the control of the Company; therefore, actual results could differ from those estimates.
We record certain assets and liabilities in accordance with ASC Topic 980, “Regulated Operations.” In applying provisions of this Topic, our regulated operations may defer costs or revenues in different periods than our unregulated operations would recognize, resulting in their being recorded as assets or liabilities on the applicable operation’s balance sheet. If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the income statement at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material.
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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. Many of these fair value measurements can be highly subjective and it is also possible that others applying reasonable judgment to the same facts and circumstances could develop and support a range of alternative estimated amounts. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature and impact of such regulations on those assets and liabilities 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 the value of net assets and future earnings of the Company.
Total value of the consideration transferred by Chesapeake in the merger was $75.7 million. Net fair value of the assets acquired and liabilities assumed in the merger was estimated to be $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. Note B, “Acquisitions and Dispositions,” to the Consolidated Financial Statements describes more fully the purchase price allocation.
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 considerations 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. During 2009, we incurred approximately $3.0 million to consummate the merger, including the cost associated with merger-related litigation, and integrate operations following the merger. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at December 31, 2009, which represents our 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.
Subsequent Events
We have assessed and reported on subsequent events through the date of issuance of these Consolidated Financial Statements.
Reclassifications
As a result of the merger with FPU in 2009, we changed our operating segments (see Note C, “Segment Information,” to the Consolidated Financial Statements). We revised the 2008 and 2007 segment information to reflect the new segments. We also revised the 2008 segment information by reclassifying transaction costs, which were previously allocated to all segments, to the “Other” segment. We reclassified certain amounts in the statements of income and cash flows for the years ended December 31, 2008 and 2007, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our Consolidated Financial Statements.
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Codification
Beginning in the third quarter of 2009, we adopted the Financial Accounting Standards Board (“FASB”) ASC, which is now the single source of authoritative accounting principles in the United States. The adoption of the ASC did not have a material impact on our financial position and results of operations. As a result of this adoption, we updated all references to accounting and reporting standards included in this Form 10-K and in some instances provided references to both pre-and post-Codification standards, as appropriate.
FASB Statements and Other Authoritative Pronouncements
Recent Accounting Pronouncements 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 financial statements in accordance with IFRS as early as 2014. 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 we are subject in our rate-regulated businesses. We will continue to monitor the development of the potential implementation of IFRS.
The FASB has issued ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in 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 separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, 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 are currently assessing the potential impact of this pronouncement.
Other Accounting Amendments Adopted by the Company in 2009:
In December 2007, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 141(R), now codified within ASC Topic 805, “Business Combinations.” SFAS No.141(R): (a) defines the acquirer as the entity that obtains control of one or more businesses in a business combination; (b) establishes the acquisition date as the date that the acquirer achieves control; and (c) requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interests at their fair values as of the acquisition date. It also requires that acquisition-related costs be expensed as incurred. Provisions of this standard were adopted effective January 1, 2009. The merger with FPU, effective October 28, 2009, was accounted for using provisions of this standard. For further discussion, see Note B, “Acquisition and Dispositions” to the Consolidated Financial Statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” SFAS No. 161 was codified within ASC Sections 815-10-15 and 65, of the Topic, “Derivatives and Hedging,” and it requires enhanced disclosures for derivative instruments and hedging activities including: (i) how and why a company uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under the Derivatives and Hedging Topic, and (iii) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. Disclosures required by this standard were adopted by the Company, effective January 1, 2009. Adoption of this standard did not have an impact on our consolidated financial position and results of operations. These disclosures are discussed in Note E, “Derivative Instruments,” to the Consolidated Financial Statements.
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In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of the Useful Life of Intangible Assets,” which is codified within ASC Sections 350-30-50, 55 and 65 of the Topic, “Intangibles — Goodwill and Other,” and ASC Section 275-10-50, of the Topic, “Risks and Uncertainties.” It amended factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of these provisions is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. We adopted this standard, effective January 1, 2009. Adoption of this standard did not have an impact on our consolidated financial position and results of operations.
In May 2008, the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” which was codified within: (a) ASC Sections 470-20-10, 15, 25, 30, 35, 40, 45, 50, 55 and 65 of the Topic, “Debt,” (b) ASC Section 815-15-55, of the Topic, “Derivatives and Hedging,” and (c) ASC Section 825-10-15, of the Topic, “Financial Instruments.” FSP APB 14-1 clarifies that companies with convertible debt instruments, which may be settled in cash upon either mandatory or optional conversion (including partial cash settlement), should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. We adopted this standard, effective, January 1, 2009. The adoption of this standard did not have an impact on our consolidated financial position and results of operations.
In September 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP, codified within FASB ASC Sections 260-10-45, 55 and 65, of the Topic, “Earnings Per Share,” clarifies that holders of outstanding unvested share-based payment awards containing rights to nonforfeitable dividends participate with common shareholders in undistributed earnings. Awards of this nature are considered participating securities, and the two-class method of computing basic and diluted earnings per share must be applied. We adopted this standard, effective January 1, 2009. The adoption of this standard did not have an impact on our consolidated financial position and results of operations.
In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP is codified within ASC Section 715-20-65, of the Topic, “Compensation — Retirement Benefits.” It expands the disclosure requirements of a defined benefit pension or other postretirement plan by including the following discussions about plan assets: (i) how investment allocation decisions are made, including the plan’s investment policies and strategies; (ii) the major categories of plan assets; (iii) the inputs and valuation techniques used to measure the fair value of plan assets; (iv) the effect of fair value measurements, using significant unobservable inputs on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. The disclosures required by this standard are discussed in Note M, “Employee Benefit Plans,” to the Consolidated Financial Statements.
In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP, codified within ASC Section 825-10-65 of the Topic, “Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. The provisions of this standard are effective for interim and annual reporting periods ending after June 15, 2009, and they did not have an impact on our consolidated financial position and results of operations. The disclosures required by this standard are discussed in Note F, “Fair Value of Financial Instruments,” to the Consolidated Financial Statements.
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which we adopted in the second quarter of 2009. The provisions of this standard, now residing in ASC Sections 855-10-05, 15, 25, 45, 50 and 55 of the Topic, “Subsequent Events,” establish general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this standard did not have an impact on our consolidated financial position and results of operations.
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In August 2009, the FASB issued FASB Accounting Standards Update (“ASU”) No. 2009-05, “Fair Value Measurement and Disclosures — Measuring Liabilities at Fair Value.” This ASU provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value, using either: (a) a valuation technique that applies the quoted price of the identical liability when traded as an asset or quoted prices for similar liabilities when traded as assets; or (b) another valuation technique that is consistent with the principles of the Topic, “Fair Value Measurements and Disclosures.” We adopted this ASU in the third quarter of 2009, and the adoption of this standard did not have an impact on our consolidated financial position and results of operations.
B. Acquisitions and Dispositions
FPU
On October 28, 2009, we completed the previously announced 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 allowed us to become a larger energy company serving approximately 200,000 customers in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. The merger increases our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing operations in Florida. It also introduces us to the electric distribution business as we incorporate FPU’s 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 is no contingent consideration in the merger. Total value of considerations 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 value, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate.
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the merger. Estimates of deferred income taxes and certain accruals are subject to change, pending the finalization of income tax returns and availability of additional information about the facts and circumstances that existed as of the merger closing. We will complete the purchase price allocation as soon as practicable but no later than one year from the merger closing.
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(in thousands)   October 28, 2009  
Purchase price
  $ 75,699  
 
     
 
       
Current assets
    26,761  
Property, plant and equipment
    141,907  
Regulatory assets
    17,918  
Investments and other deferred charges
    3,659  
Intangible assets
    4,019  
 
     
Total assets acquired
    194,264  
 
       
Long term debt
    47,812  
Borrowings from line of credit
    4,249  
Other current liabilities
    17,504  
Other regulatory liabilities
    19,414  
Pension and post retirement obligations
    14,276  
Environmental liabilities
    12,414  
Deferred income taxes
    20,850  
Customer deposits and other liabilities
    15,467  
 
     
Total liabilities assumed
    151,986  
Net identifiable assets acquired
    42,278  
 
     
Goodwill
  $ 33,421  
 
     
Goodwill of $33.4 million was recorded in connection with the merger, none of which 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 primarily to the strength of FPU’s regulated energy businesses and the synergies and opportunities in the combined company. Intangible assets acquired in connection with the merger are related to propane customer relationships ($3.5 million) and favorable propane contracts ($519,000). The intangible value assigned to FPU’s existing propane customer relationships will be amortized over a 12-year period based on the expected duration of benefit arising from the relationships. The intangible value assigned to favorable propane contracts, will be amortized over a period ranging from one to 14 months based on contractual terms. See Note H, “Goodwill and Other Intangible Assets,” to the Consolidated Financial Statements.
Current assets of $26.7 million acquired during the merger include notes receivable of approximately $5.8 million, for which we expect to receive payment in March 2010, and accounts receivable of approximately $3.1 million, $6.0 million and $891,000 for natural gas, electric and propane distribution businesses, respectively.
The financial position and results of operations and cash flows of FPU from the effective date of the merger are consolidated in our Consolidated Financial Statements in 2009. The revenue and net income from FPU for the post-merger period in 2009 included in our Consolidated Statements of Income were $26.4 million and $1.8 million, respectively. The following table shows pro forma results of operations for the year ended December 31, 2009, as if the merger had been completed at January 1, 2009, as well as pro forma results of operations for the year ended December 31, 2008, as if the merger had been completed at January 1, 2008.
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For the Years Ended December 31,   2009     2008  
(in thousands, except per share data)                
 
               
Operating revenues
  $ 394,772     $ 451,292  
Operating Income
    44,382       38,468  
Net Income
    20,872       17,544  
 
               
Earnings per share — basic
  $ 2.23     $ 1.89  
Earnings per share — diluted
  $ 2.20     $ 1.86  
Pro forma results are presented for informational purposes only, and are not necessarily indicative of what the actual results would have been had the acquisitions actually occurred on January 1, 2009, and January 1, 2008, respectively.
OnSight
During 2007, we decided to close our distributed energy services subsidiary, OnSight, which had experienced operating losses since its inception in 2004. The results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. The discontinued operations experienced a net loss of $20,000 for 2007. We did not have any discontinued operations in 2008 and 2009.
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.
As a result of the merger with FPU, we changed our operating segments to better align with how the chief operating decision maker views the various operations of the Company. Our three operating segments are now composed of the following:
   
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 operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.
We also reclassified the segment information for 2008 and 2007 to reflect the new segments. During 2009, we also decided not to allocate merger-related transaction costs to different operations for the purpose of reporting their operating profitability because such costs are not directly attributable to their operations. To conform to the current year’s presentation, we revised the 2008 segment information by reclassifying transaction costs, which were previously allocated to all segments, to the “Other” segment.
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The following table presents information about our reportable segments. The table excludes financial data related to its former distributed energy service subsidiary, OnSight, which was reclassified to discontinued operations for 2007.
                         
For the Years Ended December 31,   2009     2008     2007  
(in thousands)                        
 
                       
Operating Revenues, Unaffiliated Customers
                       
Regulated Energy
  $ 137,847     $ 115,544     $ 128,491  
Unregulated Energy
    119,719       161,287       115,190  
Other
    11,219       14,612       14,606  
 
                 
Total operating revenues, unaffiliated customers
  $ 268,785     $ 291,443     $ 258,287  
 
                 
 
                       
Intersegment Revenues (1)
                       
Regulated Energy
  $ 1,252     $ 924     $ 359  
Unregulated Energy
    254       3        
Other
    779       761     $ 1,115  
 
                 
Total intersegment revenues
  $ 2,285     $ 1,688     $ 1,474  
 
                 
 
                       
Operating Income
                       
Regulated Energy
  $ 26,900     $ 24,733     $ 21,809  
Unregulated Energy
    8,158       3,781       5,174  
Other
    (1,322 )     (35 )     1,131  
 
                 
Operating Income
    33,736       28,479       28,114  
 
                       
Other income
    165       103       291  
Interest charges
    7,086       6,158       6,590  
Income taxes
    10,918       8,817       8,597  
 
                 
Net income from continuing operations
  $ 15,897     $ 13,607     $ 13,218  
 
                 
 
                       
Depreciation and Amortization
                       
Regulated Energy
  $ 8,866     $ 6,694     $ 6,918  
Unregulated Energy
    2,415       2,024       1,842  
Other
    307       287       300  
 
                 
Total depreciation and amortization
  $ 11,588     $ 9,005     $ 9,060  
 
                 
 
                       
Capital Expenditures
                       
Regulated Energy
  $ 22,917     $ 25,386     $ 23,087  
Unregulated Energy
    1,873       3,417       5,290  
Other
    1,504       2,041       1,765  
 
                 
Total capital expenditures
  $ 26,294     $ 30,844     $ 30,142  
 
                 
     
(1)  
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
                 
    December 31,     December 31,  
(in thousands)   2009     2008  
 
               
Identifiable Assets
               
Regulated Energy
  $ 480,903     $ 297,407  
Unregulated Energy
    101,437       72,955  
Other
    34,724       15,394  
 
           
Total identifiable assets
  $ 617,064     $ 385,756  
 
           
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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, 2009, 2008, and 2007 were as follows:
                         
For the Years Ended December 31,   2009     2008     2007  
(in thousands)                        
Cash paid for interest
  $ 6,703     $ 5,835     $ 5,592  
Cash paid for income taxes
  $ 1,111     $ 3,885     $ 7,009  
Non-cash investing and financing activities during the years ended December 31, 2009, 2008, and 2007 were as follows:
                         
For the Years Ended December 31,   2009     2008     2007  
(in thousands)                        
Capital property and equipment acquired on account, but not paid as of December 31
  $ 1,151     $ 696     $ 366  
Merger with FPU
  $ 75,682     $     $  
Retirement Savings Plan
  $ 982     $ 159     $ 949  
Dividends Reinvestment Plan
  $ 692     $ 208     $ 841  
Conversion of Debentures
  $ 135     $ 177     $ 138  
Performance Incentive Plan
  $     $ 568     $ 435  
Director Stock Compensation Plan
  $ 214     $ 181     $ 184  
Tax benefit on stock warrants
  $     $ 50     $  
E. Derivative Instruments
As of December 31, 2009, we had the following outstanding trading contracts which we accounted for as derivatives:
                         
    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.
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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 Sheet as of December 31, 2009 and 2008, are the following:
                         
            Asset Derivatives  
            Fair Value  
(in thousands)   Balance Sheet Location     December 31, 2009     December 31, 2008  
Derivatives not designated as fair value hedges:
 
Forward contracts
  Mark-to-market energy assets     $ 2,379     $ 4,482  
Put option(1)
  Mark-to-market energy assets              
 
                 
 
Total asset derivatives
          $ 2,379     $ 4,482  
 
                 
                         
            Liability Derivatives  
            Fair Value  
(in thousands)   Balance Sheet Location     December 31, 2009     December 31, 2008  
Derivatives designated as fair value hedges:
Propane swap agreement (2)
  Other current liabilities   $     $ 105  
 
                       
Derivatives not designated as fair value
hedges:
Forward contracts
  Mark-to-market energy liabilities       2,514       3,052  
 
                 
 
Total liability derivatives
          $ 2,514     $ 3,157  
 
                 
     
(1)  
We purchased a put option for the Pro-Cap (propane price cap) plan in September 2009. The put option, which expires on March 31, 2010, had a fair value of $0 at December 31, 2009.
 
(2)  
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 plan that was offered to customers. We terminated this swap agreement in January 2009.
The effects of gains and losses from derivative instruments on the Consolidated Statement of Income for the years ended December 31, 2009 and 2008, are the following:
                         
    Amount of Gain (Loss) on Derivatives:  
    Location of Gain   For the Years Ended December 31,  
(in thousands)   (Loss) on Derivatives   2009     2008  
Derivatives designated as fair value hedges
                       
Propane swap agreement (1)
  Cost of Sales   $ (42 )   $ 1,476  
 
Derivatives not designated as fair value hedges
                       
Put Option (2)
  Revenue     (41 )      
 
Derivatives not designated as fair value hedges
                       
Unrealized gains (losses) on forward contracts
  Revenue     (1,565 )     1,357  
 
                 
 
Total
          $ (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 September 2009. The put option, which expires on March 31, 2010, had a fair value of $0 at December 31, 2009.
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The effects of trading activities on the Consolidated Statement of Income for the years ended December 31, 2009 and 2008, are the following:
                         
    Amount of Trading Revenue:  
    Location in the     For the Years Ended December 31,  
(in thousands)   Statement of Income     2009     2008  
Realized gains on forward contracts
  Revenue   $ 3,830     $ 1,935  
Unrealized gains (losses) on forward contracts
  Revenue     (1,565 )     1,357  
 
                 
Total
          $ 2,265     $ 3,292  
 
                 
F. Fair Value of Financial Instruments
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability;
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).
The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2009:
                                 
            Fair Value Measurements Using:  
                    Significant Other     Significant  
            Quoted Prices in     Observable     Unobservable  
            Active Markets     Inputs     Inputs  
(in thousands)   Fair Value     (Level 1)     (Level 2)     (Level 3)  
Assets:
                               
Investments
  $ 1,959     $ 1,959     $     $  
Mark-to-market energy assets, including put option
  $ 2,379     $     $ 2,379     $  
 
                               
Liabilities:
                               
Mark-to-market energy liabilities
  $ 2,514     $     $ 2,514     $  
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The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2008:
                                 
            Fair Value Measurements Using:  
                    Significant Other     Significant  
            Quoted Prices in     Observable     Unobservable  
            Active Markets     Inputs     Inputs  
(in thousands)   Fair Value     (Level 1)     (Level 2)     (Level 3)  
Assets:
                               
Investments
  $ 1,601     $ 1,601     $     $  
Mark-to market energy assets
  $ 4,482     $     $ 4,482     $  
 
                               
Liabilities:
                               
Mark-to market energy liabilities
  $ 3,052     $     $ 3,052     $  
Propane swap agreement
  $ 105     $     $ 105     $  
The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of December 31, 2009 and 2008:
Level 1 Fair Value Measurements:
Investments — The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
Level 2 Fair Value Measurements:
Mark-to-market energy assets and liabilities — These forward contracts are valued using market transactions in either the listed or OTC markets.
Propane price swap agreement and put option — The fair value of the propane price swap agreement and put option is valued using market transactions for similar assets and liabilities in either the listed or OTC markets.
At December 31, 2009, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.
Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The carrying value of these financial assets and liabilities approximates fair value due to their short maturities and because interest rates approximate current market rates for short-term debt.
At December 31, 2009, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $134.1 million, compared to a fair value of $145.5 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile. At December 31, 2008, the estimated fair value was approximately $92.3 million, compared to a carrying value of $93.1 million.
G. Investments
The investment balances at December 31, 2009 and 2008 represent a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan and a Rabbi Trust related to a stay bonus agreement with a former executive. We classify these investments as trading securities and report them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the consolidated statements of income. We also have an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trusts. At December 31, 2009 and 2008, total investments had a fair value of $2.0 million and $1.6 million, respectively.
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