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)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
State of Delaware
Washington, D.C. 20549
51-0064146
 
 
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, 2006
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
(I.R.S. Employer

incorporation or organization)
(I.R.S. Employer
Identification No.)

909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including zip code)
 
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:
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)

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 [X]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 [X]þ.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d)15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]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). Yeso. Noo.
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. [X]þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer.smaller reporting company. See definitionthe definitions of ““accelerated filer,” “large accelerated filerfiler” and large accelerated filer”“smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [  ]                 Accelerated filer [X]                 Non-accelerated filer [  ]
Large accelerated fileroAccelerated filerþNon-accelerated fileroSmaller Reporting Companyo
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [  ].o. No [X]þ.

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2006,2009, 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 $179.2$223.5 million.
As of March 8, 2007, 6,717,348February 28, 2010, 9,436,558 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 20072010 Annual Meeting of Stockholders are incorporated by reference in Part III.
 


Chesapeake Utilities Corporation

Form 10-K
Form 10-K

YEAR ENDED DECEMBER 31, 20062009

TABLE OF CONTENTS
 
Page
 Part I
 1
 Page
Part I
3
Item 1. Business
 14
 
Item 1A. Risk Factors
 814
 
Item 1B. Unresolved Staff Comments
 1223
 
Item 2. Properties
 1223
 
Item 3. Legal Proceedings
 1224
 
Item 4. Submission of Matters to a Vote of Security Holders
 1224
 Part II
13Item 4A. Executive Officers of the Registrant
25
 
Part II
26
Item 5. Market for the Registrant'sRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 1326
 
Item 6. Selected Financial Data
 1629
 
Item 7. Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations
 2033
 
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
 4559
 
Item 8. Financial Statements and Supplementary Data
 4559
 
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
 76108
 
Item 9A. Controls and Procedures
 76108
 
Item 9B. Other Information
 76111
 
Part III
 77
111
 
Item 10. Directors, Executive Officers of the Registrant and Corporate GovernanceGovernanace
 77111
 
Item 11. Executive Compensation
 77111
 
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 77111
 
Item 13. Certain Relationships and Related Transactions, and Director Independence
 78112
 
Item 14. Principal Accounting Fees and Services
 78112
 Part IV
 79
Part IV
113
Item 15. Exhibits, Financial Statement Schedules
 79113
 Signatures
 83Signatures
119
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

GLOSSARY OF KEY TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
Subsidiaries of Chesapeake Utilities Corporation
BravePointBravePoint, Inc., a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake
ChesapeakeThe Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
CompanyThe Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
ESNGEastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake
FPUFlorida Public Utilities Company, a new wholly-owned subsidiary of Chesapeake, effective October 28, 2009
OnSightChesapeake OnSight Services, LLC, a wholly-owned subsidiary of Chesapeake
PESCOPeninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake
PIPECOPeninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake
SharpSharp Energy, Inc., a wholly-owned subsidiary of Chesapeake and Sharp’s subsidiary, Sharpgas, Inc.
XeronXeron, Inc., a wholly-owned subsidiary of Chesapeake
Regulatory Agencies
Delaware PSCDelaware Public Service Commission
DOTUnited States Department of Transportation
EPAUnited States Environmental Protection Agency
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FDEPFlorida Department of Environmental Protection
Florida PSCFlorida Public Service Commission
IRSInternal Revenue Service
Maryland PSCMaryland Public Service Commission
MDEMaryland Department of the Environment
PSCPublic Service Commission
SECSecurities and Exchange Commission
Chesapeake Utilities Corporation 2009 Form 10-K      Page 1

Other
AOCIAccumulated Other Comprehensive Income
DSCPDirectors Stock Compensation Plan
GSRGas sales service rates
HDDHeating degree-days
McfThousand Cubic Feet
MWHMegawatt Hour
MGPManufactured Gas Plant
NYSENew York Stock Exchange
PIPPerformance Incentive Plan
S&P 500 IndexStandard & Poor’s 500 Index
SFASStatement of Financial Accounting Standards
Accounting Standards
ASC
FASB Accounting Standards CodificationTM(Codification)
ASUFASB Accounting Standards Update
FSPFinancial Accounting Standards Board Staff Position
GAAPGenerally Accepted Accounting Principles
Page 2      Chesapeake Utilities Corporation 2009 Form 10-K


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

Safe Harbor for Forward-Looking Statements
Chesapeake Utilities Corporation has madeWe make statements in this Form 10-K that are considereddo not directly or exclusively relate to behistorical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. TheseYou can typically identify forward-looking statements are not mattersby the use of historical fact and are typically identified byforward-looking words, such as but not limited to, “believes,“project,” “expects,“believe,” “intends,“expect,” “plans,“anticipate,” and“intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar expressions,words, or future or conditional verbs such as “may,” “will,” “should,” “would,“would” or “could.” and “could”. These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trendsrepresent our intentions, plans, expectations, assumptions and decisions, market risks associated with our propane operations, the competitive positionbeliefs about future financial performance, business strategy, projected plans and objectives of the Company and other matters. It is important to understand that these forward-lookingCompany. These statements are not guarantees, but are subject to certainmany risks and uncertainties and otheruncertainties. In addition to the risk factors described under Item 1A “Risks Factors,” the following important factors, thatamong others, could cause actual future results to differ materially from those expressed in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to those discussed in Item 1A “Risk Factors.”

Item 1. Business.
statements:
(a)  
General Development•
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 Businessregulatory, 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 isUtilities Corporation 2009 Form 10-K      Page 3

Item 1. Business.
(a)Overview
We are a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information servicesvarious energy and other related 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
Chesapeake’sAs 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

(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 approximately 59,10051,736 residential and commercial customers and 155 industrial customers in central and southern Delaware and Maryland’s Eastern ShoreShore. For the year ended December 31, 2009, operating revenues and parts of Florida. The Company’sdeliveries 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 transmission subsidiary, Eastern Shore 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

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

Natural Gas Company (“Eastern Shore” or “ESNG”),Transmission
ESNG operates a 366-mile384-mile interstate pipeline system that transports natural gas from various points in Pennsylvania to the Company’sChesapeake’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. Our propane distribution operation serves approximately 33,300 customers in centralESNG also provides swing transportation service and southern Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania, and parts of Florida. The advanced information services segment provides domestic and international clients with information technology related business services and solutions for both enterprise and e-business applications.

(b)  
Financial Information about Industry Segments
Financial information by business segment is included in Item 8 under the heading “Notes to Consolidated Financial Statements — Note C.”

(c)  
Narrative Description of Business
Chesapeake is engaged in three primary business activities: natural gas distribution, transmission and marketing, propane distribution and wholesale marketing and advanced informationcontract storage services. In addition to the primary groups, Chesapeake has subsidiaries in other related businesses.

(i) (a) Natural Gas Distribution, Transmission and Marketing
General
Chesapeake distributes natural gas to residential, commercial and industrial customers in central and southern Delaware, the Salisbury and Cambridge, Maryland areas on Maryland’s Eastern Shore and parts of Florida. These activities are conducted through three utility divisions, one division in Delaware, another in Maryland and a third division in Florida. The Company also offers natural gas supply and supply management services in the state of Florida through its subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”).

- Page 1 -
Delaware and Maryland. Chesapeake’s Delaware and Maryland utility divisions serve approximately 45,400 customers, of which approximately 45,200 are residential and commercial customers purchasing gas primarily for heating purposes. The remaining customers are industrial. For the year 2006, residentialended December 31, 2009, operating revenues and commercial customers accounteddeliveries by customer class for approximately 77% of the volume delivered by the divisions and 75% of the divisions’ revenue.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.
Florida. The Florida division distributes natural gasIn 2005, we formed PIPECO to approximately 13,630 residential and commercial and 100 industrial customers in the 13 Counties of Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee, Liberty, Washington and Citrus. Currently, the industrial customers, which purchase and transport gas on a firm basis, account for approximately 92% of the volume delivered by the Florida division and 43% of the revenues. These customers are primarily engaged in the citrus and phosphate industries and in electric cogeneration.

PESCO provides natural gas supply and supply management services to commercial and industrial end users in Florida. During 2005, Chesapeake formed a wholly owned subsidiary, Peninsula Pipeline Company, Inc.operate an intrastate pipeline to provide natural gas transportation services to industrial customers by an intra-state pipeline.

Eastern Shore. The Company’s wholly owned transmission subsidiary, Eastern Shore, owns and operates an interstatein 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 provides open access transportationregulations. In January 2009, PIPECO began providing natural gas transmission services to a customer for affiliated and non-affiliated companiesa period of 20 years at a fixed monthly charge, through an integrated8-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 pipeline extending from southeastern Pennsylvania through Delawareand electricity is adequate under existing arrangements to its terminus onmeet the Eastern Shoreanticipated needs of Maryland. Eastern Shore also provides swing transportation service and contract storage services. Eastern Shore’s rates and services are subject to regulation by the Federal Energy Regulatory Commission (“FERC”).customers.

Natural Gas Distribution
Adequacy of Resources
General. TheOur Delaware and Maryland natural gas distribution divisions have both firm and interruptible transportation service contracts with four interstate “open access” pipelinespipeline companies, including Eastern Shore. Thethe ESNG pipeline. These divisions are directly interconnected with Eastern Shorethe ESNG pipeline, and serviceshave contracts with interstate pipelines upstream of Eastern Shore are contracted withESNG, including Transcontinental Gas PipelinePipe 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 service providers are affiliatespipelines 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. In order to meet the difference between firm supplyrequirements and firm demand, the divisionsthey purchase natural gas supplysupplies on the spot market from various suppliers.suppliers as needed to match firm supply and demand. This gas is transported by the upstream pipelines and delivered to the divisions’ interconnectstheir interconnections with Eastern Shore. TheESNG. 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

The Company believesfollowing table shows the firm transmission and storage capacity that the availability of gas supply and transportation to the Delaware and Maryland divisions is adequatecurrently have under existing arrangements to meetcontract with ESNG and pipelines upstream of the anticipated needs of their customers.ESNG pipeline, including the respective contract expiration dates.

Delaware
Delaware. The Delaware division’s contracts with Transco include: (a) firm transportation capacity of 9,029 dekatherms (“Dt”) per day, with provisions to continue from year to year, subject to 180 days notice for termination; (b) firm transportation capacity of 311 Dt per day for December through February, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination; (c) firm transportation capacity of 174 Dt per day, which expires in 2008; (d) firm transportation capacity of 1,842 Dt, which expires in 2009; (e) firm storage service, providing a peak day entitlement of 1,680 Dt and a total capacity of 142,830 Dt, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination; and (f) firm storage service, providing a peak day entitlement of 1,786 Dt and a total capacity of 17,967 Dt, which expires in 2013.
           
  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
- Page 2 -

           
  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 division’sand Maryland divisions currently have contracts with Columbia include: (a) firm transportation capacity of 880 Dt per day, which expires in 2014; (b) firm transportation capacity of 1,132 Dt per day, which expires in 2017; (c) firm transportation capacity of 549 Dt per day, which expires in 2018; (d) firm transportation capacity of 899 per day, which expires in 2019; (e) firm storage service providing a peak day entitlement of 6,193 Dt and a total capacity of 298,195 Dt, which expires in 2015; (f) firm storage service, providing a peak day entitlement of 635 Dt and a total capacity of 57,139 Dt, which expires in 2018; (g) firm storage service providing a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires in 2019; (h) firm storage service providing a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires in 2020; (i) firm storage service providing a peak day entitlement of 15 Dt and a total capacity of 1,350 Dt, which expires in 2018; and (j) firm storage service providing a peak day entitlement of 215 Dt and a total capacity of 10,646 Dt, which expires in 2010. Delaware’s contracts with Columbia for storage-related transportation provide quantities that are equivalent to the peak day entitlement for the period of October through March and are equivalent to fifty percent (50%) of the peak day entitlement for the period of April through September. The terms of the storage-related transportation contracts mirror the storage services that they support.

The Delaware division’s contract with Gulf, which expires in 2009, provides firm transportation capacity of 880 Dt per day for the period November through March and 809 Dt per day for the period April through October.

The Delaware division’s contracts with Eastern Shore include: (a) firm transportation capacity of 53,637 Dt per day for the period December through February, 52,415 Dt per day for the months of November, March and April, and 43,339 Dt per day for the period May through October, with various expiration dates ranging from 2007 to 2017; (b) firm storage capacity providing a peak day entitlement of 2,655 Dt and a total capacity of 131,370 Dt, which expires in 2013; (c) firm storage capacity providing a peak day entitlement of 580 Dt and a total capacity of 29,000 Dt, which expires in 2013; (d) firm storage capacity providing a peak day entitlement of 911 Dt and a total capacity of 5,708 Dt, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination.

The Delaware division currently has contractsseveral suppliers for the purchase of firm natural gas supply with several suppliers.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 the availability of a maximum firm daily entitlement of 37,500 Dt13,237 Mcfs and 2,029 Mcfs for the Delaware and Maryland divisions, respectively, delivered on the Transco, Columbia, and/or Gulf systems to Eastern ShoreESNG for redelivery to these divisions under firm transportationtransmission contracts. TheThese gas purchasesupply contracts have various expiration dates, and daily quantities may vary from day to day and month to month.

Maryland. The Maryland division’sChesapeake’s Florida natural gas distribution division has firm transmission service contracts with Transco include: (a) firm transportation capacity of 4,738 Dt per day, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination; (b) firm transportation capacity of 155 Dt per day for December through February, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination; (c) firm transportation capacity of 973 Dt, which expires in 2009; (d) firm storage service providing a peak day entitlement of 390 Dt and a total capacity of 33,120 Dt, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination ; and (e) firm storage service, providing a peak day entitlement of 546 Dt and a total capacity of 5,489 Dt, which expires in 2013.

The Maryland division’s contracts with Columbia include: (a) firm transportation capacity of 442 Dt per day, which expires in 2014; (b) firm transportation capacity of 908 Dt per day, which expires in 2017; (c) firm transportation capacity of 350 Dt per day, which expires in 2018; (d) firm storage service providing a peak day entitlement of 3,142 Dt and a total capacity of 154,756 Dt, which expires in 2015; (e) firm storage service providing a peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which expires in 2018; and (f) firm transportation capacity of 1,832 Dt per day for the period April through September. The Maryland division’s contracts with Columbia for storage-related transportation provide quantities that are equivalent to the peak day entitlement for the period October through March and are equivalent to fifty percent (50%) of the peak day entitlement for the period April through September. The terms of the storage-related transportation contracts mirror the storage services that they support.
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The Maryland division’s contract with Gulf, which expires in 2009, provides firm transportation capacity of 590 Dt per day for the period November through March and 543 Dt per day for the period April through October.

The Maryland division’s contracts with Eastern Shore include: (a) firm transportation capacity of 18,982 Dt per day for the period December through February, 18,254 Dt per day for the months of November, March and April and 13,674 Dt per day for the period May through October, with various expiration dates ranging from 2007 to 2015; (b) firm storage capacity providing a peak day entitlement of 1,428 Dt and a total capacity of 70,665 Dt, which expires in 2013; (c) firm storage capacity providing a peak day entitlement of 309 Dt and a total capacity of 15,500 Dt, which expires in 2013; and (d) firm storage capacity providing a peak day entitlement of 569 Dt and a total capacity of 3,560 Dt, with provisions to continue such contract on a year to year basis, subject to 180 days notice for termination.

The Maryland division currently has contracts for the purchase of firm natural gas supply with several suppliers. These supply contracts provide the availability of a maximum form daily entitlement of 11,500 Dt delivered on Transco, Columbia, and/or Gulf systems to Eastern Shore for redelivery under the Maryland division’s transportation contracts. The gas purchase contracts have various expiration dates and daily quantities may vary from day to day and month to month.

Florida. The Florida division receives natural gas from Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). ThePursuant to a program approved by the Florida division has firm transportation agreements with both of these interstate pipelines. AllPSC, all of the capacity under these agreements has been released to various third parties and PESCO, our natural gas marketing subsidiary.third-parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should theany 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.
Chesapeake’sPage 8     Chesapeake Utilities Corporation 2009 Form 10-K

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 transportation service for: (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 27,519 Dt in November through April; 21,123 Dt in May through September, and 27,105 Dt in October,292 Mcfs on its Pioneer Pipeline. The contract with IGC, which expires in 2010; and (b)2016, provides daily firm transportation capacity of 1,000 Dt daily, which expires in 2015.487 Mcfs on its distribution system.

Chesapeake’s contracts with Gulfstream include transportation serviceFPU uses gas marketers and producers to procure all its gas supplies for daily firm transportation capacity of 10,000 Dt daily. The contract with Gulfstream expires May 31, 2022.

PESCO currently has contracts with Eagle Energy Partners and Prior Energy for the purchase of firmits natural gas supply. The Eagle Energy Partners’ contract provides the availability of a maximum firm daily entitlement of 10,000 MMBtus anddistribution 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 an expiration date of May 2007. The Prior Energy contract provides the availability of a maximum firm daily entitlement of 7,500 MMBtus and has an expiration date of May 2007.

Eastern Shore. Eastern Shore also hasthree contracts with Transco for: (a) 7,046 Mcffor a total of 7,045 Mcfs of firm peak day storage entitlements and total storage capacity of 278,264 Mcf,Mcfs, each of which expires in 2013.

Eastern Shore ESNG has retained the firm transportation capacity andthese firm storage services described above in order to provide swing transportation service and firm storage service to those customers that have requested such service.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 onof competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”

Rates and Regulation
General. Chesapeake’sOur natural gas and electric distribution divisionsoperations are subject to regulation by the Delaware, Maryland and Florida Public Service CommissionsPSCs with respect to various aspects of thetheir business, including the rates for sales and transportation to all customers in each respective jurisdiction. All of Chesapeake’sour firm distribution sales rates are subject to gasfuel cost recovery mechanisms, which match revenues with gas and electric supply and transportation costs and normally allow eventual full recovery of gassuch costs. Adjustments under these mechanisms, which are limited to gassuch costs, require periodic filings and hearings with the relevantstate regulatory authority.authority having jurisdiction.
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Eastern ShoreESNG is subject to regulation as an interstate pipeline by the FERC, as an interstate pipeline. The FERCwhich regulates the provision of service, terms and conditions of service and the rates Eastern ShoreESNG can charge for its transportationtransmission and storage services. PIPECO is subject to regulation by the Florida PSC.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 9

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:
RegulatoryEffective Date ofAllowed
Regulated BusinessJurisdictionthe Current RatesRate of Return
Chesapeake — Delaware DivisionDelaware PSC9/3/200810.25%(1)
Chesapeake — Maryland DivisionMaryland PSC12/1/200710.75%(1)
Chesapeake — Florida DivisionFlorida PSC1/14/201010.80%(1)
FPU — Natural GasFlorida PSC1/14/2010(3)10.85%(1)
FPU — ElectricFlorida PSC5/22/200811.00%(1)
ESNGFERC9/1/200713.60%(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 raterates of return inof each jurisdictionof our regulated energy operations in order to ensure the 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
(i) (b) Propane DistributionRevenues from our residential and Wholesale Marketingcommercial 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.
GeneralFor 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.
Chesapeake’sIn 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.
Page 10     Chesapeake Utilities Corporation 2009 Form 10-K

(ii)  Unregulated Energy
Our unregulated energy segment provides natural gas marketing, propane distribution group consists of (1) Sharp Energy, Inc. (“Sharp Energy”), a wholly owned subsidiary of Chesapeake, (2) Sharpgas, Inc. (“Sharpgas”), a wholly owned subsidiary of Sharp Energy, and (3) Tri-County Gas Co., Incorporated (“Tri-County”), a wholly owned subsidiary of Sharp Energy. The propane wholesale marketing group consistsservices 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 Xeron, Inc.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 (“Xeron”Valero”), for its Delaware City refinery operation. We previously reported on November 25, 2009 in a wholly owned subsidiary of Chesapeake.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 energy.fossil fuels. Propane is sold primarily in suburban and rural areas, which are not served by natural gas distributors. Demand is typically much higher in the winter months and is significantly affected by seasonal variations, particularly the relative severity of winter temperatures, because of its use in residential and commercial heating.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 11

During 2006,
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 approximately 33,300by Sharp’s propane customers on the Delmarva Peninsula, southeastern Pennsylvania anddistribution 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 approximately 24.2to these new customers were $3.0 million retail 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 gallons of propane.

In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeronmarketing operation, markets propane to large, independent and petrochemical companies, resellers and southeastern retail propane companies in the southeastern United States. Additional informationThe 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 the controls that limit and monitor theXeron’s risks, are included insee Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk.”

The propane distribution business is affected by many factors, such as seasonality, the absence of price regulation, and competition among local providers. The propane wholesale marketing business is affected by wholesale price volatility and the supply and demand for propane at a wholesale level.

Adequacy of Resources
The Company’s propane distribution operations purchase propane primarily from suppliers, including major oil companies and independent producers of natural gas liquids. Supplies of propane from these and other sources are readily available for purchase by the Company. Supply contracts generally include minimum (not subject to take-or-pay premiums) and maximum purchase provisions.
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The Company’s propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to its bulk storage facilities. From these facilities, propane is delivered primarily by “bobtail” trucks, owned and operated by the Company, to tanks located at the customer’s premises.

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

Rates and Regulation
TheNatural 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 underby the Federal Motor Carrier Safety Act, which is administered byAdministration 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.

Page 12     Chesapeake Utilities Corporation 2009 Form 10-K

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 Company’s propane operations are subject to all operating hazards normally associated with the handling, storage and transportation”Other” segment consists primarily of combustible liquids, such as the risk of personal injury and property damage caused by fire. The Company carries general liability insurance in the amount of $35 million, but there is no assurance that such insurance will be adequate.

(i) (c) Advanced Information Services
General
Chesapeake’sour advanced information services segment consistssubsidiary, 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, Inc. (“BravePoint”), a wholly owned subsidiary of the Company. BravePoint,is headquartered in Norcross, Georgia, and provides domestic and international clients with information technology related business services and solutions for both enterprise and e-business applications.

Competition
See discussion on competition in Item 7 under the heading “Management’s Discussion and Analysis — Competition.”

(i) (d) Other Subsidiaries
Skipjack, Inc. (“Skipjack”), Eastern Shore Real Estate, Inc. and Chesapeake Investment Company are wholly owned subsidiaries of Chesapeake Service Company. Skipjack and Eastern Shore Real Estate, Inc. own and lease office buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is a Delawarean affiliated investment company. During 2004, Chesapeake formed a new company OnSight Energy, LLC (“OnSight”), to provide distributed energy solutions to customers requiring reliable, uninterrupted energy sources and/or those wishing to reduce energy costs.registered in Delaware.

(c) Other information about the Business
(ii) Seasonal Nature of Business
Revenues from the Company’s residential and commercial natural gas sales and from its propane distribution activities are affected by seasonal variations, since the majority of these sales are to customers using the fuels for heating purposes. Revenues from these customers are accordingly affected by the mildness or severity of the heating season.
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(iii)(i) Capital Budget
A discussion of capital expenditures by business segment and capital expenditures for environmental controlremediation facilities areis included in Item 7 under the heading “Management“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

(iv)(ii) Employees
As of December 31, 2006, Chesapeake2009, we had 437a total of 757 employees, including 193 in natural gas, 142 in propane and 70 in advanced information services. The remaining 32332 employees are considered general and administrative and include officerswho joined the Company as a result of the Company, treasury, accounting, internal audit, information technology, human resourcesrecent 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 other administrative personnel.United Food and Commercial Workers Union, all of whose collective bargaining agreements expire in 2010.

(v) Executive Officers of the Registrant
Information pertaining to the executive officers of the Company is as follows:

John R. Schimkaitis (age 59) Mr. Schimkaitis is President and Chief Executive Officer of Chesapeake and its subsidiaries. Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. He has served as President since 1997. Prior to this, Mr. Schimkaitis served as President and 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 (age 48) Mr. McMasters is Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation. He was appointed Senior Vice President in 2004 and has served as Chief Financial Officer since December 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.

Stephen C. Thompson (age 46) Mr. Thompson is President of Eastern Shore Natural Gas Company and Senior Vice President of Chesapeake Utilities Corporation. Prior to becoming Senior Vice President in 2004, he served as Vice President of Chesapeake since May 1997. He has also served as Vice President, Director of Gas Supply and Marketing, Superintendent of Eastern Shore and Regional Manager for the Florida distribution operations.
Beth W. Cooper (age 40) Ms. Cooper is Vice President, Treasurer and Corporate Secretary of Chesapeake Utilities Corporation. Ms. Cooper has served as Corporate Secretary since July 2005. 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.

S. Robert Zola (age 54) Mr. Zola joined Sharp Energy in August of 2002 as President. Prior to joining Sharp Energy, Mr. Zola most recently served as Northeast Regional Manager of Synergy Gas, now Cornerstone MLP, in Philadelphia, PA. During his 26-year career in the propane industry, Mr. Zola also started Bluestreak Propane in Phoenix, AZ, which after successfully developing the business, was sold to Ferrell Gas.

(vi)(iii) Financial Information about Geographic Areas
All of the Company’sour material operations, customers, and assets occur and are located in the United States.

(d)  
Available Information
(d) Available Information
As a public company, Chesapeake fileswe file annual, quarterly and other reports, as well as itsour annual proxy statement and other information, with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials that the Company fileswe file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549-5546; and 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. Chesapeake makesWe make available, free of charge, on itsour Internet website, itsour 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 Chesapeake’sour Internet website is www.chpk.com. The content of this website is not part of this report.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 13

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Chesapeake hasWe 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 its internetour Internet website. ChesapeakeWe 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 Securities and Exchange CommissionSEC and the New York Stock Exchange (“NYSE”). The Board of Directors has also adopted “CorporateCorporate Governance Guidelines on Director Independence,” which conform to the NYSE listing standards on director independence. Each of these documents also is available on Chesapeake’sour Internet website or may be obtained by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation;Corporation, 909 Silver Lake Blvd.;, Dover, DE 19904.

If Chesapeake makeswe make any amendment to, or grantsgrant a waiver of, any provision of the Business Code of Ethics and Conduct or the Financial Officer Code of Ethics for Financial Officers applicable to itsour principal executive officer, president, principal financial officer, principal accounting officer or controller, the amendment or waiver will be disclosed within fivefour business days in a press release, by website disclosure, or by filing a current report on Form 8-K with the Company’s Internet website.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 theour regulated and unregulated businesses of Chesapeake.businesses. Refer to the section entitled “Management’s“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 the Company’sour operations and/or financial performance.
Financial Risks
The principal business, economicanticipated 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 other factors thatoperating efficiencies. Achieving these synergies, cost savings and operating efficiencies cannot be assured and failure to achieve these benefits will adversely affect the operations and/or financialexpected future performance of the Company include:

Fluctuations in weather have the potential to adversely affect our results of operations, cash flows and financial condition.
Our utility and propane distribution operations are sensitive to fluctuations in weather, and weather conditions directly influence the volume of natural gas and propane delivered by our utility and propane distribution operations to customers. A significant portion of our utility and propane distribution operations’ revenues are derived from the delivery of natural gas and propane to residential and commercial heating customers during the five-month peak heating season of November through March. If the weather is warmer than normal, we 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 and propane, increased supply costs and higher prices for customers.

Regulation of the Company, including changes in the regulatory environment in general, may adversely affect our results of operations, cash flows and financial condition.
The state Public Service Commissions of Delaware, Maryland and Florida regulate our natural gas distribution operations. Eastern Shore, our natural gas transmission subsidiary, is regulated by the FERC. These regulatory agencies set the rates in their respective jurisdictions that we can charge customers for our rate-regulated services. Changes in these rates, as ordered by regulatory commissions, affect our financial performance. Our ability to obtain timely future rate increases and rate supplements to maintain current rates of return depends on regulatory discretion, and there can be no assurance that our divisions and Eastern Shore will be able to obtain rate increases or supplements or continue receiving currently authorized rates of return.
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The amount and availability of natural gas and propane supplies are difficult to predict, which may reduce our earnings.
Natural gas and propane production can be impacted by factors outside of our control, such as weather and refinery closings. If we are unable to obtain sufficient natural gas and propane supplies to meet demand, our results of operations may be negatively impacted.

We rely on having access to interstate pipelines’ transportation and storage capacity. If these pipelines or storage facilities were not available, it may impair our ability to meet our customers’ full requirements.
We must acquire both sufficient natural gas supplies and interstate pipeline and storage capacity to meet customer requirements. We must contract for reliable and adequate delivery capacity for our distribution system, while considering the dynamics of the interstate pipeline and storage capacity market, our own on-system resources, as well as, the characteristics of our customer base. Local natural gas distribution companies, including us, and other participants in the energy industry, have raised concerns regarding the future availability of additional upstream interstate pipeline and storage capacity. Additional available pipeline and storage capacity is a business issue that must be managed by us, as our customer base grows.

Natural gas and propane commodity price changes may affect the operating costs and competitive positions of our natural gas and propane distribution operations, which may adversely affect our results of operations, cash flows and financial condition.
Natural Gas. Over the last four years, natural gas costs have increased significantly and become more volatile.Company. In addition, the hurricane activity in 2005 reduced the natural gas available from the Gulf Coast region, further contributing to the volatility of natural gas prices. Higher natural gas prices can result in significant increases in the cost of gas billed to customers during the winter heating season. Underregulatory agencies that have jurisdiction over our regulated gas cost recovery mechanisms, we record cost of gas expense equal to the cost of gas recovered in revenues from customers. Therefore, an increase in the cost of gas due to an increase in the price of the natural gas commodity generally has no immediate effect on our revenuesenergy businesses and net income. However, our net incomeoperations may be reduced due to higher expenses that may be incurred for uncollectible customer accounts, as well as, lower volumes of natural gas deliveries to customers due to lower natural gas consumption caused by customer conservation. Increases in the price of natural gas also can affect our operating cash flows, as well as the competitiveness of natural gas as an energy source.

Propane. The level of profitability in the retail propane business is largely dependent on the difference between the cost of propane and the revenues derived from our sale of propane to our customers. Propane costs are subject to volatile changes as a result of product supply or other market conditions, including economic and political factors impacting crude oil and natural gas supply or pricing. Propane cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be ablerequire us to pass on propanesome, or all, of the achieved cost increases fully or immediately, particularly when propane costs increase or decrease rapidly. Therefore, average retail sales prices can vary significantly from yearsavings to year as product costs fluctuate with propane, fuel oil, crude oilratepayers.
Instability and natural gas commodity market conditions. In addition,volatility in periods of sustained higher commodity prices, retail sales volumes may be negatively impacted by customer conservation efforts and increased amounts of uncollectible accounts, which may adversely affect net income.

We compete inthe financial markets could have a competitive environment and may be faced with losing customers to a competitor.
We compete with third-party suppliers to sell gas to industrial customers. As it relates to transportation services,negative impact on our competitors include the interstate pipelines if distribution customer is located close enough to the transmission company’s pipeline to make a connection economically feasible.

growth strategy.
Our propane distributionbusiness strategy includes the continued pursuit of growth, both organically and through acquisitions. To the extent that we do not generate sufficient cash from operations, compete with several other propane distributorswe may incur additional indebtedness to finance our growth. The turmoil experienced in their service territories, primarilythe credit markets in 2008 and 2009 and its potential impact on the basisliquidity of service and price, emphasizing reliability of service and responsiveness. Some of our competitors have significantly greater resources. The retail propane industry is mature, and we foresee only modest growth in total demand. Given this limited growth, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow the propane distribution business is contingent upon execution of our community gas systems strategy to capture market share and to employ service pricing programs that retain and grow our customer base. Any failure to retain and grow our customer base wouldmajor financial institutions may have an adverse effect on our results.
- Page 9 -

The propane wholesale marketing operation competes against various marketers, many of which have significantly greater resourcescustomers 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 to compete on the basis of technological expertise, reputation and price.

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 sites that we have acquired from third parties. Compliance with these legal requirements requires us to commit capital toward environmental compliance. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines.

To date, we have been able to recover through approved rate mechanisms the costs of recovery associated with the remediation of former manufactured gas plant sites. However, there is no guarantee 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 manufactured gas plant 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 or become 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 by us.

A change in the economic conditions and interest rates may adversely affect our results of operations and cash flows.
A downturn in the economies of the regions in which we operate, which we cannot accurately predict, might adversely affect our ability to increasefund our customer base and other businesses at the same rate they have grownbusiness strategy through borrowings, under either existing or newly created arrangements in the recent past. Further, an increase in interest rates, without the recovery of the higher cost of debt in the sales and/public 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 dependprivate markets on short-term debt to finance accounts receivable, 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. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. To help cope with the effects of inflation on our capital investments and returns, we seek rate relief from regulatory commissions for regulated operations while monitoring the returns of our unregulated business operations. There can be no assurance that we will be able to obtain adequate and timely rate relief 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. However, there can be no assurance that we will be able to increase propane sales prices sufficiently to fully compensate for such fluctuations in the cost of propane gas to us.

Changes in technology may adversely affect our advanced information services segment’s results of operations, cash flows and financial condition.
Our advanced information services segment participates in a market that is characterized by rapidly changing technology and accelerating product introduction cycles. The success of our advanced information services segment 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 can be no assurance that we will be able to keep up with technological advancements necessary to make our products competitive.
- Page 10 -

Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.
Xeron, our propane wholesale and marketing subsidiary, and PESCO, our natural gas marketing subsidiary in Florida, extend credit to counter-parties. Whileterms we believe Xeron and PESCO utilize prudent credit policies, each of these subsidiaries is exposed to the risk that it may not be able to collect amounts owed to it. If the counter-party to such a transaction fails to perform and any underlying collateral is inadequate, we could experience financial losses.

Xeron and PESCO are dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If the financial condition of these subsidiaries declines, or if our financial condition 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.

Our use of derivative instruments may adversely affect our results of operations.
Fluctuating commodity prices cause our earnings and financing costs to be impacted. Our propane distribution and wholesale marketing segment uses derivative instruments, including forwards, swaps and puts, to hedge price risk. In addition,reasonable. Specifically, we have utilized in the past, and may decide, after further evaluation, to continue to utilize derivative instruments to hedge price risk for our Delaware and Maryland divisions, as well as PESCO. 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 conditions may be adversely impacted.

Inability to access the capital markets may impair our future growth.
We rely on access to both short-term and longer-termlong-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flowflows from our operations. Currently, $55$40 million of the total $80$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.

Page 14     Chesapeake Utilities Corporation 2009 Form 10-K

Unsound financial institutions could adversely affect the Company.
WeOur 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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 15

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.
Page 16     Chesapeake Utilities Corporation 2009 Form 10-K

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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 17

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 constructionprice outlook. We may purchase large volumes of new facilitiespropane 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 support future growthvolatile fluctuations in earningsresponse 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 utilitiesprofits 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 interstate pipeline.reliability our natural gas and electric distribution systems could adversely affect the results of operations, cash flows and financial condition.
ConstructionOur 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 facilitiescosts 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 regulatory, development and operational risks, include but not limitedincluding 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.
Page 18     Chesapeake Utilities Corporation 2009 Form 10-K

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 obtain necessary approvalsaddress the rapidly changing needs of our customers by developing and permits by regulatory agenciessupplying high-quality, cost-effective products, product enhancements and services, on a timely basis, and on termsby 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 acceptablenot properly matched to us; potential changesour exposure, our results of operations, cash flows, and financial condition may be adversely affected.
Changes in federal, statecustomer growth may affect earnings and local statutescash flows.
Our ability to increase gross margins in our regulated energy and regulations, including environmental requirements,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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 19

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 prevent a project from proceeding or increase the anticipated cost of the project; impediments oncould disrupt our ability to acquire rights-of-waymeet customer requirements. Terrorist attacks may also disrupt capital markets and our ability to raise capital. A terrorist attack on our facilities, or land rights onthose of our suppliers or customers, could result in a timely basis on terms that are acceptable to us; lacksignificant decrease in revenues or a significant increase in repair costs, which could adversely affect our results of anticipated future growthoperations, 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, supply;as well as our results of operations, our ability to raise capital and lackour 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 transportationterror could result in disruptions of crude oil, electricity or throughput commitments.

We are subject to operating and litigation risks that may not be covered by insurance.
Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing 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, to end users. Aselectricity and natural gas if our means of supply transportation, such as rail, power grid or pipeline, become damaged as a result we are sometimesof an attack. A lower level of economic activity following such events could result in a defendantdecline in legal proceedings and litigation arisingenergy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the ordinary coursefinancial markets as a result of business.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 coveragescoverage and deductibles as we believe are reasonable and prudent. There can be no assurance;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.
Page 20     Chesapeake Utilities Corporation 2009 Form 10-K

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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 21

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;
- Page 11 -
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.
Page 22     Chesapeake Utilities Corporation 2009 Form 10-K

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. PropertiesProperties.
(a)General
(a)  
General
The Company ownsWe own offices and operatesoperate 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. Chesapeake rentsWe rent office space in Dover, and Ocean View, and South Bethany, Delaware; Jupiter, Fernandina and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton, and Salisbury, Maryland; Honey Brook and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In general, the Company believeswe believe that its propertiesour offices and facilities are adequate for the uses for which they are employed. Capacity and utilization of the Company’s facilities can vary significantly due to the seasonal nature of the
(b)Natural Gas Distribution
Our Delmarva natural gas and propane distribution businesses.

(b)  
Natural Gas Distribution
Chesapeakeoperation owns over 9651,102 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in itsour Delaware and Maryland service areas. Our Florida natural gas distribution operations, including Chesapeake’s Florida division and FPU in its service areas, and 726own 2,404 miles of natural gas distribution mains (and related equipment). Additionally, we have adequate gate stations to handle receipt of the gas in its central Florida service areas. Chesapeakeeach of the distribution systems. We also ownsown facilities in Delaware and Maryland, which we use for propane-air injection during periods of peak demand.

(c)Natural Gas Transmission
(c)  
Natural Gas Transmission
Eastern ShoreESNG owns and operates approximately 366384 miles of transmission pipelinespipeline, extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, PennsylvaniaPennsylvania; and Hockessin, Delaware, to approximately 7580 delivery points in southeastern Pennsylvania, Delaware and the eastern shoreEastern Shore of Maryland.

PIPECO owns and operates approximately eight miles of transmission pipeline in Suwanee County, Florida.
(d)  
Propane Distribution and Wholesale Marketing
(d)Electric Distribution
The company’sCompany’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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 23

(e)Propane Distribution and Wholesale Marketing
Our Delmarva-based propane distribution operation owns bulk propane storage facilities, with an aggregate capacity of approximately 2.02.4 million gallons, at 42 plant facilities in Delaware, Maryland, Pennsylvania and Virginia, located on real estate that is either owned or leased. The Company’sleased by the Company. Our Florida-based propane distribution operation owns three21 bulk propane storage facilities with a total capacity of 66,000642,000 gallons. Xeron does not own physical storage facilities or equipment to transport propane; however, it leases propane storage capacity and pipeline capacity.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 ProceedingsProceedings.
(a)  
General
(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 legal and 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 ourthe Company’s consolidated financial position.position and results of operations.

(b)  
Environmental
(b)Environmental
See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note M.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:
None
(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.
Page 24     Chesapeake Utilities Corporation 2009 Form 10-K

- Page 12 -
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.
NameAgePosition
John R. Schimkaitis62Vice Chairman and Chief Executive Officer
Michael P. McMasters51President and Chief Operating Officer
Beth W. Cooper43Senior Vice President and Chief Financial Officer
Stephen C. Thompson49Senior Vice President and President, ESNG
Joseph Cummiskey38Vice 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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 25

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:
(a)Common Stock Price Ranges, Common Stock Dividends and Shareholder Information:
The Company’s Common Stockcommon stock is listed on the New York Stock ExchangeNYSE under the symbol “CPK.” The high, low and closing prices of Chesapeake’s Common Stockthe Company’s common stock and dividends declared per share for each calendar quarter during the years 20062009 and 20052008 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 
             

Quarter Ended
 
High
 
Low
 
Close
 
Dividends Declared Per Share
 
2006
         
March 31
 
$
32.47
 
$
29.97
 
$
31.24
 
$
0.285
 
June 30
  
31.20
  
27.90
  
30.08
 
$
0.290
 
September 30
  
35.65
  
29.51
  
30.05
 
$
0.290
 
December 31
  
31.31
  
29.10
  
30.65
 
$
0.290
 
              
2005
             
March 31 $27.59 $25.83 $26.60 $0.280 
June 30  30.95  23.60  30.58 $0.285 
September 30  35.60  29.50  35.16 $0.285 
December 31  35.78  30.32  30.80 $0.285 

Holders

At December 31, 2009, there were 2,670 holders of record of Chesapeake common stock.
Dividend paymentsDividends
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. WeNo securities were sold no securities during the year 20062009 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 stringent restrictions staterestrictive 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 must maintain equityaccrued on and after January 1, 2001. As of at least 40 percent of total capitalization and the pro-forma fixed charge coverage ratio must be at least 1.5 times. The Company was in compliance with these restrictions and the other debt covenants during 2006.
At December 31, 2006, there were 1,978 shareholders2009, Chesapeake’s cumulative consolidated net income base was $102.8 million, offset by Restricted Payments of record$63.8 million, leaving $39.0 million of cumulative net income free of restrictions.
Page 26     Chesapeake Utilities Corporation 2009 Form 10-K

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 Common Stock.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.
- Page 13 -

(b)  
Purchases of Equity Securities by the Issuer
(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 Stockcommon stock during the quarter ended December 31, 2006.2009.
                 
  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   —   — 
             

Period
 
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
 
Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
 
October 1, 2006 through October 31, 2006 (1)
  463 $29.92  0  0 
November 1, 2006 through November 30, 2006  0 $0.00  0  0 
December 1, 2006 through December 31, 2006  0 $0.00  0  0 
Total  463 $29.92  0  0 
              
(1) Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on shares held in Rabbi Trust accounts for certain Senior Executives. During the quarter, 463 shares were purchased through executive dividend deferrals.
 
(2) Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.
 

(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 onof compensation plans of Chesapeake and its subsidiaries, for which shares of Chesapeake common stock are authorized for issuance, is incorporated herein by reference toincluded in the portion of the Proxy Statement captioned “Equity Compensation Plan Information” to be filed notno later than March 31, 20072010, in connection with the Company’s Annual Meeting to be held on or about May 2, 2007.5, 2010 and, is incorporated herein by reference.

(c)  
Chesapeake Utilities Corporation Common Stock Performance Graph
(c)Chesapeake Utilities Corporation Common Stock Performance Graph
The following stock Performance Graph compares the yearly percentage change in cumulative total shareholder return on the Company’sa hypothetical investment in our common stock during the five fiscal years ended December 31, 2006,2009, with the cumulative total shareholder return on a hypothetical investment in both (i) the Standard & Poor’s 500 Index (“S&P 500 IndexIndex”), and (ii) an industry index consisting of 30Chesapeake and 11 of the companies in the current Edward Jones Natural Gas Distribution and IntegratedGroup, 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 CompaniesDistribution Group as publishedour peer group to which our performance is compared for purposes of determining the level of long-term performance awards earned by C.A Turner Utility Reports.

our named executives.
The thirtyeleven companies in the C.A. TurnerEdward Jones Natural Gas Distribution Group industry index are as follows:include: AGL Resources, Inc., Atmos Energy Corporation, Cascade Natural Gas Corporation, Chesapeake Utilities Corporation, Delta Natural Gas Company, Inc., El Paso Corporation, Energen Corporation, Energy West, Inc., EnergySouth. Inc., Equitable Resources, Inc., KeySpan Corporation, Kinder Morgan, Inc., The Laclede Group, Inc., National Fuel Gas Company, New Jersey Resources Corporation, NICOR, Inc., Northwest Natural Gas Company, ONEOK, Inc., Peoples Energy Corporation, Piedmont Natural Gas Co., Inc., Questar Corporation, RGC Resources, Inc., SEMCO Energy, Inc., South Jersey Industries, Inc., Southern Union Company, Southwest Gas Corporation, Southwest Energy Company, UGI Corporation,Inc, and WGL Holdings, Inc., and The Williams Companies, Inc.
-Chesapeake Utilities Corporation 2009 Form 10-K     Page 14 -27


The comparison assumes $100 was invested on December 31, 20012004 in the Company’sour common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the Graphgraph below are based on historical data and are not intended to forecast the possible future performance of the Company’s Common Stock.our common stock.
                         
  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 

Page 28     Chesapeake Utilities Corporation 2009 Form 10-K



  
Cumulative Total Stockholder Return
 
  
2001
 
2002
 
2003
 
2004
 
2005
 
2006
 
Chesapeake
 $100 $98 $145 $155 $186 $192 
Industry Index
 $100 $96 $121 $156 $200 $236 
S & P 500
 $100 $78 $100 $111 $116 $134 

- Page 15 -

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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 29

                           
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 
                    
For the Years Ended December 31,
 
2006 (3)
 
2005
 
2004
 
2003
 
2002
 
Operating (in thousands of dollars) (1)
           
Revenues           
Natural gas 
$
170,374
 $166,582 $124,246 $110,247 $93,588 
Propane  
48,576
  48,976  41,500  41,029  29,238 
Advanced informations systems  
12,568
  14,140  12,427  12,578  12,764 
Other and eliminations  
(317
)
 (68) (218) (286) (334)
Total revenues 
$
231,201
 $229,630 $177,955 $163,568 $135,256 
                 
Operating income                
Natural gas 
$
19,733
 $17,236 $17,091 $16,653 $14,973 
Propane  
2,534
  3,209  2,364  3,875  1,052 
Advanced informations systems  
767
  1,197  387  692  343 
Other and eliminations  
(103
)
 (112) 128  359  237 
Total operating income 
$
22,931
 $21,530 $19,970 $21,579 $16,605 
                 
Net income from continuing operations 
$
10,507
 $10,468 $9,550 $10,079 $7,535 
                 
                 
Assets (in thousands of dollars)
                
Gross property, plant and equipment 
$
325,836
 $280,345 $250,267 $234,919 $229,128 
Net property, plant and equipment (2)
 
$
240,825
 $201,504 $177,053 $167,872 $166,846 
Total assets (2)
 
$
324,994
 $295,980 $241,938 $222,058 $223,721 
Capital expenditures (1)
 
$
48,969
 $33,423 $17,830 $11,822 $13,836 
                 
                 
Capitalization (in thousands of dollars)
                
Stockholders' equity 
$
111,152
 $84,757 $77,962 $72,939 $67,350 
Long-term debt, net of current maturities  
71,050
  58,991  66,190  69,416  73,408 
Total capitalization 
$
182,202
 $143,748 $144,152 $142,355 $140,758 
Current portion of long-term debt 
$
7,656
 $4,929 $2,909 $3,665 $3,938 
Short-term debt  
27,554
  35,482  5,002  3,515  10,900 
Total capitalization and short-term financing 
$
217,412
 $184,159 $152,063 $149,535 $155,596 
                 
(1) These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
 
(2) SFAS 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001.
 
(3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
 
Page 30     Chesapeake Utilities Corporation 2009 Form 10-K

             
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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 31

                           
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.
Page 32     Chesapeake Utilities Corporation 2009 Form 10-K

- Page 16 -
Item 6. Selected Financial Data

For the Years Ended December 31,
 
2001
 
2000
 
1999
 
1998
 
1997
 
Operating (in thousands of dollars) (1)
           
Revenues           
Natural gas $107,418 $101,138 $75,637 $68,770 $88,108 
Propane  35,742  31,780  25,199  23,377  28,614 
Advanced informations systems  14,104  12,390  13,531  10,331  7,786 
Other and eliminations  (113) (131) (14) (15) (182)
Total revenues $157,151 $145,177 $114,353 $102,463 $124,326 
                 
Operating income                
Natural gas $14,405 $12,798 $10,388 $8,820 $9,240 
Propane  913  2,135  2,622  965  1,137 
Advanced informations systems  517  336  1,470  1,316  1,046 
Other and eliminations  386  816  495  485  558 
Total operating income $16,221 $16,085 $14,975 $11,586 $11,981 
                 
Net income from continuing operations $7,341 $7,665 $8,372 $5,329 $5,812 
                 
                 
Assets (in thousands of dollars)
                
Gross property, plant and equipment $216,903 $192,925 $172,068 $152,991 $144,251 
Net property, plant and equipment (2)
 $161,014 $131,466 $117,663 $104,266 $99,879 
Total assets (2)
 $222,229 $211,764 $166,958 $145,029 $145,719 
Capital expenditures (1)
 $26,293 $22,057 $21,365 $12,516 $13,471 
                 
                 
Capitalization (in thousands of dollars)
                
Stockholders' equity $67,517 $64,669 $60,714 $56,356 $53,656 
Long-term debt, net of current maturities  48,409  50,921  33,777  37,597  38,226 
Total capitalization $115,926 $115,590 $94,491 $93,953 $91,882 
Current portion of long-term debt $2,686 $2,665 $2,665 $520 $1,051 
Short-term debt  42,100  25,400  23,000  11,600  7,600 
Total capitalization and short-term financing $160,712 $143,655 $120,156 $106,073 $100,533 
                 
(1) These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
 
(2) SFAS 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001.
 
(3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
 
- Page 17 -
Item 6. Selected Financial Data

For the Years Ended December 31,
 
2006 (3)
 
2005
 
2004
 
2003
 
2002
 
Common Stock Data and Ratios
           
Basic earnings per share from continuing operations (1)
 
$
1.74
 $1.79 $1.66 $1.80 $1.37 
Diluted earnings per share from continuing operations (1)
 
$
1.72
 $1.77 $1.64 $1.76 $1.37 
                 
Return on average equity from continuing operations (1)
  
10.7
%
 12.9% 12.7% 14.4% 11.2%
                 
Common equity / total capitalization  
61.0
%
 59.0% 54.1% 51.2% 47.8%
Common equity / total capitalization and short-term financing  
51.1
%
 46.0% 51.3% 48.8% 43.3%
                 
Book value per share 
$
16.62
 $14.41 $13.49 $12.89 $12.16 
                 
                 
Market price:                
High 
$
35.650
 $35.780 $27.550 $26.700 $21.990 
Low 
$
27.900
 $23.600 $20.420 $18.400 $16.500 
Close 
$
30.650
 $30.800 $26.700 $26.050 $18.300 
                 
                 
Average number of shares outstanding  
6,032,462
  5,836,463  5,735,405  5,610,592  5,489,424 
Shares outstanding at year-end  
6,688,084
  5,883,099  5,778,976  5,660,594  5,537,710 
Registered common shareholders  
1,978
  2,026  2,026  2,069  2,130 
                 
Cash dividends declared per share 
$
1.16
 $1.14 $1.12 $1.10 $1.10 
Dividend yield (annualized) (2)
  
3.8
%
 3.7% 4.2% 4.2% 6.0%
Payout ratio from continuing operations (1) (4)
  
66.7
%
 63.7% 67.5% 61.1% 80.3%
                 
                 
Additional Data
                
Customers                
Natural gas distribution and transmission  
59,132
  54,786  50,878  47,649  45,133 
Propane distribution  
33,282
  32,117  34,888  34,894  34,566 
                 
                 
Volumes                
Natural gas distribution and transmission deliveries (in MMCF)  
34,321
  34,981  31,430  29,375  27,935 
Propane distribution (in thousands of gallons)  
24,243
  26,178  24,979  25,147  21,185 
                 
                 
Heating degree-days (Delmarva Peninsula)                
Actual HDD  
3,931
  4,792  4,553  4,715  4,161 
10 -year average HDD (normal)  
4,372
  4,436  4,389  4,409  4,393 
                 
Propane bulk storage capacity (in thousands of gallons)  
2,315
  2,315  2,045  2,195  2,151 
                 
Total employees (1)
  
437
  423  426  439  455 
                 
(1) These amounts exclude the results of water services due to their reclassification to discontinued operations. The 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) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
 
(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.
 
- Page 18 -
Item 6. Selected Financial Data

For the Years Ended December 31,
 
2001
 
2000
 
1999
 
1998
 
1997
 
Common Stock Data and Ratios
           
Basic earnings per share from continuing operations (1)
 $1.37 $1.46 $1.63 $1.05 $1.17 
Diluted earnings per share from continuing operations (1)
 $1.35 $1.43 $1.59 $1.04 $1.15 
                 
Return on average equity from continuing operations (1)
  11.1% 12.2% 14.3% 9.7% 11.1%
                 
Common equity / total capitalization  58.2% 55.9% 64.3% 60.0% 58.4%
Common equity / total capitalization and short-term financing  42.0% 45.0% 50.5% 53.1% 53.4%
                 
Book value per share $12.45 $12.21 $11.71 $11.06 $10.72 
                 
                 
Market price:                
High $19.900 $18.875 $19.813 $20.500 $21.750 
Low $17.375 $16.250 $14.875 $16.500 $16.250 
Close $19.800 $18.625 $18.375 $18.313 $20.500 
                 
                 
Average number of shares outstanding  5,367,433  5,249,439  5,144,449  5,060,328  4,972,086 
Shares outstanding at year-end  5,424,962  5,297,443  5,186,546  5,093,788  5,004,078 
Registered common shareholders  2,171  2,166  2,212  2,271  2,178 
                 
Cash dividends declared per share $1.10 $1.07 $1.03 $1.00 $0.97 
Dividend yield (annualized) (2)
  5.6% 5.8% 5.7% 5.5% 4.7%
Payout ratio from continuing operations (1) (4)
  80.3% 73.3% 63.2% 95.2% 82.9%
                 
                 
Additional Data
                
Customers                
Natural gas distribution and transmission  42,741  40,854  39,029  37,128  35,797 
Propane distribution  35,530  32,117  35,267  34,113  33,123 
                 
                 
Volumes                
Natural gas distribution and transmission deliveries (in MMCF)  27,264  30,830  27,383  21,400  23,297 
Propane distribution (in thousands of gallons)  23,080  28,469  27,788  25,979  26,682 
                 
                 
Heating degree-days (Delmarva Peninsula)                
Actual HDD  4,368  4,730  4,082  3,704  4,430 
10 -year average HDD (normal)  4,446  4,356  4,409  4,493  4,574 
                 
Propane bulk storage capacity (in thousands of gallons)  1,958  1,928  1,926  1,890  1,866 
                 
Total employees (1)
  458  471  466  431  397 
                 
(1) These amounts exclude the results of water services due to their reclassification to discontinued operations. The 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) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
 
(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.
 
- Page 19 -
Management's Discussion and Analysis

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

INTRODUCTION
This section provides management’s discussion of Chesapeake Utilities Corporation and its consolidated subsidiaries, with specific information on results of operations and liquidity and capital resources.resources, as well as discussion on how certain accounting principles affect our financial statements. It includes management’s interpretation of our financial results of the Company and its operating segments, the factors affecting these results, the major factors expected to affect future operating results, and future 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”.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.

EXECUTIVE OVERVIEW
Exec 
Chesapeake is a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses.

The Company’s 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 natural gas distribution and transmission business through expansion into new geographic areas 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 the Company’s expertise across our various businesses to improve overall performance.
·  Enhancing marketing channels to attract new customers and providing reliable and responsive customer service to retain existing customers.
·  Maintaining a capital structure that enables the Company to access capital as needed.
·  Maintaining a consistent and competitive dividend.

In 2006, the Company earned $10,507,000 in net income, or $1.72 per share (diluted), in spite of weather that was the second warmest in the last thirty years. In 2005, net income was $10,468,000, or $1.77 per diluted share. Overall, operating income in 2006 increased $1,401,000, or 6.5 percent from 2005, despite weather that was 18 percent warmer than in 2005. However, the increase in operating income was offset by a decline of $194,000, or 51 percent, in other income, net of other expenses, and increases in interest expense of $644,000, or 12.5 percent, and income taxes of $525,000, or 8.3 percent. The net result was that net income was up by only $39,000, or 0.4 percent.

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 gas cost forof 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 Generally Accepted Accounting Principles (“GAAP”). Chesapeake believesGAAP. 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 non-regulated segments.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.
- Page 20 -
Management's Discussion and Analysis

Operating Income
The year 2006 reflects the strong year-over-year operating income growth experienced by the Company’s natural gasIn addition, certain information is presented, which excludes for comparison purposes, result of operations of $2,497,000,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 14.5 percent. This growth was offset by reductionsthrough subsidiaries, in operating income from propaneregulated energy businesses, unregulated energy businesses, and other unregulated businesses, including advanced information services. In 2006, both
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;
Chesapeake Utilities Corporation 2009 Form 10-K     Page 33

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 segments were negatively impacteddistribution 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 weather thatChesapeake in the merger was 18 percent warmer thanapproximately $75.7 million, which included approximately $16,000 paid in 2005. The Company estimates thatcash and 2,487,910 shares of common stock issued at a price per share of $30.42. Net fair value of the warmer weather reduced gross margin by $3.4assets 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 2006. The natural gas segmentmerger-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 able to overcome the weather impact and show an increase in operating income due to its growth and cost containment efforts. However, as the propane segment is more weather sensitive and is not experiencing the high level of growth of our natural gas segment, its operating income declined when$15.9 million, or $2.15 per share (diluted), compared to 2005.$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.

Advanced information services experiencedThe following is a decreasesummary of key factors affecting our businesses and their impacts on our 2009 results. More detailed discussion and analysis are provided in operating income in 2006 as compared to the prior year due in part to the gain on the sale“Results of Lightweight Association Management Processing System (“LAMPSTM”) during the fourth quarter of 2005. The LAMPS product was internally developed software that was developed and marketed specifically for REALTOR® Associations.


Key financial and operational highlights for fiscal year 2006 include the following:

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 and propane businesses remained strong, withdistribution divisions achieved customer growth in 2009 compared to 2008, which contributed $1.2 million in gross margin for the Delmarva andyear. Chesapeake’s Florida natural gas distribution operations registering 9 and 8 percent increasesdivision experienced a net customer loss in residential customers, respectively; and the Delmarva Community Gas Systems (“CGS”) generating2009, which resulted in a 34 percent increase in propane distribution customers.

·  In June 2006, Eastern Shore Natural Gas announced that it had received approval from the Federal Energy Regulatory Commission (“FERC”) to expand its pipeline system in the years 2006, 2007 and 2008. The entire project represents an investmentgross margin decrease of $33.6 million, with expected annualized revenue$190,000. A loss of $6.7 million after the full build-out of the facilities.

·  On September 26, 2006, the Company received approval for a base rate increase from the Maryland Public Service Commission (“PSC”) for our Maryland natural gas operations, with the new base rates effective October 1, 2006. The base rate adjustment results in an increase in base rates of approximately $780,000, which would result in an average increase in revenues of approximately 4.5 percent for the Company’s firm residential, commercial andthree large industrial customers in Maryland.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.
Page 34     Chesapeake Utilities Corporation 2009 Form 10-K

•
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 PSC also approvedabsence of similar inventory valuation adjustments in 2009 and increased margin generated from the Company’s proposallow propane cost during the first half of 2009, coupled with sustained retail prices, contributed to implement a revenue normalization mechanismincreased 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 residential heating and smaller commercial heating customers, reducing the Company’s future risk dueDelaware City refinery operation. Late in 2009, Valero announced its intention to weather and usage changes.

·  In November 2006, the Company completed a public offeringpermanently shut down that refinery. While PESCO’s sale to Valero in 2009 represented approximately 19 percent of 600,300 shares of its common stock at a price per share of $30.10. Additionally, in November 2006, the Company completed the sale of 90,045 additional shares of its common stock, pursuant to the over-allotment option granted to the Underwriters by the Company. The net proceeds of approximately $19.7 million, after the deduction of underwriting commissions and expenses from the sale of the common stock, were added to the Company’s general funds and primarily used to repay a portion of the Company’s short-term debt.

·  Total capitalization, including short-term borrowing, increased $33.3 million at December 31, 2006 compared with December 31, 2005. The increased capitalization was obtained to fund the $39.3 million increase in net plant and for other working capital needs.

·  For the year ended December 31, 2006, the Company generated $30.1 million in operating cash flow compared with $13.6 millionPESCO’s total revenue for the year, ended December 31, 2005. The higher cost ofspot 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 propanecompensation adjustments, which reduced operating costs in 2005 had an adverse impact on2009 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 in 2005.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.
- Page 21 -
Management's Discussion and Analysis

·  Net property, plant and equipment increased to $240.8 million at December 31, 2006 from $201.5 million at December 31, 2005, primarily reflecting continued capital investment to support customer growth.

·  In June 2006, Eastern Shore announced the Bay Crossing Project for which it plans to develop, construct and operate new pipeline facilities that would transport natural gas from Calvert County, Maryland, cross under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula where such facilities would interconnect with its existing facilities in Sussex County, Delaware. If completed, the project will expand the capacity of its interstate pipeline system by approximately 33 percent. We still have significant obstacles to overcome on this project to make it a reality. In 2007, Eastern Shore will initiate the processes required to obtain the FERC and other federal, state and local permits required to construct the project. Eastern Shore received approval from the FERC in August 2006 to recover the pre-service costs associated with this pipeline project through its rates from two of its customers. As of December 31, 2006, the Company had deferred a total of $409,000 of pre-service costs associated with the project.

The Company’s financial performance is discussed in greater detail below in Results of Operations.


(c) Critical Accounting Policies
Chesapeake’sWe prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported financial conditionamounts 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 operations are affected bywhich form the accounting methods, assumptionsbasis for making judgments about the carrying value of assets and estimatesliabilities that are used in the preparation of the Company’s financial statements. Becausenot readily apparent from other sources. Since most of Chesapeake’sour businesses are regulated and the accounting methods used by Chesapeakethese businesses must comply with the requirements of the regulatory bodies; therefore,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 Chesapeake’sour Audit Committee.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 35

Regulatory Assets and Liabilities
Chesapeake recordsAs a result of the ratemaking process, we record certain assets and liabilities in accordance with Statement of FinancialFASB Accounting Standards Codification (“SFAS”ASC”) No. 71 “Accounting forTopic 980, “Regulated Operations,” consequently, the Effects of Certain Types of Regulation.”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. At December 31, 2006, Chesapeake hadAs 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 $3.0$21.1 million including $1.1 million for under-recovered purchased gas costs, $1.3 million for tax-related regulatory assets, $139,000 for defined postretirement benefits, and $122,000 for environmental cost recovery. The Company has recorded regulatory liabilities totaling $23.8of $46.3 million, including $18.4 million for accrued asset removal cost, $2.4 million for over-recovered purchased gas costs, $1.2 million for self-insurance, $1.2 million for cash in/cash out, and $349,000 for over-collected environmental costs at December 31, 2006.2009. If the Companywe were required to terminate application of SFAS No. 71, itthis 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 a chargean adjustment could have a material adverse effect on the Company’sour results of operations.

Valuation of Environmental Assets and Liabilities
As more fully described in Note MItem 8 under the heading “Notes to the Consolidated Financial Statements Chesapeake has– Note O, Environmental Commitments and Contingencies,” we have completed itsour responsibilities related to one environmental site and isare currently participating in the investigation, assessment or remediation of threeseven 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. Additionally,In addition, there is uncertainty duewith regard to the outcome of legal remedies soughtamounts 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, 2006, Chesapeake had2009, we have recorded an environmental regulatory assetsasset of $122,000$7.5 million and a regulatory liability of $350,000 for over-collections and an additional liability of $212,000$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.
- Page 22 -
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.
Page 36     Chesapeake Utilities Corporation 2009 Form 10-K

Management's Discussion and Analysis

Propane Wholesale Marketing Contracts
Chesapeake’sXeron, our propane wholesale marketing operationsubsidiary, enters into forward, futures and futuresother contracts that are considered derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In accordance with the pronouncement, open positionsderivatives. These contracts are marked to marketmarked-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. Therevenue or expense. These contracts allgenerally mature within one year and are almost exclusively for propane commodities with delivery points of Mt. Belvieu, Texas, Conway, Kansas and Hattiesburg, Mississippi. Management estimatescommodities. For the market valuation based on references to exchange-traded futures prices, historical differentials and actual trading activity at the end of the reporting period. Atyears ended December 31, 2006,2009 and 2008, these contracts had net unrealized gainslosses of $8,500 that was recorded in the financial statements. At December 31, 2005, these contracts had$1.6 million and net unrealized gains of $46,000 that were recorded in the financial statements.$1.4 million, respectively.

Operating Revenues
Revenues for theour natural gas and electric distribution operations of the Company are based on rates approved by the public service commissions (“PSC”)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. However, the regulatory authoritiesThe PSCs, however, have granted the Company’sauthorized our regulated natural gas distribution operations the ability to negotiate rates, based on approved methodologies, with customers that have competitive alternatives using approved methodologies. In addition, the natural gas transmission operation canalternatives. The FERC has also authorized ESNG to negotiate rates above or below the FERC approved tariffFERC-approved maximum rates, which customers can elect as a recourse to negotiated rates.

Chesapeake’sFor regulated deliveries of natural gas distribution operations in Delaware and Maryland eachelectricity, 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 a gas cost recovery mechanism that provides forbeen delivered, but not yet billed, at the adjustmentend of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.

The Company charges flexible ratesan accounting period to the extent that they do not coincide. In connection with this accrual, we must estimate amounts of natural gas distribution’s industrial interruptibleand 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 to make them competitive with alternative types of fuel. Based on pricing, thesemeters, such as community gas system customers, can chooseand natural gas or alternative types of supply. Neithermarketing customers, whose billing cycles do not coincide with the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

accounting periods.
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in the Company’sour income statement, for open contracts. The natural gas segment recognizes revenue on an accrual basis. Thestatement. For certain propane distribution customers without meters and advanced information services and other segmentscustomers, 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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 37

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.
Page 38     Chesapeake Utilities Corporation 2009 Form 10-K

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 
                   

Net Income & Diluted Earnings Per Share Summary
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Net Income *
             
Continuing operations 
$
10,507
 $10,468 $39 $10,468 $9,550 $918 
Discontinued operations  
-
  -  -  -  (121) 121 
Total Net Income 
$
10,507
 $10,468 $39 $10,468 $9,429 $1,039 
                    
Diluted Earnings Per Share
                   
Continuing operations 
$
1.72
 $1.77  ($0.05)$1.77 $1.64 $0.13 
Discontinued operations  
-
  -  -  -  (0.02) 0.02 
Total Earnings Per Share 
$
1.72
 $1.77  ($0.05)$1.77 $1.62 $0.15 
                    
* Dollars in thousands.
                   
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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 39

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.
- Page 23 -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.
Management's DiscussionWe continued to invest in property, plant and Analysis

equipment in 2009 to support current and future growth opportunities, expending $26.3 million for such purposes.

2008 Compared to 2007
The Company’sOur net income from continuing operations increased $39,000by $389,000 in 2006 when2008 compared to 2005. Net income was $10.50 million, or $1.72 per share (diluted), for 2006, compared to a net income of $10.47 million, or $1.77 per share (diluted).

The Company’s net income from continuing operations increased $918,000, or 10 percent, in 2005 compared to 2004.2007. Net income from continuing operations was $10.5$13.6 million, or $1.77$1.98 per share (diluted), for 2008, compared to a net income from continuing operations of $9.6$13.2 million, or $1.64$1.94 per share (diluted), in 2007. Our 2008 results include a charge of $1.2 million for 2004.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).

Page 40     Chesapeake Utilities Corporation 2009 Form 10-K

During 2003, Chesapeake2007, we decided to exitclose the waterdistributed energy services business and had sold the assets of six of seven dealerships by December 31, 2003. The remaining operation was sold incompany, Chesapeake OnSight Services, LLC (“OnSight”), which consistently experienced operating losses since 2004. The results of water servicesoperations for OnSight were classified asto discontinued operations for year 2004. Discontinuedand shown net of tax. The discontinued operations experienced lossesa net loss of $0.02 per share (diluted)$20,000 for 2004.2007.


Operating Income Summary (in thousands)
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Business Segment:
             
Natural gas 
$
19,733
 $17,236 $2,497 $17,236 $17,091 $145 
Propane  
2,534
  3,209  (675) 3,209  2,364  845 
Advanced information services  
767
  1,197  (430) 1,197  387  810 
Other & eliminations  
(103
)
 (112) 9  (112) 128  (240)
Total Operating Income
 
$
22,931
 $21,530 $1,401 $21,530 $19,970 $1,560 

2006 ComparedOur operating income increased by $365,000 in 2008 compared to 2005
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 2006 increased $1.4 million, or 6.5 percent, greater than 2005, despite adverse weather, which when measured in terms of heating degree-days, was 18 percent warmer. The improved 2006 results of operations when2008 compared to 2005 were impacted by:
·  Weather on the Delmarva Peninsula was 18 percent warmer in 2006 than 2005, which the Company estimates to have cost approximately $3.42007. Our regulated energy segment achieved an increase of $2.9 million in gross margin for its Delmarva natural gas and propane distribution operations.
·  Strong residential customer growth of 9 percent and 8 percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2006.
·  The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent, due to additional capacity contracts that went into effect in November 2005 and November 2006.
·  A 67 percent increase in the number of customers for the Company’s natural gas marketing operation.
·  Gross margin for the Delmarva propane distribution operations decreased $834,000, primarily from the warmer weather in 2006.
·  The Delmarva Community Gas Systems continue to experience strong customer growth as the number of customers increased 34 percent in 2006 compared to 2005.
·  
Operating income for the advanced information services segment decreased $430,000 in 2006. Although revenues from consulting increased $749,000 in 2006, the 2005 results contained $993,000 of operating income for the LAMPSTM product, which was sold in the fourth quarter 2005.

2005 Compared to 2004
The improvement in results for 2005 versus 2004 was primarily driven by:
·  The LAMPS™ product, including the sale of its property rights, contributed $622,000 to operating income in 2005 for the Company’s advanced information services segment.
·  The Delmarva and Florida natural gas distribution operations experienced strong residential customer growth of 9 percent and 7 percent, respectively, in 2005.
- Page 24 -
Management's Discussion and Analysis
·  Temperatures on the Delmarva Peninsula were 5 percent colder than 2004, which led to increased contributions from the Company’s natural gas and propane distribution operations. This increase was offset by conservation efforts by customers.
·  The natural gas transmission operation achieved gross margin growth of 9 percent due to additional transportation capacity contracts that went into effect in November 2004.
·  A 100 percent increase in the number of customers for the Company’s natural gas marketing operation.
·  An increase of 1.1 million gallons sold by the Delmarva propane distribution operation.


Natural Gas Distribution, Transmission, and Marketing
The natural gas segment earned operating income of $19.7 million for 2006, $17.2 million for 2005, and $17.1 million for 2004, resulting in increases of $2.5 million, or 14.5 percent, for 2006 and $145,000, or 1.0 percent, for 2005.

Natural Gas Distribution, Transmission, and Marketing (in thousands)
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Revenue 
$
170,374
 $166,582 $3,792 $166,582 $124,246 $42,336 
Cost of gas  
117,948
  116,178  1,770  116,178  77,456  38,722 
Gross margin  
52,426
  50,404  2,022  50,404  46,790  3,614 
                    
Operations & maintenance  
22,673
  23,874  (1,201) 23,874  21,129  2,745 
Depreciation & amortization  
6,312
  5,682  630  5,682  5,418  264 
Other taxes  
3,708
  3,612  96  3,612  3,152  460 
Other operating expenses  
32,693
  33,168  (475) 33,168  29,699  3,469 
                    
Total Operating Income
 
$
19,733
 $17,236 $2,497 $17,236 $17,091 $145 

Heating Degree-Day (HDD) and Customer Analysis
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Heating degree-day data — Delmarva             
Actual HDD  
3,931
  4,792  (861) 4,792  4,553  239 
10-year average HDD  
4,372
  4,436  (64) 4,436  4,383  53 
                    
Estimated gross margin per HDD 
$
2,013
 $2,234  ($221)$2,234 $1,800 $434 
                    
Estimated dollars per residential customer added:                   
Gross margin 
$
372
 $372 $0 $372 $372 $0 
Other operating expenses 
$
111
 $106 $5 $106 $104 $2 
                    
Average number of residential customers                   
Delmarva  
40,535
  37,346  3,189  37,346  34,352  2,994 
Florida  
12,663
  11,717  946  11,717  10,910  807 
Total  
53,198
  49,063  4,135  49,063  45,262  3,801 

2006 Compared to 2005
Gross margin for the Company’s natural gas segment increased $2.0 million, or 4 percent, and other operating expenses decreased $475,000, or 1 percent, in 2006 compared to 2005. The gross margin increases of $1.8 million forfrom new services provided by the natural gas transmission operation, $395,000four-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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 41

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.
Page 42     Chesapeake Utilities Corporation 2009 Form 10-K

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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 43

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.
Page 44     Chesapeake Utilities Corporation 2009 Form 10-K

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 and $75,000increased 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 marketing operation were partially offset by lower gross margin of $210,000 for the Delmarva natural gas distribution operations.
- Page 25 -
Management's Discussion and Analysis

Natural Gas Transmissionmarketers.
The natural gas transmission operation achieved gross margin growth of $1.8$1.7 million or 11 percent. Of the $1.8in 2008, $1.2 million increase, $1.1 millionof which was attributedattributable to new transportationtransmission capacity contracts implemented in November 20052007 and $612,000 due to new transportation capacity contracts implemented in November 2006.2008. In addition, the implementation of rate case settlement rates, effective September 1, 2007, the new transportation capacity contracts implemented in November 2006 are expected to generatecontributed an additional gross margin of $3.3 million above and beyond 2006 gross margins. An increase of $416,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses are as follow:

·  Payroll costs and incentive compensation increased $108,000 to serve the additional growth experienced by the operation.
·  Higher depreciation and asset removal costs of $558,000 and increased property taxes of $109,000 due to an increase in the level of capital investment.
·  A reduction of $376,000 as a result of the operation receiving approval from the FERC to recover certain pre-service costs associated with the Bay Crossing Project. Please refer to the Regulatory Matters section under Other Matters within Item 2 of the Management’s Discussion and Analysis for additional details. As a result of this approval, the Company is deferring the pre-service costs that it incurs. In 2006, the Company deferred $188,000 of costs previously incurred and expensed in 2005. As a result of this deferral, the amounts recognized in the Company’s income statement have declined from 2005 by $376,000.
·  There was an increase of approximately $17,000 in other operating expenses relating to various minor items.

Natural Gas Marketing
Gross margin for the natural gas marketing operation increased $75,000 for 2006 compared to 2005. The increase was attained primarily from an increase in the number of customers to which it provides supply management services. Other operating expenses decreased $78,000 for the operation due to lower levels of consulting services, partially offset by an increase in the allowance for uncollectible accounts.

Natural Gas Distribution
Gross margin for the Florida distribution operation increased by $395,000. The impact of an 8 percent growth in residential customers contributed $230,000 to gross margin. In addition to residential customer growth, new commercial and industrial customers contributed $91,000$439,000 to gross margin in 2006.2008. The remaining $74,000$61,000 increase into gross margin is attributedwas attributable primarily to various factors, including turn-on revenue.higher interruptible sales revenue, net of required margin-sharing.

The Delmarva distribution operations experienced a decrease of $210,000 in gross margin. Weather significantly impacted gross margin in 2006 compared to 2005 as temperatures on the Delmarva Peninsula were 18 percent warmer in 2006. The Company estimates that the warmer temperatures in 2006 led to a decrease in gross margin of approximately $1.7 million when compared to 2005. This decrease was partially offset by continued residential customer growth. The average number of residential customers on the Delmarva Peninsula increased 3,189, or 9 percent, for 2006 compared to 2005 and the Company estimates these additional residential customers contributed approximately $1.2 million to gross margin. The remaining $190,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial customers and decrease of interruptible sales.

Other Operating Expenses
Other operating expenseexpenses for the natural gas distribution operations decreased $814,000 in 2006 comparedregulated energy segment increased by approximately $766,000, due primarily to 2005. Some of the key components of the decrease in other operating expenses in 2006, compared to 2005, include the following:

·  Health care costs decreased by $313,000 as a result of the Company changing health care service providers in November 2005 and has subsequently experienced lower costs related to claims.
·  Allowance for uncollectible accounts decreased by $289,000 in 2006 compared to 2005 due to lower revenues and increased collection efforts. Revenues are down due to lower prices and warmer temperatures.
·  Incentive compensation decreased $177,000 in 2006 to reflect lower than expected earnings
·  Lower corporate costs due to lower payroll and related expenses.
·  Depreciation and amortization expense and asset removal cost increased $132, 000 and $186, 000, respectively, as a result of the Company’s continued capital investments.
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.
- Page 26 -
Management's DiscussionDepreciation expense and Analysis
·  Merchant payment fees increased $136,000 in 2006 compared to 2005 as the Company experienced more customers making payments with the use of credit cards.
·  In addition, there is an increase of approximately $55,000 in other operating expenses relating to various minor items.

2005 Compared to 2004
Gross margin for the Company’s natural gas segment increased $3.6asset removal costs decreased by approximately $1.5 million, or 8 percent, which was partially offset by higher other operating expenses of $3.5 million in 2005 compared to 2004. Each of the natural gas operations experienced year-over-year increases in gross margin in 2005, primarily from customer growth, colder temperatures, and changes in rate design.

Natural Gas Transmission
The natural gas transmission operation achieved gross margin growth of $1.4 million, or 9 percent, primarily due to additional contracts signed in November 2004 for transportation capacity provided to its firm customers. In addition, the Company’s capital investments enabled the natural gas transmission operations to execute additional transportation capacity contracts in November 2005. An increase of $980,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses were associated with continued economic growth, as well as higher depreciation and property taxes due to an increase in the level of capital investments.

Natural Gas Marketing
Gross margin for the natural gas marketing operation increased $506,000, or 39 percent, for 2005 compared to 2004 as the number of customers to which it provides supply management services increased 100 percent. The increase in gross margin was partially offset by an increase of $352,000 in other operating expenses due to higher levels of staff and other operating costs necessary to support the increase in business.

Natural Gas Distribution
Gross margin for the Delaware and Maryland distribution divisions increased $1.2 million, as temperatures in 2005 were 5 percent colder than 2004 and the number of residential customers increased 8.7 percent. An increase in gross margin from the colder weather of $534,000 was offset by a decrease of $651,000 in gas deliveries to customers as a result of conservation effortsour Delaware distribution operation’s rate proceedings in response2008 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 gas prices. Gross margin for the Florida distribution operationslevel of capital investment and adjusted property assessments by various jurisdictions.
Vehicle-related costs increased $579,000, primarilyby $132,000 due to changes inhigher fuel and depreciation charges.
Information technology costs increased by approximately $517,000 as a result of higher spending to improve the customer rate designinfrastructure, including system performance, disaster recovery and a 7.4 percent increase insupport.
Corporate overhead costs allocated to the number of residential customers served. The Company estimates the rate design changes contributed $322,000 in additional gross margin and resulted in the Florida division collecting a greater percentage of revenues from fixed charges, rather than variable charges based upon consumption. Other operating expense for the natural gas distribution operationsregulated energy segment increased $2.1 million in 2005. Some of the key components of the increase in other operating expenses in 2005,by approximately $385,000 as previously discussed.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 45

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 2004, include the following:
·  The incremental operating and maintenance cost of supporting the residential customers added by the Delmarva and Florida distribution operations was approximately $403,000.
·  In response to higher natural gas prices, the Company increased its allowance for uncollectible accounts by $98,000.
·  The cost of providing health care for our employees increased $180,000.
·  Costs of line location activities increased $177,000.
·  With the additional capital investments, depreciation expense, asset removal cost and property taxes increased $225,000, $130,000 and $319,000, respectively.

- Page 27 -
Management's Discussion and Analysis

Propane
The propane segment experienced a decrease of $675,000 in operating income in 2006 compared to 2005, reflecting a gross margin decrease of $1.1 million, which was partially offset by a decrease in operating expenses of $464,000.
During 2005, the propane segment increased operating income by $845,000, or 36 percent, over 2004. Gross margin in 2005 increased $2.6 million over 2004, which more than offset the increase of $1.7 million of operating expenses.


Propane (in thousands)
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Revenue 
$
48,576
 $48,976  ($400)$48,976 $41,500 $7,476 
Cost of sales  
30,780
  30,041  739  30,041  25,155  4,886 
Gross margin  
17,796
  18,935  (1,139) 18,935  16,345  2,590 
                    
Operations & maintenance  
12,823
  13,355  (532) 13,355  11,718  1,637 
Depreciation & amortization  
1,659
  1,574  85  1,574  1,524  50 
Other taxes  
780
  797  (17) 797  739  58 
Other operating expenses  
15,262
  15,726  (464) 15,726  13,981  1,745 
                    
Total Operating Income
 
$
2,534
 $3,209  ($675)$3,209 $2,364 $845 

Propane Heating Degree-Day (HDD) Analysis — Delmarva
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Heating degree-days                   
Actual  
3,931
  4,792  (861) 4,792  4,553  239 
10-year average  
4,372
  4,436  (64) 4,436  4,383  53 
                    
Estimated gross margin per HDD 
$
1,743
 $1,743 $0 $1,743 $1,691 $52 

2006 Compared to 20052008
Operating income for the propaneunregulated energy segment decreased $675,000, or 21 percent, to $2.5increased by approximately $4.4 million for 2006in 2009 compared to 2005. This decrease2008, which was due primarilyattributable to warmera 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 2006, which resulted2009 increased gross margin by $1.2 million, as temperatures were seven percent colder in reduced customer consumption.2009, compared to 2008. Gross margin in the Delmarva propane distribution operations was lower when compared to 2005 by $834,000, primarily due to warmer weather. Gross margin also decreased infor 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 Company’slarger 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.
Page 46     Chesapeake Utilities Corporation 2009 Form 10-K

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 by $146,000 and $159,000, respectively.

Delmarva Propane Distribution$1.5 million for the natural gas marketing operation.
The Delmarva propane distribution operation’s decrease in gross margin of $834,000$3.1 million resulted from the following items:
·  Volumes sold in 2006 decreased 1.9 million gallons, or 8 percent, primarily from temperatures on the Delmarva Peninsula being 18 percent warmer during 2006 when compared to 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.7 million when compared to 2005.
·  Gross margin increased $956,000 from an increase of $0.0302 in the average gross margin per retail gallon in 2006 compared to 2005.
·  Gross margin for the Delmarva CGS increased $155,000 when compared to the prior period, primarily from an increase in the average number of customers. The average number of customers increased by approximately 1,000 to a total count of approximately 3,900, or a 34 percent increase, when compared to 2005. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide for an additional 7,700 customers.
·  Gross margin was adversely impacted by a $272,000 write-down of propane inventory to reflect the lower of cost or market.
following:
- Page 28 -
Management's Discussion and Analysis
·  The remaining grossGross margin decrease of $29,000 is attributed primarily to customer conservation and changes in the timing of deliveries to customers.

Other operating expenses decreased $335,000 for the Delmarva operationsby $1.1 million in 2006,2008, compared to 2005. The significant items contributing to the2007, primarily because of a $0.04 decrease are explained below.
·  The Company recovered $387,000 in fixed costs from one of its propane suppliers in response to a propane contamination incident that occurred in March 2006. The Company identified that approximately 75,000 gallons of propane that it purchased from the supplier contained above-normal levels of petroleum byproducts.
·  Health care costs decreased by $324,000. The Company changed health care service providers in November 2005 and has subsequently experienced lower costs related to claims.
·  In addition, there is a decrease of approximately $39,000 in other operating expenses relating to various minor items.
·  These lower costs were partially offset by increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, increased payroll costs of $165,000 and higher costs of $74,000 associated with vehicle fuel.

Florida Propane Distribution
The Florida propane distribution operation experienced a decrease in gross margin of $146,000, or 12 percent, when compared to the same period in 2005. The lower gross margin reflects a decrease of $208,000 for in-house piping sales as the operation exited the house piping service, which was partially offset by an increase in gross margin of $62,000 from propane sales. The increase in gross margin from propane sales was attained primarily from an increase in the average gross margin per retail gallon partially offset by a 1 percent decreaseattributable to inventory write-downs of approximately $800,000 during 2008 in the volumes sold in 2006. Florida propane experienced a decrease in other operating expenses in 2006 comparedresponse to 2005 of $49,000 attributed to lower payroll and benefits costs due to vacant positions during the year, partially offset by higher expenses related to leak testing and depreciation expense.

Propane Wholesale and Marketing
Gross margin for the Company’s propane wholesale marketing operation decreased by $159,000 in 2006 compared to 2005. This decrease from the 2005 results reflects the increased market opportunities that rose in 2005 due to the extreme price volatility in the propane wholesale market from rising propane prices following the hurricanes in the Gulf of Mexico area. The same level of price fluctuations was not experienced in 2006. The decrease in gross margin was partially offset by lower other operating expenses of $79,000 attributed primarily to lower incentive compensation as a result of the lower earnings in 2006.

2005 Compared to 2004
Operating income for the propane segment increased $846,000, or 36 percent, to $3.2 million for 2005 compared to 2004. Gross margin in the Delmarva propane distribution operations was higher when compared to 2004 by $1.8 million, primarily due to colder weather. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $385,000 and $445,000, respectively.

Delmarva Propane Distribution
The gross margin increase for the propane segment was due primarily to an increase of $1.8 million for the Delmarva distribution operations. Volumes sold in 2005 increased 1.1 million gallons or 5 percent. Temperatures in 2005 were 5 percent colder than 2004, causing an estimated gross margin increase of $417,000. Additionally, the gross margin per retail gallon improved by $0.0342 in 2005 compared to 2004. Gross margin per gallon increased as a result of market prices rising greater thanbelow the Company’s inventory price per gallon. This trend reverses
Chesapeake Utilities Corporation 2009 Form 10-K     Page 47

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 prices decrease and move closerprice of propane had plummeted well below the unit price in the swap agreement. As a result, we marked the agreement relating to the Company’s inventory price per gallon. TheJanuary 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 increase was partially offset by increased other operating expensesapproximately $867,000 for the Delmarva propane distribution operation. Factors contributing to this decrease in gallons sold included customer conservation and the timing of $1.5 million. The higher other operating costs were attributablepropane 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 Pennsylvania start-up costs and expensesprior year’s levels, despite realizing a charge to cost of sales of $494,000 as the December gallons related to higher earnings, such as incentive compensation and other taxes, employee benefits, insurance, vehicle fuel and maintenance expenses, and a non-recurring credit of $100,000 for vehicle insurance audits in 2004. The Pennsylvania start-up costs accounted for $722,000, or approximately 49 percent, of the increase in operating expenses.
this plan were valued at current market prices.
- Page 29 -
Management's DiscussionTemperatures 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 Analysis

Florida Propane Distribution
Grossdecreased 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 operations increased $385,000, or 45 percent, in 2005 compared to 2004. The increase in gross margin was attained from an increase of 27% in the average number of customers, which contributed to the $267,000 in propane sales gross margin, and an increase of $118,000 in house-piping sales. Florida propane also experienced an increase in other operating expenses of $147,000 attributed to business growth, such as payroll, vehicle fuel and maintenance, insurance, and depreciation expense.

Propane Wholesale and Marketing
The Company’s propane wholesale marketing operation experienced an increase in gross margin of $445,000$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.
Page 48     Chesapeake Utilities Corporation 2009 Form 10-K

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 $121,000$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 otherrecent 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 leading to an improvement of $323,000decreased by $90,000 in 2009. The decrease in operating income over 2004. Wholesale price volatility created trading opportunities duringexpenses was attributable primarily to the thirdcost containment actions, including layoffs and fourth quarters ofcompensation adjustments, implemented by the year; however, these were partiallyadvanced information service operation in 2009 to reduce costs to offset the decline in revenues. This decrease was offset by reduced trading activities particularlythe increased merger-related costs.
2008 Compared to 2007
Operating income for the “Other” segment decreased by approximately $1.2 million in the first half2008 compared to 2007, which was attributable to a gross margin decrease of the year when the wholesale marketing operation followed a conservative marketing strategy, which lowered risk$122,000 and earnings, in lightan operating expense increase of continued high wholesale price levels.$1.0 million.

Gross margin

Advanced Information Services
TheOur advanced information services segment provides domestic and international clients with information technology related business services and solutions for both enterprise and e-business applications. The advanced information services businessoperation contributed operating income of $767,000 for 2006, $1.2 million for 2005, and $387,000 for 2004.


Advanced Information Services (in thousands)
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Revenue 
$
12,568
 $14,140  ($1,572)$14,140 $12,427 $1,713 
Cost of sales  
7,082
  7,181  (99) 7,181  7,015  166 
Gross margin  
5,486
  6,959  (1,473) 6,959  5,412  1,547 
                    
Operations & maintenance  
4,119
  5,129  (1,010) 5,129  4,405  724 
Depreciation & amortization  
113
  123  (10) 123  138  (15)
Other taxes  
487
  510  (23) 510  482  28 
Other operating expenses  
4,719
  5,762  (1,043) 5,762  5,025  737 
                    
Total Operating Income
 
$
767
 $1,197  ($430)$1,197 $387 $810 
2006 Compared to 2005
Operating income for advanced information services business decreased $430,000 to $767,000 for 2006 compared to $1.2 million in 2005. The operating income for 2005 included operating income of $993,000 for LAMPS™, inclusive of a $924,000 pre-tax gain on the salemost of the product. The LAMPSTM product was sold to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc., in October 2005.

Revenuesgross margin for the period decreased $1.6 million compared“Other” segment. Gross margin for our advanced services operation declined by approximately $152,000, which was attributable to 2005, due primarilya decrease of $610,000 in consulting revenues as higher average billing rates were not able to elimination of $1.9 million of revenue generated by the LAMPSTM product in 2005. Consulting revenues increased $749,000 in 2006 when compared to 2005, primarily from offeringovercome a new service, Managed Database Administration (“MDBA”), to its customers in 2006 and an increase of 7.6 percentnine-percent decrease in the average hourly billing rate, whilenumber of billable consulting hours. The reduction in the number of billable hours remained at the same levelwas a result of 2005.economic conditions in which information technology spending broadly declined. The MDBA service provides third parties with professional database monitoring and support solutions during business hours or around the clock. The MDBA service contributed $470,000 to consulting revenues. Partially offsetting the increasedecrease in consulting revenues were decreases of $128,000 and $244,000 from training andwas partially offset with increased product sales and other revenues, respectively.
- Page 30 -
Management's Discussion and Analysis

Cost of sales for 2006 decreased $99,000 to $7.08 million, compared to 2005. The 2005 cost of sales of $7.18 million included $401,000 related to LAMPSTM. Absent the cost of sales associated with the LAMPSTM product, cost of sales increased in 2006 compared to 2005 to support the higher revenues.

Other operating expenses decreased $1.0 million in 2006 to $4.7 million, when compared to 2005. The reduction in expenses primarily reflects expenses of $554,000 in 2005 associated with LAMPSTM and lower benefits costs, rent expense and consulting costs.

2005 Compared to 2004
The advanced information services segment had operating income of $1.2 million and $387,000 for years 2005 and 2004, respectively. The results for 2005 and 2004 include revenues and costs related to the LAMPSTM product that was sold in October 2005, which resulted in a $924,000 pre-tax gain.

Revenues for 2005 increased $1.7 million to $14.1 million compared totraining revenues of $12.4 million for 2004. The 2005$403,000 and 2004 revenue figures include $2.4 million and $149,000 of revenue relating to the LAMPSTM product for those respective years. Decreases in consulting revenues for the eBusiness group of $793,000 and lower sales of Progress software licenses of $285,000 accounted for the decrease in revenue when compared to 2004. This decrease was partially offset by the performance revenue of $238,000 received in the third quarter 2005 and an increase of $317,000 in consulting revenues for the Enterprise Solutions group. The performance revenue was related to the sale of the webproEX software that took place in 2003. As part of the sale agreement, $47,000, respectively.
Chesapeake received a percentage of revenues after certain annual revenue and performance targets were reached.Utilities Corporation 2009 Form 10-K     Page 49


Cost of sales for 2005 increased $165,000 to $7.2 million, compared to $7.0 million for 2004. The increase in cost of sales was attributed to the LAMPSTM product. The 2005 and 2004 cost of sales figures included $511,000 and $345,000 of cost for the LAMPSTM product. Other operating expenses increased $738,000 in 2005 to $5.8 million, compared to $5.0 million in 2004. The increase in other operating costexpenses in 2008 was attributedprimarily related to the increase of costs relating to the LAMPSTM product. The costs associated with the LAMPSTM product for 2005 and 2004 were $1.2 million and $575,000 respectively. The remaining increase was primarily due to health care claims and office rent, whichin merger-related costs in 2008 that were offset by cost containment measures implementedexpensed in the second quarter of 20052008 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 reduce operating expenses.2007.


Other Operations and EliminationsIncome
Other operations consistincome 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 subsidiaries$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.
Page 50     Chesapeake Utilities Corporation 2009 Form 10-K

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 own real estate leasedwere determined to other Company subsidiariesbe 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 Energy, LLC (“OnSight”). Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries generated an operating loss of $103,000 for 2006 compared to an operating loss of $112,000 for 2005. The operating loss in both 2006 and 2005 is attributed to results of OnSight.

The Company formed OnSight in 2004 to provide distributed energy services. Distributed energy refers to a variety of small, modular power generating technologies that may be combined with heating and/or cooling systems. For 2006, OnSight had an operating loss of $401,000 compared to an operating loss of $390,000 for 2005. The higher operating loss in 2006 when compared to 2005 is the result of:

·  In the third quarter of 2006, actions were taken to reduce operating expenses going forward, which resulted in a charge of $65,000 to other operating expenses associated with staff reductions.
- Page 31 -
Management's Discussion and Analysis
·  The 2005 results of operation includes the impact of OnSight completing its first and only contract to date, which occurred in the second quarter of 2005.


Other Operations & Eliminations (in thousands)
 
              
For the Years Ended December 31,
 
2006
 
2005
 
Increase (decrease)
 
2005
 
2004
 
Increase (decrease)
 
Revenue 
$
620
 $763  ($143)$763 $647 $116 
Cost of sales  
1
  116  (115) 116  -  116 
Gross margin  
619
  647  (28) 647  647  - 
                    
Operations & maintenance  
479
  472  7  472  278  194 
Depreciation & amortization  
163
  220  (57) 220  210  10 
Other taxes  
83
  97  (14) 97  63  34 
Other operating expenses  
725
  789  (64) 789  551  238 
                    
Operating Income — Other  
($106
)
 ($142)$36  ($142)$96  ($238)
Operating Income — Eliminations 
$
3
 $30  ($27)$30 $32  ($2)
                    
Total Operating Income (Loss)
  
($103
)
 ($112)$9  ($112)$128  ($240)

Discontinued Operations
In 2003, Chesapeake decided to exit the water services business. Six of seven water dealerships were sold during 2003 and the remaining operation was sold in October 2004. The results of the water companies’ operations, for all periods presented in the consolidated income statements, have been reclassified to discontinued operations and shown net of tax. For 2004, thetax for all periods presented. The discontinued operations experienced a net loss of $121,000. The Company$20,000 for 2007. We did not have any discontinued operations in 20062008 and 2005.2009.

Income Taxes
Income tax expense for 2006 was $6.8 million compared to $6.3 million for 2005. Income taxes increased in 2006 compared to 2005, due primarily to increased taxable income. Income taxes increased in 2005 compared to 2004, due to increased income. The effective current federal income tax rate for 2006 and 2005 was 35 percent, whereas the rate for 2004 was 34 percent. During 2006, 2005, and 2004, the Company realized benefit of $220,000, $223,000, and $205,000, respectively, from a change in the tax law that allows tax deductions for dividends paid on Company stock held in Employee Stock Ownership Plans (“ESOP”).
Other Income
Other income was $189,000, $383,000, and $549,000 for the years 2006, 2005, and 2004, respectively. The other income amounts for the years 2006 and 2005 consist of interest income, compared to interest income and gains from the sale of assets for the year 2004.
Interest Expense
Total interest expense for 2006 increased approximately $644,000, or 12.5 percent, compared to 2005. The increase reflects the increase in the average short-term debt balance and higher short-term interest rates in 2006 compared to 2005. The average short-term borrowing balance increased $21.2 million in 2006 to $26.9 million compared to $5.7 million in 2005. The large year-over-year increase in the average short-term borrowing balance was primarily to finance the $39.3 million of net property, plant, and equipment added in 2006. The weighted average interest rate for short-term borrowing increased from 4.47 percent for 2005 to 5.47 percent for 2006. The average long-term debt balance during 2006 was $67.2 million with a weighted average interest rate of 6.98 percent, compared to $67.4 million with a weighted average interest rate of 7.18 percent for 2005. The Company also capitalized $586,000 of interest as part of capital project costs during 2006.
- Page 32 -
Management's Discussion and Analysis

Total interest expense for 2005 decreased approximately $135,000, or 2.6 percent, compared to 2004. The decrease reflects the decrease in the average long-term debt balance. The average long-term debt balance during 2005 was $67.4 million with a weighted average interest rate of 7.18 percent, compared to $71.3 million with a weighted average interest rate of 7.17 percent in 2004. The average short-term borrowing balance in 2005 was $5.7 million, an increase from $870,000 in 2004. The weighted average interest rate for short-term borrowing increased from 3.72 percent for 2004 to 4.47 percent for 2005. The Company also capitalized $136,000 of interest as part of capital project costs during 2005.

(e) Liquidity and Capital Resources
Chesapeake’sOur capital requirements reflect the capital-intensive nature of itsour business and are principally attributable to its investment in new plant and equipment and the retirement of outstanding debt. The Company reliesWe rely on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures.
During 2006,2009, net cash provided by operating activities was $30.1$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 $48.9$31.2 million, and cash provided by financing activities was $20.7$1.7 million.

During 2005,2007, net cash provided by operating activities was $13.6$25.7 million, cash used by investing activities was $33.1$31.3 million, and cash provided by financing activities was $20.4$3.7 million.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 51

As of December 31, 2006, the Board of Directors (“Board”) has authorized the Company to borrow up to $55.0 million of short-term debt from various banks and trust companies under short-term lines of credit. During 2006, the Board authorized increases in the Company’s borrowing authority up to $75 million to fund the 2006 capital budget and working capital. The $75 million limit was subsequently reduced to its current level by the Board on November 7, 2006, following the placement on October 12, 2006 of $20 million 5.50 percent Senior Notes.

On December 31, 2006, the Company2009, we had four unsecured bank lines of credit with two financial institutions, totaling $80.0for a total of $90.0 million, none of which requiredrequires 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 the Company’sour short-term cash needs to meet seasonal working capital requirements and to fund temporarily fund portions of itsthe capital expenditures. Twoexpenditure 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 $15.0$60.0 million, are committed. The other twoAdvances offered under the uncommitted lines of credit are subject to the banks’ availabilitydiscretion of funds.the banks. The outstanding balancesbalance of short-term debtborrowing at December 31, 20062009 and 2005 were $27.62008 was $30.0 million and $35.5$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 $20$30 million of 5.55.93 percent Unsecured Senior Notes in October 2006 and from2008. This reduction was offset in late 2009 by the proceeds ofincreased working capital requirements after the issuance of 600,300 shares of common stock in November 2006.FPU merger.

Chesapeake hasWe have budgeted $45.5$53.9 million for capital expenditures during 2007.2010. This amount includes $20.2$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 $16.5 million foroperation ($20.2 million), natural gas transmission $7.5 million for propaneoperation ($25.4 million) and electric distribution and wholesale marketing, $154,000 for advanced information services and $915,000 million for other operations. The natural gas distribution and transmission expenditures areoperation ($3.6 million) for expansion and improvement of facilities. The amount for the unregulated energy segment includes estimated capital expenditures for the propane expenditures are to supportdistribution operations for customer growth and for the replacement of equipment. The amount for the “Other” segment includes an estimated capital expenditure of $288,000 for the advanced information services expenditures areoperation with the remaining balance for computer hardware, software and related equipment. The other category includes general plant, computer software and hardware. Financing forWe expect to fund the 20072010 capital expenditureexpenditures program is expected 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 acquisition opportunities, 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.
Page 52     Chesapeake Utilities Corporation 2009 Form 10-K

- Page 33 -
Management's Discussion and Analysis

Chesapeake expects to incur approximately $75,000 in 2007The following presents our capitalization as of December 31, 2009 and 2008, for environmental-related expenditures. Additional expenditures may be requiredif short-term borrowing and the current portion of long-term debt were included in future years (see Note Mcapitalization:
                 
  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 the Consolidated Financial Statements). Management does not expect financing of future environmental-related expendituresmaintaining a sound capital structure and strong credit ratings to have a material adverse effect onprovide the financial position orflexibility needed to access capital resourcesmarkets 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 the Company.these objectives will provide benefits to our customers, creditors and investors.

Cash Flows Provided by Operating Activities
Our cash flows provided by (used in) 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 
          

For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Net income 
$
10,506,525
 $10,467,614 $9,428,767 
Non-cash adjustments to net income  
11,186,418
  13,059,678  16,342,116 
Changes in working capital  
8,424,055
  (9,927,351) (3,767,730)
Net cash from operating activties
 
$
30,116,998
 $13,599,941 $22,003,153 

Year-over-yearPeriod-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. The changescapital. Changes in working capital are impacteddetermined by a variety of factors, including weather, the priceprices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, purchases, and deferred gasfuel cost recoveries.

The Company generatesWe generate a large portion of itsour 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 Delmarva natural gas and propane distribution operations to our 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.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 53

During this period, our accounts payable increased to reflect payments due to providers of the natural gas, propane commodities and pipeline capacity. The value of the natural gas and propane can vary significantly from one period to the next as a result of volatility in the prices of these commodities. Our natural gas costs and deferred purchased natural gas costs due from, or to, our customers represent the difference between natural gas costs that we have paid to suppliers in the past and amounts that we have collected from customers. These natural gas costs can cause significant variations in cash flows from period to period.

In 2006,2009, our net cash flow provided by operating activities was $30.1$45.8 million, an increase of $16.5$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 same period of 2005. The increase waschange 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 a result of the recovery of working capital during 2006 that was deployed in 2005 due to the significantlytiming 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 commodity prices and the amountover-collection of working capital required for operations. Contributing to this increase was a decrease in the amount ofpurchased gas costs by our Delmarva natural gas and propane purchased for inventory of $6.1 million as a result of mild weather in the prior heating season and therefore higher inventory balances for the current heating season.distribution operation.

In 2005,2008, our net cash flow provided by operating activities was $13.6$28.5 million, a decreasean increase of $8.4$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 same periodtiming of 2004. The decrease wascollections 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 increased working capital requirements including increased spending of $5.7 millionhigher tax deductions provided by the 2008 Economic Stimulus Act; and
Cash flows provided by non-cash adjustments for seasonal natural gas and propane inventoriesdeferred income taxes. The increase in advance ofdeferred income taxes is the winter sales demand. We spent more on these inventories in 2005 primarily becauseresult of higher natural gas and propane prices due tobook-to-tax timing differences during the effects ofperiod that were generated by the hurricanes in the Gulf Coast region. The Company also used $1.2 million of cash to purchase investmentsEconomic Stimulus Act, which authorized bonus depreciation for the Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. See Note E on Investments in Item 8 under the heading “Financial Statements and Supplemental Data.”
certain assets.
Cash Flows Used in Investing Activities
NetIn 2009, net cash flows used inby investing activities totaled $48.9$23.1 million, $33.1a decrease of $8.1 million and $15.5compared to 2008. In 2008, net cash flows used by investing activities totaled $31.2 million, during fiscal years 2006, 2005, and 2004, respectively. In fiscal years 2006, 2005, and 2004, $48.8which remained relatively unchanged from net cash flows used by investing activities of $31.3 million $33.3 million, and $16.4 million, respectively,in 2007.
We acquired $359,000 in cash, net of cash werepaid, 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. Additionsexpenditures 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 2006 were primarily for natural gas transmission ($28.0 million), natural gas distribution ($16.1 million) and propane distribution ($4.3 million). In both 2006 and 2005, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. Natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system.

2007.
- Page 34 -54     Chesapeake Utilities Corporation 2009 Form 10-K

Management's Discussion and Analysis
Cash Flows Provided by Financing Activities
Cash flows provided by financing activities totaled $20.7 million during 2006, $20.4 million during 2005 andIn 2009, net cash flows used by financing activities was $8.0totaled $21.4 million, for 2004. Our significantcompared to net cash flow provided by financing activities for the years 2006, 2005,of $1.7 million and 2004 are summarized as follow:

·  In November 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, pursuant to a shelf registration statement declared effective in November 2006, generating net proceeds of $19.7 million.

·  In October 2006, the Company placed $20 million of 5.5 percent Senior Notes (“Notes”) to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). The original note agreement was executed on October 18, 2005 and provided for the Company to sell the Notes at any time prior to January 15, 2007.

·  The Company repaid $4.9 million of long-term debt during 2006 compared with $4.8 million during 2005 and $3.7 million during 2004.

·  During 2006, the Company reduced short-term debt by $8.0 million. During 2005 and 2004, net borrowing of short-term debt increased by $29.6 million and $1.2 million, respectively, primarily to support our capital investment.

·  During 2006, the Company paid $6.0 million in cash dividends compared with dividend payments of $5.8 million and $5.6 million for years 2005 and 2004, respectively. The increase in dividends paid over prior year reflects the increase in the dividend rate from $1.14 per share during 2005 to $1.16 per share during 2006 and the issuance of additional shares of common stock.

·  In August 2006, the Company paid cash of $435,000, in lieu of issuing shares of the Company’s common stock for the 30,000 stock warrants outstanding at December 31, 2005.


Capital Structure
The following presents our capitalization as of December 31, 2006 and 2005:

  
December 31,
 
  
2006
 
2005
 
  (In thousands, except percentages) 
Long-term debt, net of current maturities 
$
71,050
  
39
%
$58,990  41%
Shareholders' equity 
$
111,152
  
61
%
$84,757  59%
Total capitalization, excluding short-term debt 
$
182,202
  
100
%
$143,747  100%

The Company increased its capitalization by $38.5 million in 2006 compared2008 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 2005. The increased capitalization was primarily used to fundsupport our capital investments.
In October 2008, we completed the $39.3placement of $30.0 million of net property, plant, and equipment added in 2006 and for working capital.

As of December 31, 2006, common equity represented 615.93 percent of total capitalization, compared to 59 percent in 2005.
Unsecured Senior Notes.
- Page 35 -
Management's Discussion and Analysis

The following presents our capitalization as of December 31, 2006 and 2005 if short-term borrowing and current portionWe repaid $10.9 million of long-term debt were included in capitalization:

  
December 31,
 
  
2006
 
2005
 
  (In thousands, except percentages) 
Short-term debt 
$
27,554
  
13
%
$35,482  19%
Long-term debt, including current maturities 
$
78,706
  
36
%
$63,919  35%
Shareholders' equity 
$
111,152
  
51
%
$84,757  46%
Total capitalization, including short-term debt 
$
217,412
  
100
%
$184,158  100%

If short-term borrowing and current portionduring 2009, compared to $7.7 million of long-term debt were included in capitalization, total capitalization increased by $33.3repaid during each of 2008 and 2007.
We paid $8.0 million, $7.8 million and $7.0 million in 2006 compared to 2005. The increased capitalization was primarily used to fund a portion ofcash dividends in 2009, 2008 and 2007, respectively. An increase in cash dividends paid in each year reflects the $39.3 million of net property, plant, and equipment added in 2006 and for other general working capital. In addition, if short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 51 percent and 46 percent for 2006 and 2005, respectively.

Total debt as a percentage of total capitalization, including short-term debt, was 49 percent and 54 percent at December 31, 2006 and 2005, respectively. The decreasegrowth in the debt-to-capitalization ratio in 2006 was primarily attributed to the following:

·  The Company sold 600,300 additional shares of common stock pursuant to a shelf registration declared effective by the SEC in November 2006. The sale of these additional shares increased total shareholder’s equity by approximately $19.7 million.

·  The outstanding long-term debt balance increased $14.8 million. Contributing to the increase was the placement of $20 million of 5.5 percent Senior Notes in October 2006, partially offset by scheduled principal payments.

·  The outstanding short-term debt balance decreased $7.9 million. The Company reduced its outstanding short-term debt with funds received from the sale of additional shares of common stock and the placement of the Senior Notes.

Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as to the Company’s investors.
Shelf Registration
In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In November 2006, we sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. The net proceeds from the sale were used for general corporate purposes, including financing of capital expenditures, repayment of short-term debt, and general working capital purposes. At December 31, 2006, the Company had approximately $20.0 million remaining under this registration statement.
annualized dividend rate.
- Page 36 -
Management's Discussion and Analysis

Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2006:2009:
                     
  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.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 55

  
Payments Due by Period
 
Contractual Obligations
 
Less than 1 year
 
1 - 3 years
 
3 - 5 years
 
More than 5 years
 
Total
 
Long-term debt (1)
 $7,656,364 $14,312,727 $14,403,636 $42,333,636 $78,706,363 
Operating leases (2)
  649,659  919,216  652,026  3,769,640  5,990,541 
Purchase obligations (3)
                
Transmission capacity  7,182,746  12,413,145  8,154,556  23,523,355  51,273,802 
Storage — Natural Gas  1,363,488  2,698,742  2,666,955  5,163,488  11,892,673 
Commodities  17,862,123           17,862,123 
Forward purchase contracts — Propane (4)
  13,868,391           13,868,391 
Unfunded benefits (5)
  292,445  588,705  614,043  2,710,528  4,205,721 
Funded benefits (6)
  323,500  148,364  117,732  1,419,046  2,008,642 
Total Contractual Obligations
 
$
49,198,716
 
$
31,080,899
 
$
26,608,948
 
$
78,919,693
 
$
185,808,256
 
                 
(1) Principal payments on long-term debt, see Note H, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item. The expected interest payments on long-term debt are $5.2 million, $8.8 million, $6.9 million and $10.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $ 30.9 million.
 
(2) See Note J, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
 
(3) See Note N, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information.
 
(4) The Company has also entered into forward sale contracts. See "Market Risk" of the Management's Discussion and Analysis for further information.
 
(5) The Company has recorded long-term liabilities of $4.2 million at December 31, 2006 for unfunded post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 65 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) The Company has recorded long-term liabilities of $2.0 million at December 31, 2006 for funded benefits. These liabilities have been funded using a Rabbi Trust and an asset in the same amount is recorded under Investments on the Balance Sheet. The defined benefit pension plan was closed to new participants on January 1, 1999 and participants in the plan on that date were given the option to leave the plan. See Note K, "Employee Benefit Plans," in the Notes to the Consolidated Financial Statements for further information on the plan. Since the plan modification, no additional funding has been required from the Company and none is expected for the next five years, based on factors in effect at December 31, 2006. However, this is subject to change 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.
 

Off-Balance Sheet Arrangements
The Company hasWe have issued corporate guarantees to certain vendors of itsour subsidiaries, primarily the propane wholesale marketing subsidiary itsand the natural gas supply and management subsidiary, and propane distributionmarketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’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.Statements when incurred. The aggregate amount guaranteed at December 31, 2006, totaled $21.42009 was $22.7 million, with the guarantees expiring on various dates in 2007.

2010.
In addition to the corporate guarantees, the Company haswe have issued a letter of credit to itsour primary insurance company for $775,000,$725,000, which expires on MayAugust 31, 2007.2010. The letter of credit is provided as security for claims amounts to satisfy the deductibles under our various insurance policies. There have been no draws on the Company’s policies. The currentthis letter of credit was renewed during the second quarteras of 2006 when the insurance policies were renewed.December 31, 2009.

(f) Rate Filings and Other Regulatory Activities
The Company’sOur natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions. Eastern Shore Natural Gas (“Eastern Shore”). The Company’s natural gas transmission operationtheir respective PSC; ESNG is subject to regulation by the FERC.
- Page 37 -
Management's DiscussionFERC; and Analysis

Delaware. On September 1, 2006, the Delaware division filed its annual Gas Sales Service Rates (“GSR”) application that was effective for service rendered on and after November 1, 2006 with the Delaware Public Service Commission (“Delaware PSC”). On October 3, 2006, the Delaware PSC approved the GSR charges,PIPECO is subject to full evidentiary hearings and a final decision. The Delaware division expects a final decision during the first half of 2007.

On September 2, 2005, the Delaware division filed an application with the Delaware PSC requesting approval of an alternative rate design and rate structure in order to provide natural gas service to prospective customers in eastern Sussex County. While Chesapeake does provide natural gas service to residents and businesses in portions of Sussex County, under the Company’s current tariff, natural gas distribution lines have not been extended to a large portion of the State of Delaware’s recently targeted growth areas in eastern Sussex County. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State of Delaware’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy related to enhancing the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broad number of prospective customers within eastern Sussex County is consistent with the Task Force recommendation. While the Company cannot predict the outcome of its application at this time, the Company anticipates a final decision from the Delaware PSC regarding its application in 2007.

On October 16, 2006, the Delaware division filed an application with the Delaware PSC requesting approval for the issuance of up to $40,000,000 of common stock and/or debt securities as contained in the shelf registration statement filed with the SEC in July 2006. The Delaware PSC granted approval of the issuance at its regularly scheduled meeting on October 31, 2006.

On November 1, 2006, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2006. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 21, 2006, subject to full evidentiary hearings and a final decision. The Delaware PSC granted final approval of the ER rate at its regulatory scheduled meeting on January 23, 2007.

On November 9, 2006, the Delaware division filed two applications with the Delaware PSC requesting approval for a Town of Millsboro Franchise Fee Rider and a Town of Georgetown Franchise Fee Rider. These Riders will allow the Delaware division to charge all respective natural gas customers within town limits the franchise fee paid by the Delaware division to the Towns of Millsboro and Georgetown as a condition to providing natural gas service. The Delaware PSC granted approval of both of the Riders at its regularly scheduled meeting on January 23, 2007.

On December 14, 2006, the Delaware division filed an application with the Delaware PSC requesting approval to change its base delivery service rates in order to recover a 1 mill increase in the assessment factor, which had been approved by the state legislature. The Delaware PSC granted approval of the application at its regularly scheduled meeting on December 19, 2006.

Maryland. On May 1, 2006, the Maryland division filed a base rate application with the Maryland Public Service Commission (“Maryland PSC”) requesting an overall increase in base rates of approximately $1,137,000 annually, based on a proposed overall rate of return of 9.7 percent and a return on equity of 11.5 percent. On September 26, 2006, the Maryland PSC approved a base rate increase of approximately $780,000 annually, based on an overall rate of return of 9.03 percent and a return on equity of 10.75 percent. This increase will result in an average increase in revenues of approximately 4.5 percent for the Maryland division’s firm residential, commercial and industrial customers. The PSC also approved the Company’s proposal to implement a revenue normalization mechanism for its residential heating and smaller commercial heating customers, reducing the Company’s risk due to weather and usage changes.
- Page 38 -
Management's Discussion and Analysis

On December 14, 2006, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2006. On December 15, 2006, the Hearing Examiner issued proposed findings approving the quarterly gas cost recovery rates as filed by the Maryland division, permitting complete recovery of its purchased gas costs for the period under review. No appeals or written exceptions to the proposed findings were made and a final order approving the quarterly gas cost recovery rates as filed was issued by the Maryland PSC on January 17, 2007.

Florida. On March 22, 2006, the Florida division filed a petition with the Florida Public Service Commission (“Florida PSC”) seeking approval of special contracts to provide Delivery Point Operator (“DPO”) services. Under the proposed contracts, the DPO services would be provided to an affiliate company, Peninsula Energy Services Company, Inc. The Florida PSC approved the petition on July 7, 2006, ordering that the special contracts be effective June 20, 2006.

On May 16, 2005, the Florida division filed a request with the Florida PSC for approval of a Special Contract with the Department of Management Services, an agency of the State of Florida, for service to the Washington Correction Institution (“WCI”). The Florida PSC approved the Company’s request on July 19, 2005, and service to the existing WCI facility began in February 2006. WCI is located in Washington County in the Florida panhandle and is the thirteenth county served by the Company’s Florida division.

On September 2, 2005, the Florida division filed a petition for a Declaratory Statement with the Florida PSC for a determination that Peninsula Pipeline Company, Inc. (“PPC”), a wholly owned subsidiary of the Company, qualifies as a natural gas transmission company under the Natural Gas Transmission Pipeline Intrastate Regulatory Act. The Florida PSC approved this Petition at its December 20, 2005 agenda conference, and a final order was issued on January 9, 2006. The determination that PPC qualifies as a natural gas transmission company provides opportunities for investment by PPC to provide natural gas transmission service to industrial customers in Florida by an intrastate pipeline.

On September 15, 2006, the Florida division filed a petition with the Florida PSC for approval of its Energy Conservation Cost Recovery Factors for the year 2007. Approved on November 30thregulation by the Florida PSC, the new factors went into effect on January 1, 2007.

On October 10, 2006, the Florida division filed a petition with the Florida PSC for authority to implement phase two of its experimental transitional transportation service (“TTS”) pilot program, and for approval of a new tariff to reflect the division’s transportation service environment. When approved, the implementation of phase two of the TTS program for residential and certain small commercial consumers will expand the number of pool managers from one to two, and increase the gas supply pricing options available to these consumers. A decision is expected from the Florida PSCPSC. At December 31, 2009, Chesapeake was involved in March 2007.

On November 29, 2006, the Florida division filed a petition with the Florida PSC for authority to modify its energy conservation programs. In this petition the Florida division is seeking approval to increase the cash allowances paid within the Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of the Residential Water Heater Retention Program to add natural gas heating systems, cooking and clothes drying appliances. A decision is expected from the Florida PSCrate filings and/or regulatory matters in March 2007.

Eastern Shore. During October 2002, Eastern Shore filed for recovery of gas supply realignment costs, which totaled $196,000 (including interest), associated with the implementation of FERC Order No. 636. At that time, the FERC deferred review of the filing pending settlement of a related matter concerning another transmission company. Upon resolution of the issue with the other transmission company, Eastern Shore resubmitted its filing to the FERC, requesting authorization to recover a total of $223,000 (including interest) of gas supply realignment costs. FERC approved Eastern Shore’s filing by letter order dated July 14, 2006.
- Page 39 -
Management's Discussion and Analysis

System Expansion 2006 - 2008. On January 20, 2006, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (the “2006 - 2008 Project”) with the FERC. The application requested authority to construct and operate approximately 55 miles of new pipeline facilities and two new metering and regulating station facilities to provide an additional 47,350 dekatherms per day (“dt/d”) of firm transportation service in accordance with the phased-in customer requests of 26,200 dt/d in 2006, 10,300 dt/d in 2007, and 10,850 dt/d in 2008, at a total estimated cost of approximately $33.6 million. The following table provides a breakdown for the additional amounts of firm capacity per day, the estimated capital investment required, and the estimated annual gross margin contribution for the new services that will become effective November 1st for each of the respective yearsjurisdictions in which it operates. Each of these rate filings or regulatory matters is fully described in Item 8 under the project:
 
Year
 
2006
2007
2008
Additional firm capacity per day26,20010,30010,850
Capital investment$17 million$8 million$8 million
Annualized gross margin contribution$3,670,000$1,484,000$1,595,000
A Scoping Meeting was held on March 29, 2006 at which the public and all other interested stakeholders were invited to attend to review the project. No oppositionheading “Notes to the project was received. On June 13, 2006, the FERC issued a Certificate to Eastern Shore authorizing it to constructConsolidated Financial Statements – Note P, Other Commitments and operate the 2006-2008 Project as proposed. Eastern Shore has completed and placed in service the authorized Phase I facilities. Phase II and Phase III facilities are expected to be constructed in 2007 and 2008, respectively.Contingencies.”

Bay Crossing Project. On May 31, 2006, Eastern Shore entered into Precedent Agreements with Delmarva Power & Light Company (“Delmarva”) and Chesapeake, through its Delaware and Maryland Divisions to provide additional firm transportation services upon completion of its latest proposed pipeline project.

Under the Bay Crossing Project, Eastern Shore has proposed to develop, construct and operate approximately 63 miles of new pipeline facilities that would transport natural gas from Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula where such facilities would interconnect with its existing facilities in Sussex County, Delaware.

Chesapeake and Delmarva are currently parties to existing firm natural gas transportation service agreements with Eastern Shore and each desires firm transportation services under the Bay Crossing Project, as evidenced by the May 31 Precedent Agreements. Pursuant to these Precedent Agreements, the parties have agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations that are necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, such firm transportation services under the Bay Crossing Project.

During the negotiations of the Precedent Agreements, Eastern Shore and each of the participating customers entered into Letter Agreements which provide that, in the event that the Bay Crossing Project is not certified and placed in service, the participating customers will each pay their proportionate share of certain pre-certification costs by means of a negotiated surcharge of up to $2 million, over a period of no less than 20 years.

In connection with the Bay Crossing Project, on June 27, 2006 Eastern Shore submitted a petition to the FERC for approval of the uncontested Settlement Agreement. The Settlement Agreement provides Eastern Shore and all customers utilizing Eastern Shore’s system with benefits, including but not limited to the following: (1) advancement of a necessary infrastructure project to meet the growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project development costs by the participating customers in the project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC granted approval of the uncontested Settlement Agreement. On September 6, 2006, Eastern Shore submitted to FERC proposed tariff sheets to implement the provisions of the above-referenced Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets effective September 7, 2006. Eastern Shore anticipates entering into a pre-filing process at the FERC during the first half of 2007 with the ultimate goal of obtaining FERC approval to construct the Proposed Project. Eastern Shore will also be required to obtain permits from other federal, state and local agencies prior to proceeding with construction. It is not until the Company obtains the appropriate approvals and permits that a majority of the total estimated cost of $93 million for the Bay Crossing Project is estimated to be spent. This estimated cost will depend upon the final size and route of the pipeline, as well as construction materials and labor costs.
- Page 40 -
Management's Discussion and Analysis

Rate Matters. On September 19, 2006, Eastern Shore submitted its Annual Charge Adjustment (“ACA”) compliance filing to reflect the most current ACA surcharge rate as established by the FERC. The compliance filing was accepted by the FERC and the revised ACA surcharge rate became effective on October 1, 2006.

On October 31, 2006 Eastern Shore filed a Section 4 base rate proceeding in compliance with Article IX of the Stipulation & Agreement approved in its prior base rate proceeding in Docket No.RP02-34-000. Eastern Shore’s filed rates, proposed to be effective November 1, 2006, reflect an annual increase of $5,589,000 over its current rates. The proposed rate increase reflects increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on new gas plant facilities that are expected to be placed into service before March 31, 2007. Eastern Shore proposed a return on equity of 14.875 percent utilizing a capital structure of 39 percent debt and 61percent equity.

On November 30, 2006 the FERC issued its Order Accepting and Suspending Tariff Sheets Subject to Refund and Establishing a Hearing. The FERC accepted and suspended the effectiveness of Eastern Shore’s rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order.

On December 5, 2006 the FERC’s Chief Judge issued an order stating this proceeding is subject to a Track Three procedural schedule. Track Three denotes an exceptionally complex case and provides for a total of 63 weeks within which a formal hearing will be conducted and an Initial Decision issued. The Chief Judge’s order also designated the Presiding Administrative Law Judge (“ALJ”).

On December 19, 2006 the ALJ issued an Order Establishing Procedural Schedule as agreed upon by the participants and the Judge at a pre-hearing conference held that same day. The procedural schedule specifies that an Initial Decision shall be issued on February 19, 2008. The ALJ also strongly encouraged the participants in this proceeding to pursue a negotiated settlement through the Commission’s settlement process, thus eliminating the need for a formal hearing.


(g) Environmental Matters
The Company continuesWe continue to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at threeseven environmental sites (see Note MItem 8 under the heading “Notes to the Consolidated Financial Statements)Statements – Note O, Environmental Commitments and Contingencies” for further detail on each site). The Company believesWe 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 the changechanges in interest rates. The Company’sOur long-term debt consists of fixed-rate senior notes, secured debt and convertible debentures (see Note HItem 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 Chesapeake’sour long-term debt is fixed-rate debt.debt and was not entered into for trading purposes. The carrying value of the Company’s long-term debt, including current maturities, was $78.7$134.1 million at December 31, 20062009, as compared to a fair value of $81.4$145.5 million, based mainly on current market prices ora discounted cash flows using currentflow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for similar issuesdebt instruments with similar terms and remaining maturities. The Company evaluatesaverage maturities with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently financerefinance existing short-term borrowing, based in part on the fluctuation in interest rates.
- Page 41 -
Management's Discussion and Analysis

The Company’sOur propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. The CompanyWe can store up to approximately four million gallons of propane (including leased storage and rail cars) of propane during the winter season to meet itsour 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, the Company haswe have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of itsour inventory. At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on our price-cap plan that we offer to customers. The Company considers this agreement to be an economic hedge and does not qualify for hedge accounting as described in SFAS 133. At the end of the period, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.

Page 56     Chesapeake Utilities Corporation 2009 Form 10-K

The
Our propane wholesale marketing operation is a party to natural gas liquids (“NGL”) forward contracts, primarily propane contracts, with various third parties.third-parties. These contracts require that the propane wholesale marketing operation purchase or sell NGLnatural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGLnatural gas liquids to the Companyus or the counterpartycounter-party or booking out“booking out” the transaction (bookingtransaction. Booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy).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.

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 operationbusiness is subject to commodity price risk on its open positions to the extent that market prices for NGLnatural gas liquids deviate from fixed contract settlement amounts.prices. Market risk associated with the trading of futures and forward contracts areis monitored daily for compliance with Chesapeake’sour 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 on a daily basis. Additionally,officials. In addition, the Risk Management Committee reviews periodic reports on marketmarkets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within the limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on the forward and futures contracts at December 31, 20062009 and 20052008 is shownpresented in the following charts.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.
At December 31, 2006
Quantity in gallons
Estimated Market Prices
Weighted Average Contract Prices
Forward Contracts
Sale
13,797,000
$0.9250 — $1.2100
$1.0107
Purchase
13,733,800
$0.9250 — $1.2200
$1.0098
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2007.
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.
At December 31, 2005
 
Quantity in gallons
 
Estimated Market Prices
 
Weighted Average Contract Prices
 
Forward Contracts
       
Sale  20,794,200 $1.0350 — $1.1013 $1.0718 
Purchase  20,202,000 $1.0100 — $1.0450 $1.0703 
           
Estimated market prices and weighted average contract prices are in dollars per gallon.
 
All contracts expired in 2006.
 
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 
The Company’sChesapeake Utilities Corporation 2009 Form 10-K     Page 57

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 in SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are not marked to market.accounted for on an accrual basis.
(i) Competition
- Page 42 -
Management's Discussion and Analysis

Competition
The Company’sOur 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. The Company’sOur natural gas distribution operations have several large volumelarge-volume industrial customers that have the capacityare 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. Lower levels inrequirements, and our interruptible sales occur when oil prices are lower relative to the price of natural gas.volumes may decline. Oil prices, as well as the prices of electricity and other fuels, are subject to fluctuationfluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company useswe use flexible pricing arrangements on both the supply and sales sidesides of this business to maximize sales volumes.compete with alternative fuel price fluctuations. As a result of the transmission business’operation’s conversion to open access and theChesapeake’s Florida natural gas distribution division’s restructuring of its services, theirthese businesses have shifted from providing competitivebundled transportation and sales service to providing transportationonly 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.

The Company’sOur natural gas distribution operations located in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, theChesapeake’s Florida operationnatural gas distribution division extended transportationsuch service to residential customers. With such transportation service available on the Company’sour distribution systems, the Company iswe are competing with third-party suppliers to sell gas to industrial customers. As it relatesWith respect to unbundled transportation services, the Company’sour competitors include the interstate transmission companycompanies, if the distribution customer iscustomers are located close enough to thea transmission company’s pipeline to make a connectionconnections economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass theour existing distribution operations in this manner. In certain situations, theour distribution operations may adjust services and rates for these customers to retain their business. The Company expectsWe expect to continue to expand the availability of unbundled transportation service to additional classes of distribution customers in the future. The CompanyWe have also established a natural gas sales and supplymarketing operation in Florida, Delaware and Maryland to compete forprovide such service to customers eligible for unbundled transportation services. The Company also provides sales service in Delaware.

The Company’sOur propane distribution operations compete with several other propane distributors in their service territories,respective geographic markets, primarily on the basis of service and price, emphasizing reliability of serviceresponsive and responsiveness. Competition isreliable service. Our competitors generally frominclude local outlets of national distribution companiesdistributors and local businesses, becauseindependent distributors, located in closewhose proximity to customers incurentails lower costs of providingto 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 servicedserved 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, whichand could adversely impactaffect the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.

Page 58     Chesapeake Utilities Corporation 2009 Form 10-K

(j) Inflation
Inflation affects the cost of supply, labor, products and services required for operation,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. FluctuationsIn the regulated natural gas and electric distribution operations, fluctuations in natural gas and electricity prices are passed on to customers through the gasfuel cost recovery mechanism in the Company’sour tariffs. To help cope with the effects of inflation on itsour capital investments and returns, the Company seekswe seek rate reliefincreases from regulatory commissions for our regulated operations while monitoringand closely monitor the returns of itsour unregulated business operations. To compensate for fluctuations in propane gas prices, Chesapeake adjusts itswe adjust propane selling prices to the extent allowed by the market.
- Page 43 -
Management's Discussion and Analysis

Cautionary Statement
Chesapeake has made statements in this report that are considered to be forward-looking statements. These statements are not matters of historical fact. Sometimes they contain words such as “believes,” “expects,” “intends,” “plans,” “will” or “may,” and other similar words of a predictive nature. These statements relate to matters such as customer growth, changes in revenues or gross margin, capital expenditures, environmental remediation costs, regulatory approvals, market risks associated with the Company’s propane wholesale marketing operation, competition, inflation and other matters. It is important to understand that these forward-looking statements are not guarantees but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. These factors include, among other things:

o  the temperature sensitivity of the natural gas and propane businesses;
o  the effect of spot, forward and futures market prices on the Company’s distribution, wholesale marketing and energy trading businesses;
o  amount and availability of natural gas and propane supplies and the access to interstate pipelines’ transportation and storage capacity;
o  the effects of natural gas and propane commodity price changes may affect the operating costs and competitive positions of our natural gas and propane distribution operations;
o  the effects of competition on the Company’s unregulated and regulated businesses;
o  the effect of changes in federal, state or local regulatory and tax requirements, including deregulation;
o  the effect of changes in technology on the Company’s advanced information services segment;
o  the effects of credit risk and credit requirements on the Company’s energy marketing subsidiaries;
o  the effect of accounting changes;
o  the effect of changes in benefit plan assumptions;
o  the effect of compliance with environmental regulations or the remediation of environmental damage;
o  the effects of general economic conditions and including interest rates on the Company and its customers;
o  the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues;
o  the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions; and
o  the Company’s ability to obtain necessary approvals and permits by regulatory agencies on a timely basis.



- Page 44 -

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 Rules 13a-15(f).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 generally accepted accounting principles.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 generally accepted accounting principles,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”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, 2006.2009.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 59
Management’s assessment of the effectiveness of Chesapeake’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.



- Page 45 -

Report of Independent Registered Public Accounting Firm
________


To the Board of Directors and
Stockholders
of Chesapeake Utilities Corporation

We have completed integrated auditsaudited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation’s consolidated financial statements and of its internal control over financial reportingCorporation as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements2009 and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2006 and 2005,2008, and the resultsrelated consolidated statements of their operationsincome, stockholders’ equity and their cash flows for each of the three years in the three-year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related2009. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits of these statements 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,statements. An audit also includes assessing the accounting principles used and significant estimates made by management, andas well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note K toIn our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans, effective December 31, 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reportingposition of Chesapeake Utilities Corporation as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by2009 and 2008, and the Committeeresults of Sponsoring Organizationstheir operations and their cash flows for each of the Treadway Commission (COSO), is fairly stated,years in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofthree-year period ended December 31, 2006, based on criteria established2009 in Internal Control - Integrated Framework issued byconformity with accounting principles generally accepted in the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessmentUnited States of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. America.
We conducted our audit of internal control over financial reportingalso have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective, Chesapeake Utilities Corporation’s internal control over financial reporting was maintainedas of December 31, 2009, based on criteria established in all material respects. An auditInternal Control—Integrated Framework issued by the Committee of internal control over financial reporting includes obtainingSponsoring Organizations of the Treadway Commission (COSO), and our report dated March 8, 2010 expressed an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.unqualified opinion.
 
/s/ ParenteBeard LLC
ParenteBeard LLC
Malvern, Pennsylvania
March 8, 2010
Page 60     Chesapeake Utilities Corporation 2009 Form 10-K

Consolidated Statements of Income
- Page 46 -
             
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 
          

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 generally accepted accounting principles. 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 generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (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.

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.



/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Boston, MA
March 13, 2007

- Page 47 -



Consolidated Statements of Income
 
        
For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Operating Revenues
 
$
231,200,591
 $229,629,736 $177,955,441 
Operating Expenses
          
Cost of sales, excluding costs below  
155,810,622
  153,514,739  109,626,377 
Operations  
37,053,223
  40,181,648  35,146,595 
Maintenance  
2,103,562
  1,818,981  1,518,774 
Depreciation and amortization  
8,243,715
  7,568,209  7,257,538 
Other taxes  
5,058,158
  5,015,660  4,436,411 
Total operating expenses  
208,269,280
  208,099,237  157,985,695 
Operating Income
  
22,931,311
  21,530,499  19,969,746 
Other income net of other expenses  
189,112
  382,626  549,156 
Interest charges  
5,777,336
  5,133,495  5,268,145 
Income Before Income Taxes
  
17,343,087
  16,779,630  15,250,757 
Income taxes  
6,836,562
  6,312,016  5,701,090 
Net Income from Continuing Operations
  
10,506,525
  10,467,614  9,549,667 
Loss from discontinued operations, net of tax benefit of $0, $0 and $59,751  
-
  -  (120,900)
Net Income
 
$
10,506,525
 $10,467,614 $9,428,767 
           
Earnings Per Share of Common Stock:
 
Basic
          
From continuing operations 
$
1.74
 $1.79 $1.66 
From discontinued operations  
-
  -  (0.02)
Net Income
 
$
1.74
 $1.79 $1.64 
           
Diluted
          
From continuing operations 
$
1.72
 $1.77 $1.64 
From discontinued operations  
-
  -  (0.02)
Net Income
 
$
1.72
 $1.77 $1.62 


The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 61

Consolidated Statements of Cash Flows
- Page 48 -
             
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)


Consolidated Statements of Cash Flows
 
        
For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Operating Activities
       
Net Income 
$
10,506,525
 $10,467,614 $9,428,767 
Adjustments to reconcile net income to net operating cash:          
Depreciation and amortization   
8,243,715
  7,568,209  7,257,538 
Depreciation and accretion included in other costs   
3,102,066
  2,705,620  2,611,779 
Deferred income taxes, net   
(408,533
)
 1,510,777  4,559,207 
Unrealized gain (loss) on commodity contracts   
37,110
  (227,193) 353,183 
Unrealized loss on investments   
(151,952
)
 (56,650) (43,256)
Employee benefits and compensation   
382,608
  1,621,607  1,536,586 
Other, net   
(18,596
)
 (62,692) 67,079 
Changes in assets and liabilities:          
Sale (purchase) of investments   
(177,990
)
 (1,242,563) 43,354 
Accounts receivable and accrued revenue   
9,705,860
  (16,831,751) (11,723,505)
Propane inventory, storage gas and other inventory   
354,764
  (5,704,040) (1,741,941)
Regulatory assets   
2,498,954
  (1,719,184) 428,516 
Prepaid expenses and other current assets   
(271,438
)
 36,704  (221,137)
Other deferred charges   
(231,822
)
 (102,561) (168,898)
Long-term receivables   
137,101
  247,600  428,964 
Accounts payable and other accrued liabilities   
(11,434,370
)
 15,569,924  9,731,360 
Income taxes receivable (payable)   
1,800,913
  (2,006,762) (229,237)
Accrued interest   
273,672
  (42,376) (51,272)
Customer deposits and refunds   
2,361,265
  462,781  665,549 
Accrued compensation   
(542,512
)
 875,342  (794,194)
Regulatory liabilities   
2,824,068
  144,501  (191,266)
Other liabilities   
1,125,590
  385,034  55,977 
Net cash provided by operating activities  
30,116,998
  13,599,941  22,003,153 
           
Investing Activities
          
Property, plant and equipment expenditures  
(48,845,828
)
 (33,319,613) (16,435,938)
Sale of investments  
-
  -  135,170 
Sale of discontinued operations  
-
  -  415,707 
Environmental recoveries (expenditures)  
(15,549
)
 240,336  369,719 
Net cash used by investing activities  
(48,861,377
)
 (33,079,277) (15,515,342)
           
Financing Activities
          
Common stock dividends  
(5,982,531
)
 (5,789,180) (5,560,535)
Issuance of stock for Dividend Reinvestment Plan  
321,865
  458,757  200,551 
Stock issuance  
19,698,509
  -    
Cash settlement of warrants  
(434,782
)
 -  - 
Change in cash overdrafts due to outstanding checks  
49,047
  874,083  (143,720)
Net borrowing (repayment) under line of credit agreements  
(7,977,347
)
 29,606,400  1,184,742 
Proceeds from issuance of long-term debt  
20,000,000
  -  - 
Repayment of long-term debt  
(4,929,674
)
 (4,794,827) (3,665,589)
Net cash provided (used) by financing activities  
20,745,087
  20,355,233  (7,984,551)
           
Net Increase (Decrease) in Cash and Cash Equivalents
  
2,000,708
  875,897  (1,496,740)
Cash and Cash Equivalents — Beginning of Period
  
2,487,658
  1,611,761  3,108,501 
Cash and Cash Equivalents — End of Period
 
$
4,488,366
 $2,487,658 $1,611,761 
           
Supplemental Disclosures of Non-Cash Investing Activities:
          
Capital property and equipment acquired on account,          
but not paid as of December 31 
$
1,490,890
 $1,367,348 $1,678,724 
           
Supplemental Disclosure of Cash Flow information
          
Cash paid for interest 
$
5,334,477
 $5,052,013 $5,280,299 
Cash paid for income taxes 
$
6,285,272
 $6,342,476 $1,977,223 
The accompanying notes are an integral part of the financial statements.
Page 62     Chesapeake Utilities Corporation 2009 Form 10-K

Consolidated Balance Sheets
- Page 49 -
         
  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 
       


Consolidated Balance Sheets
Assets
At December 31,
2006
2005
Property, Plant and Equipment
Natural gas distribution and transmission
$
269,012,516
$220,685,461
Propane
44,791,552
41,563,810
Advanced information services
1,054,368
1,221,177
Other plant
9,147,500
9,275,729
Total property, plant and equipment
324,005,936
272,746,177
Less: Accumulated depreciation and amortization
(85,010,472
)
(78,840,413)
Plus: Construction work in progress
1,829,948
7,598,531
Net property, plant and equipment
240,825,412
201,504,295
Investments
2,015,577
1,685,635
Current Assets
Cash and cash equivalents
4,488,366
2,487,658
Accounts receivable (less allowance for uncollectible accounts of $661,597 and $861,378, respectively)
44,969,182
54,284,011
Accrued revenue
4,325,351
4,716,383
Propane inventory, at average cost
7,187,035
6,332,956
Other inventory, at average cost
1,564,937
1,538,936
Regulatory assets
1,275,653
4,434,828
Storage gas prepayments
7,393,335
8,628,179
Income taxes receivable
1,078,882
2,725,840
Deferred income taxes
1,365,316
-
Prepaid expenses
2,280,900
2,021,164
Other current assets
1,553,284
1,596,797
Total current assets
77,482,241
88,766,752
Deferred Charges and Other Assets
Goodwill
674,451
674,451
Other intangible assets, net
191,878
205,683
Long-term receivables
824,333
961,434
Other regulatory assets
1,765,088
1,178,232
Other deferred charges
1,215,004
1,003,393
Total deferred charges and other assets
4,670,754
4,023,193
Total Assets
$
324,993,984
$295,979,875

The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 63

Consolidated Balance Sheets
- Page 50 -
         
  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 
       


Consolidated Balance Sheets
 
      
Capitalization and Liabilities
 
At December 31,
 
2006
 
2005
 
Capitalization
     
Stockholders' equity     
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares) (1)
 
$
3,254,998
 $2,863,212 
Additional paid-in capital  
61,960,220
  39,619,849 
Retained earnings  
46,270,884
  42,854,894 
Accumulated other comprehensive income  
(334,550
)
 (578,151)
Deferred compensation obligation  
1,118,509
  794,535 
Treasury stock  
(1,118,509
)
 (797,156)
Total stockholders' equity  
111,151,552
  84,757,183 
Long-term debt, net of current maturities  
71,050,000
  58,990,363 
Total capitalization  
182,201,552
  143,747,546 
        
Current Liabilities
       
Current portion of long-term debt  
7,656,364
  4,929,091 
Short-term borrowing  
27,553,941
  35,482,241 
Accounts payable  
33,870,552
  45,645,228 
Customer deposits and refunds  
7,502,265
  5,140,999 
Accrued interest  
832,392
  558,719 
Dividends payable  
1,939,482
  1,676,398 
Deferred income taxes  
-
  1,150,828 
Accrued compensation  
2,901,053
  3,793,244 
Regulatory liabilities  
4,199,147
  550,546 
Other accrued liabilities  
4,005,795
  3,560,055 
Total current liabilities  
90,460,991
  102,487,349 
        
Deferred Credits and Other Liabilities
       
Deferred income taxes  
26,517,098
  24,248,624 
Deferred investment tax credits  
328,277
  367,085 
Other regulatory liabilities  
1,236,254
  2,008,779 
Environmental liabilities  
211,581
  352,504 
Accrued pension costs  
1,608,311
  3,099,882 
Accrued asset removal cost  
18,410,992
  16,727,268 
Other liabilities  
4,018,928
  2,940,838 
Total deferred credits and other liabilities  
52,331,441
  49,744,980 
        
Other Commitments and Contingencies (Note N)
       
        
        
Total Capitalization and Liabilities
 
$
324,993,984
 $295,979,875 
        
(1) Shares issued were 6,688,084 and 5,883,099 for 2006 and 2005, respectively.
 
Shares outstanding were 6,688,084 and 5,883,002 for 2006 and 2005, respectively. 

The accompanying notes are an integral part of the financial statements.
Page 64     Chesapeake Utilities Corporation 2009 Form 10-K

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.
- Page 51 -


Statements of Stockholders' Equity
 
        
For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Common Stock
       
Balance — beginning of year 
$
2,863,212
 $2,812,538 $2,754,748 
Dividend Reinvestment Plan  
18,685
  20,038  20,125 
Retirement Savings Plan  
14,457
  10,255  19,058 
Conversion of debentures  
8,117
  11,004  9,060 
Performance shares and options exercised (1)
  
14,536
  9,377  9,547 
Stock issuance  
335,991
  -  - 
Balance — end of year  
3,254,998
  2,863,212  2,812,538 
           
Additional Paid-in Capital
          
Balance — beginning of year  
39,619,849
  36,854,717  34,176,361 
Dividend Reinvestment Plan  
1,148,100
  1,224,874  996,715 
Retirement Savings Plan  
900,354
  682,829  946,319 
Conversion of debentures  
275,300
  373,259  307,940 
Performance shares and options exercised (1)
  
887,426
  484,170  427,382 
Stock issuance  
19,362,518
  -  - 
Exercise warrants, net of tax  
(233,327
)
 -  - 
Balance — end of year  
61,960,220
  39,619,849  36,854,717 
           
Retained Earnings
          
Balance — beginning of year  
42,854,894
  39,015,087  36,008,246 
Net income  
10,506,525
  10,467,614  9,428,767 
Cash dividends (2)
  
(7,090,535
)
 (6,627,807) (6,403,450)
Loss on issuance of treasury stock  
-
  -  (18,476)
Balance — end of year  
46,270,884
  42,854,894  39,015,087 
           
Accumulated Other Comprehensive Income
          
Balance — beginning of year  
(578,151
)
 (527,246) - 
Minimum pension liability adjustment, net of tax  
74,036
  (50,905) (527,246)
Gain on funded status of Employee Benefit Plans, net of tax  
169,565
  -  - 
Balance — end of year  
(334,550
)
 (578,151) (527,246)
           
Deferred Compensation Obligation
          
Balance — beginning of year  
794,535
  816,044  913,689 
New deferrals  
323,974
  130,426  296,790 
Payout of deferred compensation  
-
  (151,935) (394,435)
Balance — end of year  
1,118,509
  794,535  816,044 
           
Treasury Stock
          
Balance — beginning of year  
(797,156
)
 (1,008,696) (913,689)
New deferrals related to compensation obligation  
(323,974
)
 (130,426) (296,790)
Purchase of treasury stock  
(51,572
)
 (182,292) (344,753)
Sale and distribution of treasury stock  
54,193
  524,258  546,536 
Balance — end of year  
(1,118,509
)
 (797,156) (1,008,696)
           
           
Total Stockholders’ Equity
 
$
111,151,552
 $84,757,183 $77,962,444 
           
(1) Includes amounts for shares issued for Directors' compensation.
 
(2) Cash dividends declared per share for 2006, 2005 and 2004 were $1.16, $1.14 and $1.12, respectively.
 

Statements of Comprehensive Income
 
        
For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Net income 
$
10,506,525
 $10,467,614 $9,428,767 
Pension liability adjustment, net of tax of $48,889, $33,615 and $347,726, respectively  
74,036
  (50,905) (527,246)
Comprehensive Income
 
$
10,580,561
 $10,416,709 $8,901,521 
The accompanying notes are an integral part of the financial statements.
-Chesapeake Utilities Corporation 2009 Form 10-K     Page 52 -65


Consolidated Statements of Income Taxes
 
        
For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Current Income Tax Expense
       
Federal 
$
5,994,296
 $3,687,800 $1,221,155 
State  
1,424,485
  789,233  618,916 
Investment tax credit adjustments, net  
(54,816
)
 (54,816) (54,816)
Total current income tax expense  
7,363,965
  4,422,217  1,785,255 
           
Deferred Income Tax Expense (1)
          
Property, plant and equipment  
1,697,024
  1,380,628  4,230,650 
Deferred gas costs  
(2,085,066
)
 1,064,310  283,547 
Pensions and other employee benefits  
(97,436
)
 (340,987) (49,620)
Environmental expenditures  
(5,580
)
 (98,229) (150,864)
Other  
(36,345
)
 (115,923) (397,878)
Total deferred income tax expense  
(527,403
)
 1,889,799  3,915,835 
Total Income Tax Expense
 
$
6,836,562
 $6,312,016 $5,701,090 
           
Reconciliation of Effective Income Tax Rates
          
Federal income tax expense (2)
 
$
6,070,080
 $5,872,871 $5,185,257 
State income taxes, net of federal benefit  
804,988
  708,192  736,176 
Other  
(38,506
)
 (269,047) (220,343)
Total Income Tax Expense
 
$
6,836,562
 $6,312,016 $5,701,090 
Effective income tax rate
  
39.4
%
 37.6% 37.4%
           
At December 31,
  
2006
  
2005
    
Deferred Income Taxes
          
Deferred income tax liabilities:
          
Property, plant and equipment  
$
27,997,744
 $26,795,452    
Environmental costs   
204,149
  -    
Deferred gas costs   
-
  1,664,252    
Other   
870,424
  612,943    
Total deferred income tax liabilities  
29,072,317
  29,072,647    
           
Deferred income tax assets:
          
Pension and other employee benefits   
2,225,944
  2,289,370    
Self insurance   
468,922
  575,303    
Environmental costs   
-
  181,734    
Deferred gas costs   
528,814
  -    
Other   
696,855
  626,788    
Total deferred income tax assets  
3,920,535
  3,673,195    
Deferred Income Taxes Per Consolidated Balance Sheet 
$
25,151,782
 $25,399,452    
           
(1) Includes ($54,000), $146,000 and $386,000 of deferred state income taxes for the years 2006, 2005 and 2004, respectively.
 
(2) Federal income taxes were recorded at 35% for the years 2006 and 2005. They were recorded at 34% in 2004.
 


The accompanying notes are an integral part of the financial statements.
- Page 53 -
Notes to the Consolidated Financial Statements

A. Summary of Accounting Policies
Nature of Business
Chesapeake, Utilities Corporation (“Chesapeake” or “the Company”)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 distribution to approximately 59,100118,000 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. The Company’sOur regulated energy business also provides natural gas transmission subsidiary operates an intrastateservice primarily through a 384-mile interstate pipeline from various points in Pennsylvania and northern Delaware to the Company’sour natural gas distribution affiliates in Delaware and Maryland distribution divisions, as well as to other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s
Our unregulated energy business includes natural gas marketing, propane distribution and propane wholesale marketing segmentoperations. 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 approximately 33,30049,000 customers in central and southern Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania central Florida and the Eastern Shore of Virginia, andFlorida. 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. The
We also engage in non-energy businesses, primarily through our advanced information services segmentsubsidiary, which provides domestic and international clients with information technology relatedinformation-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 ownedwholly-owned subsidiaries. The Company doesAs 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
TheOur natural gas and electric distribution divisions of the Company locatedoperations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service CommissionsPSC with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore Natural Gas CompanyESNG is an open access pipeline and is subject to regulationregulated by the Federal Energy Regulatory Commission (“FERC”).FERC. Our financial statements are prepared in accordance with generally accepted accounting principles,GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various regulatory commissions. The propane, advanced information servicesunregulated energy and other business segmentsunregulated businesses are not subject to regulation with respect to rates, service or maintenance of accounting records.

Property, Plant, Equipment and Depreciation
UtilityProperty, plant and non-utility propertyequipment is stated at original cost.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 non-utility property of unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of utility 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 anvarious annual rate for each segment. The three-year average rates, were 3 percentas approved by the regulators.
Page 66     Chesapeake Utilities Corporation 2009 Form 10-K

             
  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 distributiontransmission 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 transmission, 5 percentprovides $264,000 in annual revenues for propane, 11 percenta term of 20 years. Accumulated depreciation for advanced information services and 7 percent for general plant.these assets total $74,000 at December 31, 2009.
- Page 54 -
Notes to the Consolidated Financial Statements

        
At December 31,
 
2006
 
2005
 
Useful Life (1)
 
Plant in service       
Mains $151,890,304 $113,111,408  24-37 years 
Services — utility  32,334,145  29,010,008  14-28 years 
Compressor station equipment  24,921,976  23,853,871  28 years 
Liquefied petroleum gas equipment  24,627,398  22,162,867  30-39 years 
Meters and meter installations  16,093,737  15,165,212  Propane 15-33 years, Natural gas 17-49 years 
Measuring and regulating station equipment  13,272,201  12,219,964  17-37 years 
Office furniture and equipment  10,114,101  9,572,926  Non-regulated 3-10 years, Regulated 3-20 years 
Transportation equipment  10,686,259  9,822,272  2-11 years 
Structures and improvements  9,538,345  9,161,696  
5-44 years(2)
 
Land and land rights  7,386,268  5,646,852  Not depreciable, except certain regulated assets 
Propane bulk plants and tanks  5,301,457  6,097,036  15 - 40 years 
Various  17,839,745  16,922,065  Various 
Total plant in service  324,005,936  272,746,177    
Plus construction work in progress  1,829,948  7,598,531    
Less accumulated depreciation  (85,010,472) (78,840,413)   
Net property, plant and equipment $240,825,412 $201,504,295    
           
(1) Certain immaterial account balances may fall outside this range.
 
           
The regulated operations compute depreciation in accordance with rates approved by either the state Public Service Commission 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 and propane operations, improvements to those facilities and leasehold improvements.
 

Cash and Cash Equivalents
The Company’sOur policy is to invest cash in excess of operating requirements in overnight income producingincome-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.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 67

Inventories
Inventories
The Company usesWe use the average cost method to value propane, and materials and supplies, and other merchandise inventory. If the market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.

Regulatory Assets, Liabilities and Expenditures
The Company accountsWe account for itsour regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.ASC Topic 980, “Regulated Operations.” This standardTopic 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, thea regulated utilitycompany defers the associated costs as regulatory assets (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 (regulatory liabilities).

as regulatory liabilities.
At December 31, 20062009 and 2005,2008, 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 
       
- Page 55 -
Notes to the Consolidated Financial Statements

At December 31,
 
2006
 
2005
 
Regulatory Assets
     
Current
     
Underrecovered purchased gas costs 
$
1,076,921
 $4,016,522 
Conservation cost recovery  
51,408
  303,930 
Swing transportation imbalances  
-
  454 
PSC Assessment  
22,290
  - 
Flex rate asset  
81,926
  113,922 
Other  
43,108
  - 
Total current  
1,275,653
  4,434,828 
        
Non-Current
       
Income tax related amounts due from customers  
1,300,544
  711,961 
Deferred regulatory and other expenses  
188,686
  89,258 
Deferred gas supply  
15,201
  15,201 
Deferred post retirement benefits  
138,949
  166,739 
Environmental regulatory assets and expenditures  
121,708
  195,073 
Total non-current  
1,765,088
  1,178,232 
        
Total Regulatory Assets 
$
3,040,741
 $5,613,060 
        
Regulatory Liabilities
       
Current
       
Self insurance — current 
$
568,897
 $44,221 
Overrecovered purchased gas costs  
2,351,553
  - 
Shared interruptible margins  
100,355
  3,039 
Operational flow order penalties  
7,831
  7,831 
Swing transportation imbalances  
1,170,511
  495,455 
Total current  
4,199,147
  550,546 
        
Non-Current
       
Self insurance — long-term  
600,787
  1,383,247 
Income tax related amounts due to customers  
285,819
  327,893 
Environmental overcollections  
349,648
  297,639 
Total non-current  
1,236,254
  2,008,779 
        
Accrued asset removal cost  
18,410,992
  16,727,268 
        
Total Regulatory Liabilities 
$
23,846,393
 $19,286,593 
(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 are $133,000 ofis $1.5 million related to deferred merger-related costs at December 31, 2009 for which is accruing interest. Ofwe intend to seek recovery in future rates in Florida. Also included in the remaining regulatory assets $1.4 million will be collectedlisted above are $838,000 and $711,000 at December 31, 2009 and 2008, respectively, in approximately oneother costs primarily related to two years, $310,000 will be collected within approximately 3 to 10 years, and $1.4 millionincome 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 but once approved are expected to be collected within 12 months.of the deferred costs is allowed in rates and we do not earn a return on those regulatory assets.

Page 68     Chesapeake Utilities Corporation 2009 Form 10-K

As required by SFAS No. 71, the Company monitors its
We monitor our regulatory and competitive environment to determine whether the recovery of itsour regulatory assets continues to be probable. If the Companywe were to determine that recovery of these assets is no longer probable, itwe would write off the assets against earnings. The Company believesWe believe that SFAS No. 71 continuesprovisions of ASC Topic 980 “Regulated Operations” continue to apply to itsour regulated operations, and that the recovery of itsour regulatory assets is probable.

Goodwill and Other Intangible Assets
The Company accounts for its goodwill and other intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS No. 142, goodwillGoodwill is not amortized but it 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 FH, “Goodwill and Other Intangible Assets” for additional discussions of this area.
- Page 56 -
NotesAssets,” 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. Deferred post-employment benefits
Pension and Other Postretirement Plans
Pension and other postretirement plan costs and liabilities are adjusted baseddetermined 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 age,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 projectedCitigroup 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 benefit receivedpension 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 life expectancy.based upon our annual reviews of participant census information as of the measurement date.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 69

Income Taxes and Investment Tax Credit Adjustments
The Company files a consolidated federal income tax return. Income tax expense allocated to the Company’s subsidiaries is based upon their respective taxable incomes and tax credits.

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 current effective incomethe enacted tax rates.rates in effect in the years in which the differences are expected to reverse. The portions of the Company’sour deferred tax liabilities applicable to utilityregulated 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, Inc. (“Xeron”), the Company’sour 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, the Company’sour 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. The resulting unrealized gains and losses are recorded as assets or liabilities, respectively. There were unrealized losses of $1.6 million in 2009 and unrealized gains of $8,500 and $46,000 at December 31, 2006 and 2005, respectively.$1.4 million in 2008. Trading liabilities are recorded in other accruedmark-to-market energy liabilities. Trading assets are recorded in prepaid expenses and other currentmark-to-market energy assets.

The Company’sOur natural gas, electric and propane distribution operations have entered into agreements with natural gas and propane 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 in SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are accounted for on an accrual basis.

The propane distribution operation has enteredmay enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. At December 31, 2006, the propane distribution operation hadDuring 2008, we entered into a swap agreement to protect the Company from the impact ofthat propane price increases would have on the Pro-Cap (propane price cap) Plan that the Delmarva propane distribution operation offers to our price-cap plan thatcustomers. Propane prices declined significantly in late 2008 and we offer to customers. The Company considers thisrecorded a mark-to-market loss of approximately $939,000 on the swap agreement to be an economic hedge and does not qualify for hedge accounting as described in SFAS 133. At2008, which increased the end of the period, the market pricecost of propane dropped below the unit price withinsales. In January 2009, we terminated the swap agreement. AsDuring 2009, we purchased a resultput 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 price drop,put agreement and $(105,000) in fair value of the Company marked theswap agreement, to market, which resulted in an unrealized loss of $84,000.respectively.
Page 70     Chesapeake Utilities Corporation 2009 Form 10-K

- Page 57 -
Notes to the Consolidated Financial Statements

Earnings Per Share
Basic earnings per share are computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed by dividing income available for common 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 from continuing operations 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 
          

For the Periods Ended December 31,
 
2006
 
2005
 
2004
 
Calculation of Basic Earnings Per Share:
       
Net Income 
$
10,506,525
 $10,467,614 $9,549,667 
Weighted average shares outstanding  
6,032,462
  5,836,463  5,735,405 
Basic Earnings Per Share
 
$
1.74
 $1.79 $1.66 
           
Calculation of Diluted Earnings Per Share:
          
Reconciliation of Numerator:
          
Net Income — Basic 
$
10,506,525
 $10,467,614 $9,549,667 
Effect of 8.25% Convertible debentures  
105,024
  123,559  139,097 
Adjusted numerator — Diluted 
$
10,611,549
 $10,591,173 $9,688,764 
           
Reconciliation of Denominator:
          
Weighted shares outstanding — Basic  
6,032,462
  5,836,463  5,735,405 
Effect of dilutive securities          
Stock options  
-
  -  1,784 
Warrants  
-
  11,711  7,900 
8.25% Convertible debentures  
122,669
  144,378  162,466 
Adjusted denominator — Diluted  
6,155,131
  5,992,552  5,907,555 
           
Diluted Earnings Per Share
 
$
1.72
 $1.77 $1.64 


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 theour natural gas and electric distribution operations of the Company are based on rates approved by the various public service commissions.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;commissions. The PSCs, however, the regulatory authorities have grantedauthorized our regulated natural gas distribution operations the ability to negotiate rates, based on approved methodologies, with customers that have competitive alternatives using approved methodologies. In addition, the natural gas transmission operation canalternatives. The FERC has also authorized ESNG to negotiate rates above or below the FERC-approved tariffmaximum rates, which customers can elect as a recourse to negotiated rates.

Chesapeake’s Maryland and DelawareFor regulated deliveries of natural gas distribution operations eachand 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 a gas cost recovery mechanism that provides forbeen delivered, but not yet billed, at the adjustmentend of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.

The Company charges flexible ratesan accounting period to the extent that they do not coincide. In connection with this accrual, we must estimate the amount of natural gas distribution’s industrial interruptibleand 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 to compete with alternative types of fuel. Based on pricing, thesemeters, such as community gas system customers, can chooseand natural gas or alternative types of supply. Neithermarketing customers, whose billing cycles do not coincide with the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

accounting periods.
The propane wholesale marketing operation records trading activity net on the Company’s income statement,for open contracts on a net mark-to-market basis for open contracts. Thein our consolidated statement of income. For propane distribution customers without meters and advanced information services and other segmentscustomers, we record revenue in the period the products are delivered and/or services are rendered.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 71

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
TheOur financial statements are prepared in conformity with generally accepted accounting principles thatGAAP, which require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes MNote O, “Environmental Commitments and NContingencies,” 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.
- Page 58 -
Notes to the Consolidated Financial Statements

The Company recordsWe record certain assets and liabilities in accordance with SFAS No. 71.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 the Companywe were required to terminate the application of SFAS No. 71 for itsthese provisions to our regulated operations, all such deferred amounts would be recognized in the income statement at that time. This couldwould result in a charge to earnings, net of applicable income taxes, which could be material.

Page 72     Chesapeake Utilities Corporation 2009 Form 10-K

Acquisition Accounting
FASBThe 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 Other Authoritative Pronouncementsmerger-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.
InSubsequent 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 2004,31, 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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 73

Codification
Beginning in the third quarter of 2009, we adopted the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”). The Company was required to adopt SFAS No. 123(R)ASC, which is now the single source of authoritative accounting principles in the first quarter of 2006. The Company is required to measure the cost of all employee share-based payments to employees, including grants of employee stock options, using a fair-value-based method. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition.United States. The adoption of SFAS No. 123(R)the ASC did not have a material impact on the financial statements

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”. This statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement was effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company was required to adopt SFAS No. 154 in the first quarter of 2006. The implementation of this statement did not have a material impact on Chesapeake’s financial statements.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”. This statement improves financial reporting by requiring an employer to recognize the over-funded or under-funded status of a defined benefit postretirement plan as an asset or liability in its statement ofour financial position and results of operations. As a result of this adoption, we updated all references to recognize changesaccounting and reporting standards included in that funded statusthis 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 yearCompany
In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in whichaccordance with International Financial Reporting Standards (“IFRS”), a comprehensive series of accounting standards published by the changes occur through comprehensive income. The Company isInternational Accounting Standards Board (“IASB”). Under the proposed roadmap, we may be required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. The Company adopted SFAS No. 158 as of December 31, 2006. Based on the fair value of plan assets and their related funded status at December 31, 2006, the adoption of SFAS 158 resulted in an increase in total assets by approximately $282,000, an increase in total liabilities by approximately $112,000 and an increase to total shareholders equity by approximately $170,000. Please refer to Note K “Employee Benefit Plans,” for details of each of the Company’s benefit plans.

In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes”. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’sprepare financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. This interpretation prescribesIFRS as early as 2014. The SEC will make a recognition threshold and measurement attribute fordetermination in 2011 regarding the financial statementmandatory 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 tax position taken or expectedreporting entity to be takendisclose 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 tax return. This interpretation also provides guidance on derecognition, classification, interestreporting entity should present separately information about purchases, sales, issuances, and penalties, accountingsettlements. 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 interim periods, disclosure, and transition. This interpretation isthe roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2006. Chesapeake is required to adopt FIN No. 48 in the first quarter of 2007. The Company is currently evaluating the impact that this interpretation will have on our financial statements.
- Page 59 -
Notes to the Consolidated Financial Statements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”. This statement defines fair value, establishes a framework2010, and for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Chesapeake willWe 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 requiredexpensed 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 adoptthe Consolidated Financial Statements.
In March 2008, the FASB issued SFAS No. 157 in161, “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 first quarterTopic, “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 2008. The Company hasthis standard did not yet evaluated thehave an impact that this statement will have on our consolidated financial statements.position and results of operations. These disclosures are discussed in Note E, “Derivative Instruments,” to the Consolidated Financial Statements.

Page 74     Chesapeake Utilities Corporation 2009 Form 10-K

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 2006,2008, the SECFASB issued Staff Accounting Bulletin No. 108, which expresses the SEC’s views regarding the process of quantifying financial statement misstatements. The applicationFSP 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 guidanceTopic, “Earnings Per Share,” clarifies that holders of outstanding unvested share-based payment awards containing rights to nonforfeitable dividends participate with common shareholders in this bulletin is applicable at December 31, 2006. The implementationundistributed earnings. Awards of this bulletinnature 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 anyan impact on our consolidated financial position and results of operations.
In December 2008, the Company’sFASB 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 statements.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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 75

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.
ReclassificationB. 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 Prior Years’ AmountsChesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes.
Certain prior years’ amountsThe 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.
Page 76     Chesapeake Utilities Corporation 2009 Form 10-K

     
(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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 77

         
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 reclassified to conform tohad the current year’s presentation.acquisitions actually occurred on January 1, 2009, and January 1, 2008, respectively.

B. Business Dispositions and Discontinued Operations
OnSight
During 2003, Chesapeake2007, we decided to exit the waterclose our distributed energy services business and sold six ofsubsidiary, OnSight, which had experienced operating losses since its seven operations. The remaining operation was soldinception in October 2004. At December 31, 2006, all property and assets of the water subsidiary have been sold. The results of operations for all water service businessesOnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. Operating revenues forThe discontinued operations was $1.1 million and operating losses for discontinued operations was $94,000 for 2004. Aexperienced a net loss of $52,000, net of tax, was recorded$20,000 for 2004 on the sale of the water operations. The Company2007. We did not have any discontinued operations in 20062008 and 2005.



- Page 60 -
2009.
Notes to the Consolidated Financial Statements

C. Segment Information
The following table presents information about the Company’s reportable segments. The table excludes discontinued operations.


For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Operating Revenues, Unaffiliated Customers
       
Natural gas distribution, transmission and marketing 
$
170,114,514
 $166,388,562 $124,073,939 
Propane  
48,575,976
  48,975,349  41,499,687 
Advanced information services  
12,509,077
  14,121,441  12,381,815 
Other  
1,024
  144,384  - 
Total operating revenues, unaffiliated customers 
$
231,200,591
 $229,629,736 $177,955,441 
           
Intersegment Revenues (1)
          
Natural gas distribution, transmission and marketing 
$
259,969
 $193,404 $172,427 
Propane  
-
  668  - 
Advanced information services  
58,532
  18,123  45,266 
Other  
618,493
  618,492  647,378 
Total intersegment revenues 
$
936,994
 $830,687 $865,071 
           
Operating Income
          
Natural gas distribution, transmission and marketing 
$
19,733,487
 $17,235,810 $17,091,360 
Propane  
2,534,035
  3,209,388  2,363,884 
Advanced information services  
767,160
  1,196,544  387,193 
Other and eliminations  
(103,371
)
 (111,243) 127,309 
Total operating income 
$
22,931,311
 $21,530,499 $19,969,746 
           
Depreciation and Amortization
          
Natural gas distribution, transmission and marketing 
$
6,312,277
 $5,682,137 $5,418,007 
Propane  
1,658,554
  1,574,357  1,524,016 
Advanced information services  
112,729
  122,569  138,007 
Other and eliminations  
160,155
  189,146  177,508 
Total depreciation and amortization 
$
8,243,715
 $7,568,209 $7,257,538 
           
Capital Expenditures
          
Natural gas distribution, transmission and marketing 
$
43,894,614
 $28,433,671 $13,945,214 
Propane  
4,778,891
  3,955,799  3,395,190 
Advanced information services  
159,402
  294,792  84,185 
Other  
321,204
  739,079  404,941 
Total capital expenditures 
$
49,154,111
 $33,423,341 $17,829,530 
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
 
           
At December 31,
  
2006
  
2005
  
2004
 
Identifiable Assets
          
Natural gas distribution, transmission and marketing 
$
252,292,600
 $225,667,049 $184,412,301 
Propane  
60,170,200
  57,344,859  47,531,106 
Advanced information services  
2,573,810
  2,062,902  2,387,440 
Other  
9,957,374
  10,905,065  7,379,794 
Total identifiable assets 
$
324,993,984
 $295,979,875 $241,710,641 

- Page 61 -
Notes to the Consolidated Financial Statements
Chesapeake usesWe use the management approach to identify operating segments. Chesapeake organizes itsWe 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 Company’s 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.
Page 78     Chesapeake Utilities Corporation 2009 Form 10-K

The Company’sfollowing 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 
       
Chesapeake Utilities Corporation 2009 Form 10-K     Page 79

Our operations are allalmost entirely domestic. TheOur advanced information services segmentsubsidiary, 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  $— 
D.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.
Page 80     Chesapeake Utilities Corporation 2009 Form 10-K

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.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 81

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:
Various itemsLevel 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 balance sheetfair 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  $— 
Page 82     Chesapeake Utilities Corporation 2009 Form 10-K

The following table summarizes our financial assets and liabilities that are consideredmeasured 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 be financial instruments because they are cash or are to be settledmeasure fair value assets in cash.the table above on a recurring basis as of December 31, 2009 and 2008:
Level 1 Fair Value Measurements:
Investments— The carryingfair values of these items generally approximate theirtrading securities are recorded at fair value (see Note E to the Consolidated Financial Statements for disclosure of fair value of investments). The Company’s open forward and futures contracts at December 31, 2006 had a gain in fair value of $8,500 and at December 31, 2005 had a gain in fair value of $46,000 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 rates. transactions in either the listed or OTC markets.
Propane price swap agreement and put option —The fair value of the Company’spropane 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, is estimatedwhich 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. The Company’s long-term debt at December 31, 2006, including current maturities, had an estimated fair value of $81.4 million as compared tomethodology that incorporates a carrying value of $78.7 million. At December 31, 2005, the estimated fair value was approximately $68.5 million as compared to a carrying value of $63.9 million. These estimates aremarket interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities.

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.
E.G. Investments
The investment balances at December 31, 20062009 and 20052008 represent a Rabbi Trust (“the trust”) associated with the Company’sour Supplemental Executive Retirement Savings Plan. In accordancePlan and a Rabbi Trust related to a stay bonus agreement with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifiesa former executive. We classify these investments as trading securities. As a result of classifyingsecurities and report them as trading securities, we are required to report the securities at their fair value, with anyvalue. 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 along with other expense, for the gains and losses incurred by the trust.Rabbi Trusts. At December 31, 20062009 and 2005,2008, total investments had a fair value of $2.0 million and $1.7 million.$1.6 million, respectively.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 83

F.H. Goodwill and Other Intangible Assets
In accordanceOn October 28, 2009, we completed the merger with SFAS No. 142, goodwill 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. The propane unit had $674,000FPU, which resulted in $33.4 million in goodwill, for the two years endedregulated energy segment. The regulated energy segment did not have goodwill prior to the merger. As of December 31, 20062009 and 2005. Testing2008, the unregulated energy segment reported $674,000 in goodwill. No goodwill was recorded in the unregulated energy segment as a result of the merger with FPU. We test for 2006impairment of goodwill at least annually. The impairment testing for 2009 and 2005 has2008 indicated that no impairment has occurred.of goodwill.


- Page 62 -
NotesWe intend to seek recovery of the purchase premium related to the Consolidated Financial Statements

regulated operations through future rates in Florida. If and when approval is obtained from the Florida PSC to recover all or part of the purchase premium in future rates from customers, we will reclassify that portion of goodwill, for which recovery has been authorized, to a regulatory asset.
The carrying value and accumulated amortization of intangible assets subject to amortization for the two years ended December 31, 20062009 and 2008 are as follows:

                 
  December 31, 2009  December 31, 2008 
  Gross      Gross    
  Carrying  Accumulated  Carrying  Accumulated 
(in thousands) amount  amortization  amount  amortization 
                 
Favorable propane contracts $519  $169  $—  $— 
Customer relationships — FPU  3,500   49   —   — 
Customer list  115   97   115   90 
Acquisition costs  264   132   264   125 
             
  $4,398  $447  $379  $215 
             

  
December 31, 2006
 
December 31, 2005
 
  Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization 
Customer lists 
$
115,333
 
$
75,057
 $115,333 $67,845 
Acquisition costs  
263,659
  
112,057
  263,659  105,465 
Total 
$
378,992
 
$
187,114
 $378,992 $173,310 

In the FPU merger, we acquired intangible assets related to propane customer relationships and favorable propane contracts, which are shown separately on the table above, and are amortized over a 12-year period and a period ranging from one to 14 months, respectively. Customer list and acquisition costs are related to our acquisitions in the late 1980’s and 1990’s, which are amortized over a 16-year period and a 40-year period, respectively.
Amortization expense of intangible assets was $14,000for 2010 to 2014 is: $655,000 for 2010, $305,000 for 2011, $302,000 for 2012, $298,000 for 2013, and $298,000 for 2014.
Page 84     Chesapeake Utilities Corporation 2009 Form 10-K

I. Income Taxes
We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. FPU will be included in our 2009 consolidated federal return for the post-merger period. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. FPU will continue to file a separate state income tax return in Florida.
In September 2008, the IRS completed its examination of our 2005 and 2006 consolidated federal returns and issued its Examination Report. As a result of the examination, we reduced our income tax receivable by $27,000 for the tax liability associated with disallowed expense deductions included on the tax returns. We have amended our 2005 and 2006 federal and state corporate income tax returns to reflect the disallowed expense deductions. We are no longer subject to income tax examinations by the Internal Revenue Service for years endedbefore December 31, 20062006. FPU filed a separate federal income tax return for the period prior to the merger and 2005, respectively. The estimated annual amortizationis not subject to income tax examinations by the IRS for years before December 31, 2005.
We generated net operating losses in 2008, for federal income tax purposes, which were generated primarily from increased book-to-tax timing differences authorized by the 2008 American Recovery and Reinvestment Act, which allowed bonus depreciation for certain assets. A federal tax net operating loss of intangibles is $14,000 per year$9,049,132 was carried forward to 2009 and fully offset taxable income for eachthe year. As of December 31, 2009, we have a federal tax net operating loss of $202,000 which expires in 2027. As of December 31, 2009, we also had tax net operating losses from various states totaling $2.7 million, almost all of which expire in 2027. We have recorded a deferred tax asset of $305,000 related to these carry-forwards. We have not recorded a valuation allowance to reduce the future benefit of the years 2007 through 2011, respectively.tax net operating losses because we believe they will all be utilized.

G. Stockholders’ Equity
The changes intables below provide the common stock shares issuedfollowing: (a) the components of income tax expense; (b) reconciliation between the statutory federal income tax rate and outstanding are shown in the table below:
For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Common Stock shares issued and outstanding (1)
       
Shares issued — beginning of period balance  
5,883,099
  5,778,976  5,660,594 
Dividend Reinvestment Plan (2)
  
38,392
  41,175  40,993 
Retirement Savings Plan  
29,705
  21,071  39,157 
Conversion of debentures  
16,677
  22,609  18,616 
Employee award plan  
350
  -  - 
Performance shares and options exercised (3)
  
29,516
  19,268  19,616 
Public offering  
690,345
  -  - 
Shares issued — end of period balance (4)
  
6,688,084
  5,883,099  5,778,976 
           
Treasury shares — beginning of period balance  
(97
)
 (9,418) - 
Purchases  
-
  (4,852) (15,316)
Dividend Reinvestment Plan  
-
  2,142  - 
Retirement Savings Plan  
-
  12,031  - 
Other issuances  
97
  -  5,898 
Treasury Shares — end of period balance  
-
  (97) (9,418)
           
Total Shares Outstanding  
6,688,084
  
5,883,002
  
5,769,558
 
           
(1) 12,000,000 shares are authorized at a par value of $0.4867 per share.
 
(2) Includes shares purchased with reinvested dividends and optional cash payments.
 
(3) Includes shares issued for Directors' compensation.
 
(4) Includes 48,187, 37,528, and 48,175 shares at December 31, 2006, 2005 and 2004, respectively, held in a Rabbi Trust established by the Company relating to the Executive Deferred Compensation Plan.
 

In 2000effective income tax rate; and 2001,(c) the Company entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 sharescomponents of Chesapeake stock in 2000accumulated deferred income tax assets and liabilities at an exercise price of $18.00 per share and 15,000 in 2001 at an exercise price of $18.25 per share. In August 2006, the investment banker exercised the 30,000 warrants pursuant to the terms of the agreement at $33.3657 per share. At the request of the investment banker, Chesapeake settled the warrants with a cash payment of $435,000, in lieu of issuing shares of the Company’s common stock. At December 31, 2006, 2009 and 2008.
Chesapeake does not have any stock warrants outstanding.Utilities Corporation 2009 Form 10-K     Page 85

             
For the Years Ended December 31, 2009  2008  2007 
(in thousands)            
Current Income Tax Expense
            
Federal $—  $(2,551) $5,512 
State  878   —   1,223 
Investment tax credit adjustments, net  (69)  (42)  (51)
          
Total current income tax expense (benefit)  809   (2,593)  6,684 
          
             
Deferred Income Tax Expense(1)
            
Property, plant and equipment  7,187   10,347   2,959 
Deferred gas costs  (786)  781   (629)
Pensions and other employee benefits  (612)  (174)  (9)
Environmental expenditures  7   145   46 
Net operating loss carryforwards  4,043   —   — 
Merger related costs  967   —   — 
Reserve for insurance deductibles  518   462   27 
Other  (1,215)  (151)  (492)
          
Total deferred income tax expense (benefit)  10,109   11,410   1,902 
          
Total Income Tax Expense
 $10,918  $8,817  $8,586 
          
             
             
For the Years Ended December 31, 2009  2008  2007 
Reconciliation of Effective Income Tax Rates
(in thousands)
            
Continuing Operations            
Federal income tax expense(2)
 $9,171  $7,863  $7,635 
State income taxes, net of federal benefit  1,490   1,162   1,087 
Merger related costs  299   —   — 
ESOP dividend deduction  (213)  (205)  (199)
Other  171   (3)  74 
          
Total continuing operations  10,918   8,817   8,597 
Discontinued operations  —   —   (11)
          
Total Income Tax Expense
 $10,918  $8,817  $8,586 
          
             
Effective income tax rate
  40.72%  39.32%  39.41%
         
At December 31, 2009  2008 
(in thousands)        
Deferred Income Taxes
        
Deferred income tax liabilities:
        
Property, plant and equipment $75,898  $41,248 
Environmental costs  —   395 
Deferred gas costs  689   — 
Other  3,162   2,414 
       
Total deferred income tax liabilities  79,749   44,057 
       
         
Deferred income tax assets:
        
Pension and other employee benefits  6,406   4,679 
Environmental costs  1,802   — 
Self insurance  1,318   370 
Storm reserve liability  985   — 
Deferred gas costs  —   364 
Other  3,813   2,502 
       
Total deferred income tax assets  14,324   7,915 
       
Net Deferred Income Taxes Per Consolidated Balance Sheet
 $65,425  $36,142 
       
(1)Includes $985,000, $1,588,000 and $260,000 of deferred state income taxes for the years 2009, 2008 and 2007, respectively.
(2)Federal income taxes were recorded at 35% for each year represented.
Page 86     Chesapeake Utilities Corporation 2009 Form 10-K

- Page 63 -
Notes to the Consolidated Financial Statements

On November 21, 2006 the Company completed a public offering of 600,300 shares of its common stock at a price per share of $30.10. On November 30, 2006, the Company completed the sale of 90,045 additional shares of its common stock, pursuant to the over-allotment option granted to the Underwriters by the Company. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $19.8 million, which were added to the Company’s general funds and used primarily to repay a portion of the Company’s short-term debt under unsecured lines of credit.

H.J. Long-term Debt
TheOur outstanding long-term debt net of current maturities, is as shown below.

         
  December 31,  December 31, 
(in thousands) 2009  2008 
        
Secured first mortgage bonds:        
9.57% bond, due May 1, 2018 $8,156  $— 
10.03% bond, due May 1, 2018  4,486   — 
9.08% bond, due June 1, 2022  7,950   — 
6.85% bond, due October 1, 2031  14,012   — 
4.90% bond, due November 1, 2031  13,222   — 
Uncollateralized senior notes:        
6.91% note, due October 1, 2010  909   1,818 
6.85% note, due January 1, 2012  2,000   3,000 
7.83% note, due January 1, 2015  10,000   12,000 
6.64% note, due October 31, 2017  21,818   24,545 
5.50% note, due October 12, 2020  20,000   20,000 
5.93% note, due October 31, 2023  30,000   30,000 
Convertible debentures:        
8.25% due March 1, 2014  1,520   1,655 
Promissory note  40   60 
       
Total long-term debt  134,113   93,078 
Less: current maturities  (35,299)  (6,656)
       
Total long-term debt, net of current maturities $98,814  $86,422 
       
At December 31,
 
2006
 
2005
 
2004
 
Uncollateralized senior notes:       
7.97% note, due February 1, 2008 
$
1,000,000
 $2,000,000 $3,000,000 
6.91% note, due October 1, 2010  
2,727,273
  3,636,363  4,545,454 
6.85% note, due January 1, 2012  
4,000,000
  5,000,000  6,000,000 
7.83% note, due January 1, 2015  
14,000,000
  16,000,000  20,000,000 
6.64% note, due October 31, 2017  
27,272,727
  30,000,000  30,000,000 
5.50% note, due October 12, 2020  
20,000,000
  -  - 
Convertible debentures:          
8.25% due March 1, 2014  
1,970,000
  2,254,000  2,644,000 
Promissory note  
80,000
  100,000  - 
Total Long-Term Debt 
$
71,050,000
 $58,990,363 $66,189,454 
           
Annual maturities of consolidated long-term debt for the next five years are as follows: $7,656,364 for 2007;$7,656,364 for 2008; $6,656,364 for 2009,$6,656,364 for 2010 and $7,747,273 for 2011.
 
Annual maturities of consolidated long-term debt are as follows: $36,765 for 2010; $9,156 for 2011; $8,136 for 2012; $8,136 for 2013; $12,656 for 2014 and $60,818 thereafter. The annual maturity for 2010 of $37,765 includes $28,700 of the secured first mortgage bonds redeemed prior to stated maturity in January 2010.

Secured First Mortgage Bonds
In October 2009, we became subject to the obligations of FPU’s secured first mortgage bonds in connection with the merger. FPU’s secured first mortgage bonds had a carrying value of $47.8 million ($49.3 million in outstanding principal balance). The first mortgage bonds are secured by a lien covering all of FPU’s property. The 9.57 percent bond and 10.03 percent bond require annual sinking fund payments of $909,000 and $500,000, respectively.
In January 2010, we redeemed the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds prior to their respective maturity for $28.7 million, which represented the outstanding principal balance of those bonds. We used short-term borrowing to finance the redemption of these bonds. The difference between the carrying value of those bonds and the amount paid at redemption totaling $1.5 million was deferred as a regulatory asset.
Uncollateralized Senior Notes
On October 31, 2008, we issued $30 million of 5.93 percent uncollateralized senior notes to two institutional investors. The terms of the senior notes require a semi-annual principal repayment of $1.5 million in April and October of each year, commencing on April 30, 2014. The senior notes will mature on October 31, 2023. The proceeds of the sale of the Senior Notes were used to refinance capital expenditures and for general corporate purposes.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 87

Convertible Debentures
The convertible debentures may be converted, at the option of the holder, into shares of the Company’sour common stock at a conversion price of $17.01 per share. During 20062009 and 2005,2008, debentures totaling $284,000$135,000 and $385,000,$177,000, respectively, were converted to stock. The debentures are also redeemable for cash at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000. In 2006,2009 and 2008, no debentures were redeemed for cash. During 2005, debentures totaling $5,000 were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.

On October 12, 2006, the Company issued $20 million of 5.5 percent Senior Notes to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). The original note agreement was executed on October 18, 2005 and provided for the Company to sell the Notes at any time prior to January 15, 2007. The terms of the Notes require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes. The Notes will mature on October 12, 2020. The proceeds from this issuance were used to reduce a portion of the Company’s outstanding short-term debt.

Debt Covenants
Indentures to theour long-term debt of the Company and its subsidiaries contain various restrictions. The most stringent restrictions state that the Companywe must maintain equity of at least 40 percent of total capitalization, and the pro-forma fixed charge coverage ratio must be 1.5at least 1.2 times. TheIn connection with the merger, the uncollateralized senior notes were amended to include an additional covenant requiring the Company isto maintain no more than a 20-percent ratio of secured and subsidiary long-term debt to consolidated tangible net worth by October 2011. Failure to comply with those covenants could result in accelerated due dates and/or termination of the uncollateralized senior note agreements. As of December 31, 2009, we are in compliance with all of itsour debt covenants.covenants and with the redemption of FPU’s 6.85 percent and 4.90 percent secured first mortgage bonds in January 2010, the additional covenant requiring us to maintain no more than a 20-percent ratio of secured and subsidiary long-term debt to consolidated tangible net worth has been met.
Each of Chesapeake’s uncollateralized senior notes contains a “Restricted Payments” covenant as defined in the note agreements. The most restrictive covenants of this type are included within the 7.83 percent senior notes, due January 1, 2015. The covenant provides that we 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, the 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.
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 restrictive 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 provides 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.
I.K. Short-term Borrowing
At December 31, 2009 and 2008, the Company had $30.0 million and $33.0 million, respectively, of short-term borrowing outstanding under our bank credit facilities. The annual weighted average interest rates on its short-term borrowing were 1.28 percent and 2.79 percent for 2009 and 2008, respectively. We incurred commitment fees of $79,000 and $16,000 in 2009 and 2008, respectively.
In October 2009 in connection with the FPU merger, we became subject to $4.2 million in outstanding borrowings under FPU’s revolving line of credit. All of the outstanding borrowings were repaid in full in November 2009 and FPU’s revolving line of credit was terminated on November 23, 2009.
Page 88     Chesapeake Utilities Corporation 2009 Form 10-K

As of December 31, 2006, the Board of Directors (“Board”) has authorized the Company to borrow up to $55.0 million from various banks and trust companies under short-term lines of credit. During 2006, the Board authorized increases in the Company’s borrowing authority up to $75 million to fund the 2006 capital budget and working capital. The $75 million limit was subsequently reduced to its current level by the Board on November 7, 2006, following the placement on October 12, 2006 of $20 million 5.50 percent Senior Notes.
- Page 64 -
Notes to the Consolidated Financial Statements

As of December 31, 2006, the Company2009, we had four unsecured bank lines of credit with two financial institutions, totaling $80.0$90.0 million, none of which requiredrequires compensating balances. The unsecured bank lines of credit were increased to $100.0 million in January 2010. These bank lines are available to provide funds for the Company’sour short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of itsour capital expenditures. TwoWe 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. We maintain both committed and uncommitted credit facilities. Advances offered under the bankuncommitted lines totaling $15.0 million, are committed. The other two linesof credit are subject to the banks’discretion of the banks.
Committed credit facilities
As of December 31, 2009 we had two committed revolving credit facilities totaling $55.0 million, which were subsequently increased to $60.0 million in January 2010. The first facility is an unsecured $30.0 million revolving line of credit that bears interest at the respective LIBOR rate, plus 1.25 percent per annum. At December 31, 2009, there was $7.5 million available under this credit facility.
The second facility is a $25.0 million committed revolving line of credit that bears interest at a base rate plus 1.25 percent, if requested and advanced on the same day, or LIBOR for the applicable period plus 1.25 percent if requested three days prior to the advance date. At December 31, 2009, there was $18.3 million available under this credit facility. In January 2010, the second facility was increased to a $30.0 million committed revolving line of credit with the same terms, resulting in total committed revolving credit facilities of $60.0 million.
The availability of funds. Underfunds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. The Company is required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year:
a funded indebtedness ratio of no greater than 65 percent; and
a fixed charge coverage ratio of at least 1.20 to 1.0.
We are in compliance with all of our debt covenants.
Uncommitted credit facilities
As of December 31, 2009, we had two uncommitted lines of credit facilities totaling $35.0 million, which were subsequently increased to $40.0 million in January 2010. Advances offered under the outstanding balancesuncommitted lines of short-term debtcredit are subject to the discretion of the banks.
The first facility is an uncommitted $20.0 million line of credit that bears interest at a rate per annum as offered by the bank for the applicable period. At December 31, 2006 and 2005 were $27.62009, the entire borrowing capacity of $20.0 million and $35.5was available under this credit facility.
The second facility is a $15.0 million respectively. The annual weighted averageuncommitted line of credit that bears interest rates on short-term debt were 5.47 percent and 4.47 percentat a rate per annum as offered by the bank for 2006 and 2005, respectively. The Company also hadthe applicable period. At December 31, 2009, there was $14.3 million available under this credit facility, which was reduced by $725,000 for a letter of credit outstandingissued to our primary insurance company. The letter of credit is provided as security to satisfy the deductibles under our various insurance policies and expires on August 31, 2010. We do not anticipate that this letter of credit will be drawn upon by the counter-party and we expect that it will be renewed as necessary. In January 2010, the second facility was increased to a $20.0 million uncommitted line of credit with the same terms, resulting in the amounttotal uncommitted revolving credit facilities of $775,000 that reduced the amounts available under the lines of credit.

$40.0 million.
J.L. Lease Obligations
The Company hasWe have entered into several operating lease arrangements for office space, at various locations, equipment and pipeline facilities. Rent expense related to these leases was $680,000, $837,000,$997,000, $880,000 and $934,000$736,000 for 2006, 20052009, 2008 and 2004,2007, respectively. Future minimum payments under the Company’sour current lease agreements are $650,000, $496,000, $423,000, $331,000$866,000, $771,000, $677,000, $502,000 and $321,000$364,000 for the years 20072010 through 2011,2014, respectively; and $3.8$2.0 million thereafter, totaling $6.0with an aggregate total of $5.2 million.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 89

K.M. Employee Benefit Plans
Retirement Plans
Retirement Plans
Before 1999, Company employees generally participated in bothWe sponsor a defined benefit pension plan (“DefinedChesapeake Pension Plan”), an unfunded pension supplemental executive retirement plan (“Chesapeake SERP”), and an unfunded postretirement health care and life insurance plan (“Chesapeake Postretirement Plan”). As a result of the merger with FPU, we now sponsor and maintain a separate defined benefit pension plan for FPU (“FPU Pension Plan”) and a Retirement Savings Plan. Effective January 1, 1999,separate unfunded postretirement medical plan for FPU (“FPU Medical Plan”).
We measure the Company restructured its retirement program to compete more effectively with similar businesses. As part of this restructuring, the Company closed the Defined Pension Plan to new participants. Employees who participated in the Defined Pension Plan at that time were given the option of remaining in (and continuing to accrue benefits under) the Defined Pension Plan or receiving an enhanced matching contribution in the Retirement Savings Plan.

Because the Defined Pension Plan was not open to new participants, the number of active participants in that plan decreasedassets and is approaching the minimum number needed for the Defined Pension Plan to maintain its tax-qualified status. To avoid jeopardizing the tax-qualified statusobligations of the Defined Pension Plan, the Company’s Board of Directors amended the Defined Pension Plan on September 24, 2004. To ensure that the Company continues to provide appropriate levels of benefits to the Company’s employees, the Board amended the Defined Pension Plan and the Retirement Savings Plan, effective January 1, 2005, so that Defined Pension Plan participants who were actively employed by the Company on that date (1) receive two additional years of benefit service credit to be used in calculating their Defined Pension Plan benefit (subject to the Defined Pension Plan’s limit of 35 years of benefit service credit), (2) have the option to receive their Defined Pension Plan benefit in the form of a lump sum at the time they retire, and (3) are eligible to receive the enhanced matching contribution in the Retirement Savings Plan. In addition, effective January 1, 2005, the Board amended the Defined Pension Plan so that participants will not accrue any additional benefits under that plan. These changes were communicated to the Company’s employees during the first week of November 2004. As a result of the amendments to the Defined Pension Plan, a gain of approximately $172,000 (after tax) was recorded during 2004.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). The Company adopted SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize all obligations related to defined benefit pensionspension plans and other postretirement benefits. This statement requires that we quantifybenefits plans to determine the plans’ funded status as of the end of the year as an asset or a liability on our consolidated balance sheets.
- Page 65 -
Notes to the Consolidated Financial Statements

SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. The Company is also required to We recognize as a component of accumulated other comprehensive income (“AOCI”)income/loss the changes in funded status that occurred during the year but that are not recognized as part of net periodic benefit costcosts, except for the portion related to FPU’s regulated energy operations, which is deferred as explaineda regulatory asset to be recovered in SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

Based on the funded status offuture pursuant to a previous order by the Company’s defined benefit pension and postretirement benefit plans as ofFlorida PSC. The measurement dates were December 31, 2006, the effects of adopting SFAS 158 on the Company’s financial statement is set forth in the following table.


  
Pre-SFAS 158
 
SFAS Adoption Adjustments
 
Post SFAS 158
 
Asset (liability) for pension benefits  ($3,741,054)$281,538  ($3,459,516)
Deferred income tax asset (liability)  1,224,742  (111,973) 1,112,769 
Accumulated other comprehensive income  504,115  (169,565) 334,550 


The amounts recognized in AOCI as a result of the adoption of SFAS 158 consist of:


  
Defined Benefit Pension
 
Other Postretirement Benefit
 
Total
 
Prior service cost (credit)  ($29,560) -  ($29,560)
Loss (gain)  (1,284,400) 1,032,422  (251,978)
Total  (1,313,960) 1,032,422  (281,538)
Less: Deferred tax asset (liability)  (522,582) 410,609  (111,973)
Loss (gain) in AOCI, net of tax  ($791,378)$621,813  ($169,565)

2009 and 2008.
The amounts in AOCIaccumulated other comprehensive income/loss for the respective retirementour pension and postretirement benefits plans that are expected to be recognized as a component of net benefit cost in 2007 is2010 are set forth in the following table.
                         
  Chesapeake  FPU      Chesapeake  FPU    
  Pension  Pension  Chesapeake  Postretirement  Medical    
(in thousands) Plan  Plan  SERP  Plan  Plan  Total 
Prior service cost (credit) $(5) $—  $19  $—  $—  $14 
Net (gain) loss $(137) $—  $47  $71  $—  $(19)

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive income/loss as of December 31, 2009.
 
Defined Benefit Pension
 
Executive Excess Defined Benefit
 
Total
                         
 Chesapeake FPU Chesapeake FPU   
 Pension Pension Chesapeake Postretirement Medical   
(in thousands) Plan Plan SERP Plan Plan Total 
Prior service cost (credit)  ($4,699) -  -  $(15) $— $102 $— $— $87 
Loss (gain)  (6,846) 51,279  136,978 
Net loss (gain) 2,672  (540) 673 1,351  (14) 4,142 
             
Subtotal 2,657  (540) 775 1,351  (14) 4,229 
Tax expense (benefit)  (1,065) 208  (311)  (542) 5  (1,705)
             
Accumulated other comprehensive (income) loss $1,592 $(332) $464 $809 $(9) $2,524 
             


Defined Benefit Pension PlanPlans
As described above,The Chesapeake Pension Plan was closed to new participants effective January 1, 2005, the Defined Pension Plan1999 and was frozen with respect to additional years of service or additional compensation.compensation effective January 1, 2005. Benefits under the planChesapeake Pension Plan were based on each participant’s years of service and highest average compensation, prior to the freeze. freezing of the plan.
The Company’sFPU Pension Plan covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the merger, the FPU Pension Plan was frozen with respect to additional years of service and additional compensation effective December 31, 2009.
Our funding policy provides that payments to the trustee of each plan shall be equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The Company doesWe were not expect to be required to make any funding payments towardto the DefinedChesapeake Pension Plan in 2007. The measurement dates for2009 or to the FPU Pension Plan were December 31, 2006 and 2005, respectively.subsequent to the merger closing in October 2009.

Page 90     Chesapeake Utilities Corporation 2009 Form 10-K

The following schedule summarizes the assets of the DefinedChesapeake Pension Plan, by investment type, at December 31, 2006, 20052009, 2008 and 2004:2007 and the assets of the FPU Pension Plan, by investment type, at December 31, 2009:

At December 31,
 
2006
 
2005
 
2004
 
Asset Category
       
Equity securities  
77.34
%
 76.12% 72.64%
Debt securities  
18.59
%
 23.28% 12.91%
Other  
4.07
%
 0.60% 14.45%
Total  
100.00
%
 100.00% 100.00%
- Page 66 -
Notes to the Consolidated Financial Statements
                 
  Chesapeake  FPU 
  Pension Plan  Pension Plan 
At December 31, 2009  2008  2007  2009 
Asset Category
                
Equity securities  66.22%  48.70%  49.03%  63.00%
Debt securities  33.76%  51.24%  50.26%  29.00%
Other  0.02%  0.06%  0.71%  8.00%
             
Total  100.00%  100.00%  100.00%  100.00%
             
The asset listed as “Other” in the above table represents monies temporarily held in money market funds. The money market fund investsfunds, which invest at least 80 percent of itstheir total assets in:
United States government obligations; and
·  United States Government obligations; and
Repurchase agreements that are fully collateralized by such obligations.
·  Repurchase agreements that are fully collateralized by such obligations.

All of the assets held by the Chesapeake Pension Plan and FPU Pension Plan are classified under Level 1 of the fair value hierarchy and are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
The investment policy offor the Chesapeake Pension Plan calls for an allocation of assets between equity and debt instruments, with equity being 60 percent and debt at 40 percent, but allowing for a variance of 20 percent in either direction. Additionally,In addition, as changes are made to holdings, cash, money market funds or United States Treasury Bills may be held temporarily by the fund. Investments in the following are prohibited: options, guaranteed investment contracts, real estate, venture capital, private placements, futures, commodities, limited partnerships and Chesapeake stock. Additionally,stock; short selling and margin transactions are prohibited.prohibited as well. Investment allocation decisions are made by the Employee Benefits committee. During 2004, Chesapeake modified its investment policy to allow the Employee Benefits Committee to reallocate investments to better match the expected life of the plan.

The investment policy for the FPU Pension Plan is designed to achieve a long-term rate of return, including investment income and appreciation, sufficient to meet the actuarial requirements of the plan. The plan’s investment strategy is to achieve its return objectives by investing in a diversified portfolio of equity, fixed income and cash securities seeking a balance of growth and stability as well as an adequate level of liquidity for pension distributions as they fall due. Plan assets are constrained such that no more than 10 percent of the portfolio will be invested in any one issue. Investment allocation decisions for the FPU Pension Plan are made by the Pension Committee.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 91

The following schedule sets forth the funded status of the Defined Pension Plan at December 31, 2006, 20052009 and 2004:2008:
             
  Chesapeake  FPU 
  Pension Plan  Pension Plan 
At December 31, 2009  2008  2009 
(in thousands)            
Change in benefit obligation:
            
Benefit obligation — beginning of year(1)
 $11,593  $11,074  $46,851 
Interest cost  547   594   418 
Change in assumptions  (188)  268   — 
Actuarial loss  (307)  84   (1,544)
Benefits paid  (518)  (427)  (305)
          
Benefit obligation — end of year  11,127   11,593   45,420 
          
             
Change in plan assets:
            
Fair value of plan assets — beginning of year(1)
  6,689   10,799   35,037 
Actual return on plan assets  1,278   (3,683)  1,695 
Benefits paid  (518)  (427)  (305)
          
Fair value of plan assets — end of year  7,449   6,689   36,427 
          
             
Reconciliation:
            
Funded status  (3,678)  (4,904)  (8,993)
          
Accrued pension cost
 $(3,678) $(4,904) $(8,993)
          
             
Assumptions:
            
Discount rate  5.25%  5.25%  5.75%
Expected return on plan assets  6.00%  6.00%  7.00%

At December 31,
 
2006
 
2005
 
2004
 
Change in benefit obligation:
       
Benefit obligation — beginning of year 
$
12,399,621
 $12,053,063 $11,948,755 
Service cost  
-
  -  338,352 
Interest cost  
635,877
  645,740  690,620 
Change in assumptions  
(301,851
)
 388,979  573,639 
Actuarial loss  
607
  28,895  220,842 
Amendments  
-
  -  883,753 
Effect of curtailment/settlement  
-
  -  (2,171,289)
Benefits paid  
(1,284,529
)
 (717,056) (431,609)
Benefit obligation — end of year  
11,449,725
  12,399,621  12,053,063 
           
Change in plan assets:
          
Fair value of plan assets — beginning of year  
11,780,866
  12,097,248  11,301,548 
Actual return on plan assets  
1,543,950
  400,674  1,227,309 
Benefits paid  
(1,284,529
)
 (717,056) (431,609)
Fair value of plan assets — end of year  
12,040,287
  11,780,866  12,097,248 
           
Reconciliation of funded status: (1)
          
Plan assets in excess (less than) benefit obligation at year-end  
590,560
  (618,755) 44,185 
Unrecognized prior service cost  
-
  (34,259) (38,958)
Unrecognized net actuarial gain  
-
  (129,739) (850,224)
Net amount accrued
 
$
590,560
  ($782,753) ($844,997)
           
Assumptions:
          
Discount rate  
5.50
%
 5.25% 5.50%
Expected return on plan assets  
6.00
%
 6.00% 7.88%
           
(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.
 

(1)FPU Pension Plan’s beginning balance reflects the benefit obligations as of the merger date of October 28, 2009.
Net periodic pension costscost (benefit) for the defined benefit Pension Planplans for 2006, 2005,2009, 2008, and 20042007 include the components as shown below:

                 
  Chesapeake  FPU 
 Pension Plan  Pension Plan(1) 
For the Years Ended December 31, 2009  2008  2007  2009 
(in thousands)        
Components of net periodic pension cost (benefit):
                
Interest cost $547  $594  $622  $418 
Expected return on assets  (362)  (629)  (696)  (396)
Amortization of prior service cost  (5)  (5)  (5)  — 
Amortization of actuarial loss/gain  237   —   —   — 
             
Net periodic pension cost (benefit)
 $417  $(40) $(79) $22 
             
 
Assumptions:
                
Discount rate  5.25%  5.50%  5.50%  5.50%
Expected return on plan assets  6.00%  6.00%  6.00%  7.00%
(1)FPU Pension Plan’s net periodic pension cost includes only the cost from the merger closing (October 28, 2009) through December 31, 2009.

Page 92     Chesapeake Utilities Corporation 2009 Form 10-K

For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Components of net periodic pension cost:
       
Service cost 
$
0
 $0 $338,352 
Interest cost  
635,877
  645,740  690,620 
Expected return on assets  
(690,533
)
 (703,285) (869,336)
Amortization of:          
Transition assets  
-
  -  (11,328)
Prior service cost  
(4,699
)
 (4,699) (4,699)
Net periodic pension cost (benefit)
  
($59,355
)
 ($62,244)$143,609 

- Page 67 -
Notes to the Consolidated Financial Statements
Pension Supplemental Executive Retirement Plan
The following actuarial assumptions were used in calculating net periodic pension cost or benefit.

For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Assumptions:
       
Discount rate  
5.25
%
 5.50% 5.88%
Expected return on plan assets  
6.00
%
 6.00% 7.88%

The assumptions used for the discount rate of the plan were reviewed by the Company and increased from 5.25 percent to 5.50 percent, reflecting an increase in the interest rates of high quality bonds and reflecting the expected life of the plan, due to the lump sum payment option. Additionally, the average expected return on plan assets for the qualified plan remained constant at 6 percent due to the adoption of a change in the investment policy that allows for a higher level of investment in bonds and a lower level of equity investments. Since the Plan is frozen in regards to additional years of service and compensation, the rate of assumed compensation rate increases is not applicable. The accumulated benefit obligation was $11.4 million and $12.4 million at December 31, 2006 and 2005, respectively.

Executive Excess Defined Benefit Pension Plan
The Company also sponsors an unfunded executive excess defined benefit pension plan. As noted above, this planChesapeake SERP was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the planChesapeake SERP were based on each participant’s years of service and highest average compensation, prior to the freeze.freezing of the plan. The accumulated benefit obligation for the Chesapeake SERP, which is unfunded, was $2.29 million and $2.32$2.5 million at both December 31, 20062009 and 2005, respectively.2008.

         
At December 31, 2009  2008 
(In thousands)        
Change in benefit obligation:
        
Benefit obligation — beginning of year $2,520  $2,326 
Interest cost  129   125 
Actuarial (gain) loss  (55)  39 
Amendments  —   119 
Benefits paid  (89)  (89)
       
Benefit obligation — end of year  2,505   2,520 
       
         
Change in plan assets:
        
Fair value of plan assets — beginning of year  —   — 
Employer contributions  89   89 
Benefits paid  (89)  (89)
       
Fair value of plan assets — end of year  —   — 
       
         
Reconciliation:
        
Funded status  (2,505)  (2,520)
       
Accrued pension cost
 $(2,505) $(2,520)
       
         
Assumptions:
        
Discount rate  5.25%  5.25%
Net periodic pension costs for the executive excess benefit pension planChesapeake SERP for 2006, 2005,2009, 2008, and 20042007 include the components as shown below:

             
For the Years Ended December 31, 2009  2008  2007 
(in thousands)            
Components of net periodic pension cost:
            
Interest cost $130  $125  $123 
Amortization of prior service cost  18   —   — 
Amortization of actuarial loss  54   45   52 
          
Net periodic pension cost
 $202  $170  $175 
          
 
Assumptions:
            
Discount rate  5.25%  5.50%  5.50%

For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Components of net periodic pension cost:
       
Service cost 
$
0
 $0 $105,913 
Interest cost  
119,588
  119,658  87,568 
Amortization of:          
Prior service cost  
-
  -  2,090 
Actuarial loss  
57,039
  49,319  21,699 
Net periodic pension cost
 
$
176,627
 $168,977 $217,270 

Chesapeake Utilities Corporation 2009 Form 10-K     Page 93


- Page 68 -
Notes to the Consolidated Financial Statements

Other Postretirement Benefits Plans
The following schedule sets forth the status of other postretirement benefit plans:
             
  Chesapeake  FPU 
  Postretiment Plan  Medical Plan 
At December 31, 2009  2008  2009 
(in thousands)            
Change in benefit obligation:
            
Benefit obligation — beginning of year(1)
 $2,179  $1,756  $2,457 
Service cost  3   3   18 
Interest cost  131   114   23 
Plan participants contributions  90   104   6 
Actuarial (gain) loss  378   345   (71)
Benefits paid  (196)  (143)  (16)
          
Benefit obligation — end of year  2,585   2,179   2,417 
          
             
Change in plan assets:
            
Fair value of plan assets — beginning of year(1)
  —   —   — 
Employer contributions(2)
  106   39   10 
Plan participants contributions  90   104   6 
Benefits paid  (196)  (143)  (16)
          
Fair value of plan assets — end of year  —   —   — 
          
             
Reconciliation:
            
Funded status  (2,585)  (2,179)  (2,417)
          
Accrued pension cost
 $(2,585) $(2,179) $(2,417)
          
             
Assumptions:
            
Discount rate  5.25%  5.25%  5.75%
(1)FPU Medical Plan’s beginning balance reflects the benefit obligation as of the merger date of October 28, 2009.
(2)Chesapeake’s Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.
Net periodic postretirement costs for 2009, 2008, and 2007 include the executive excess defined benefit plan:following components:

                 
  Chesapeake  FPU 
  Postretirement Plan  Medical Plan(1) 
For the Years Ended December 31, 2009  2008  2007  2009 
(in thousands)                
Components of net periodic postretirement cost:
                
Service cost $3  $3  $6  $18 
Interest cost  131   114   102   23 
Amortization of:                
Actuarial loss  76   290   166   — 
             
Net periodic postretirement cost
 $210  $407  $274  $41 
             
(1)FPU Medical Plan’s net periodic postretiment includes only the cost from the merger date (October 28, 2009) through December 31, 2009.

Page 94     Chesapeake Utilities Corporation 2009 Form 10-K

At December 31,
 
2006
 
2005
 
2004
 
Change in benefit obligation:
       
Benefit obligation — beginning of year 
$
2,322,471
 $2,162,952 $1,406,190 
Service cost  
-
  -  105,913 
Interest cost  
119,588
  119,658  87,568 
Actuarial (gain) loss  
(65,886
)
 133,839  713,225 
Amendments  
-
  -  60,000 
Effect of curtailment/settlement  
-
  -  (184,844)
Benefits paid  
(89,203
)
 (93,978) (25,100)
Benefit obligation — end of year  
2,286,970
  2,322,471  2,162,952 
           
Change in plan assets:
          
Fair value of plan assets — beginning of year  
-
  -  - 
Employer contributions  
89,203
  93,978  25,100 
Benefits paid  
(89,203
)
 (93,978) (25,100)
Fair value of plan assets — end of year  
-
  -  - 
           
Funded status  
(2,286,970
)
 (2,322,471) (2,162,952)
Unrecognized net actuarial loss  
-
  959,492  874,972 
Net amount accrued (1)
  
($2,286,970
)
 ($1,362,979) ($1,287,980)
           
Assumptions:
          
Discount rate  
5.50
%
 5.25% 5.50%
           
(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.
 

Assumptions
The assumptions used for the discount rate to calculate the benefit obligation of all the planplans were reviewed by the Company and increased from 5.25 percent to 5.50 percent, reflecting an increase inbased on the interest rates of high qualityhigh-quality bonds and a reduction in 2009, reflecting the expected life of the plan.plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the Chesapeake’s plans and FPU’s plans have a different expected life of the plan and investment policy, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan, isdifferent discount rate and expected return on plan asset assumptions were selected for Chesapeake’s plans and FPU’s plans. Since all of the pension plans are frozen in regardswith respect to additional years of service and compensation, the rate of assumed paycompensation rate increases is not applicable. The measurement dates for the executive excess benefit plan were December 31, 2006 and 2005, respectively.

Other Postretirement Benefits
The Company sponsors a defined benefit postretirement health care and life insurance plan that covers substantially all employees.

Net periodic postretirement costs for 2006, 2005 and 2004 include the following components:


For the Years Ended December 31,
 
2006
 
2005
 
2004
 
Components of net periodic postretirement cost:
       
Service cost 
$
9,194
 $6,257 $5,354 
Interest cost  
93,924
  77,872  86,883 
Amortization of:          
Transition obligation  
22,282
  27,859  27,859 
Actuarial loss  
144,694
  88,291  78,900 
Net periodic postretirement cost
 
$
270,094
 $200,279 $198,996 
- Page 69 -
Notes to the Consolidated Financial Statements

The following schedule sets forth the status of the postretirement health care and life insurance plan:


At December 31,
 
2006
 
2005
 
2004
 
Change in benefit obligation:
       
Benefit obligation — beginning of year 
$
1,534,684
 $1,599,280 $1,471,664 
Retirees  
264,470
  (59,152) 91,747 
Fully-eligible active employees  
(114,082
)
 (31,761) 22,071 
Other active  
78,036
  26,317  13,798 
Benefit obligation — end of year 
$
1,763,108
 $1,534,684 $1,599,280 
           
Funded status  
($1,763,108
)
 ($1,534,684) ($1,599,280)
Unrecognized transition obligation  
-
  22,282  50,141 
Unrecognized net actuarial loss  
-
  751,450  899,228 
Net amount accrued (1)
  
($1,763,108
)
 ($760,952) ($649,911)
           
Assumptions:
          
Discount rate  5.50% 5.25% 5.50%
           
(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.
 
The health care inflation rate for 20062009 used to calculate the benefit obligation is assumed to be 67.50 percent for medical and 88.50 percent for prescription drugs. These rates are projected to gradually decrease to ultimate rates of 5drugs for the Chesapeake Postretirement Plan; and 610.50 percent respectively, byfor the year 2009.FPU Medical Plan. A one percentageone-percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $250,000$708,000 as of January 1, 2007,2010, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 20072009 by approximately $15,000.$30,000. A one percentageone-percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $207,000$594,000 as of January 1, 2007,2010, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 20072009 by approximately $13,000. The measurement dates were December 31, 2006 and 2005, respectively.$24,000.

Estimated Future Benefit Payments
In 2010, we expect to contribute $450,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $88,000 to the Chesapeake SERP. We also expect to contribute $115,000 and $144,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2010. The schedule below shows the estimated future benefit payments for each of the years 2007 through 2011 and the aggregate of the next five years for each of theour plans previously described.described:
                     
  Chesapeake  FPU      Chesapeake  FPU 
  Pension  Pension  Chesapeake  Postretirement  Medical 
(in thousands) Plan(1)  Plan(1)  SERP(2)  Plan(2)  Plan(2)(3) 
2010 $763  $2,176  $88  $115  $144 
2011  429   2,308   797   113   158 
2012  1,228   2,452   84   123   181 
2013  484   2,617   82   127   176 
2014  502   2,747   80   137   196 
Years 2015 through 2019  3,649   14,914   634   781   1,215 
(1)The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
(2)Benefit payments are expected to be paid out of the general funds of the Company.
(3)These amounts are shown net of estimated Medicare Part-D reimbursements of $10,000, $11,000, $11,000, $12,000 and $13,000 for the years 2010 to 2014 and $78,000 for years 2015 through 2019.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 95

  
Defined Benefit Pension Plan (1)
 
Executive Excess Defined Benefit Pension Plan (2)
 
Other Post-Retirement Benefits (2)
 
2007 $721,575 $88,096 $180,205 
2008  713,699  86,868  182,977 
2009  1,447,370  85,513  185,059 
2010  898,179  84,026  204,870 
2011  460,335  82,411  194,448 
Years 2012 through 2016  4,714,092  758,013  1,010,982 
           
(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
 
(2) Benefit payments are expected to be paid out of the general funds of the Company.
 

Retirement Savings Plan
We sponsor two 401(k) retirement savings plans and one non-qualified supplemental employee retirement savings plan.
The Company sponsors aChesapeake’s 401(k) Retirement Savings Plan, which provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions of up to 15 percent of eligible base compensation, subject to Internal Revenue Service limitations. These participants were eligible for the enhanced matching described below effective January 1, 2005.

Effective January 1, 1999, the Company began offering an enhanced 401(k) Planplan is offered to all neweligible employees, as well as existingexcept for those FPU employees, that electedwho have the opportunity to no longer participate in the Defined Benefit Plan. The Company makesFPU’s 401(k) plan. We make matching contributions on a basis of up to six percent of each employee'sChesapeake employee’s eligible pre-tax compensation for the year, except for all of the Company’s employees, except the employees forof our Advanced Information Services segment.advanced information services subsidiary, as further explained below. The match is between 100 percent and 200 percent of the employee’s contribution (up to six percent), based on a combination of the employee’s age and years of service. The first 100 percent of the funds areis matched with Chesapeake common stock. Thestock; the remaining match is invested in the Company’sChesapeake’s 401(k) Plan according to each employee’s election options.
- Page 70 -
Notes to Employees are automatically enrolled at a two percent contribution, with the Consolidated Financial Statements

option of opting out, and are eligible for the company match after three months of continuing service, with vesting of 20 percent per year.
Effective July 1, 2006, the matchingour contribution made on behalf of Advanced Information Services segmentthe advanced information services subsidiary employees, is a 50 percent matching contribution, on up to six percent of theeach employee’s annual compensation.compensation contributed to the plan. The matching contribution is funded in Chesapeake common stock. The Planplan was also amended at the same time to enable it to receive discretionary profit-sharing contributions in the form of employee pre-tax deferrals. The extent to which the Advanced Information Services segmentadvanced information services subsidiary has any dollars available for profit-sharing is dependent upon the extent to which the segment’s actual earnings exceed budgeted earnings. Any profit-sharing dollars made available to employees can be deferred into the Planplan and/or paid out in the form of a bonus.

On December 1, 2001, the Company converted the 401(k) fund holding Chesapeake stock to an Employee Stock Ownership Plan (“ESOP”).

Effective January 1, 1999, the Companywe began offering a non-qualified supplemental employee retirement savings plan open(“401(k) SERP”) to Companyour executives over a specific income threshold. Participants receive a cash onlycash-only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the twenty-one mutual funds available for investment. These same funds are available for investment of employee contributions within Chesapeake’s 401(k) plan. All obligations arising under the Retirement Savings Plan.401(k) SERP are payable from our general assets, although we have established a Rabbi Trust for the 401(k) SERP. As discussed further in Note G — “Investments,” to the Consolidated Financial Statements, the assets held in the Rabbi Trust included a fair value of $1.9 million and $1.4 million at December 31, 2009 and 2008, respectively, related to the 401(k) SERP. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.

We continue to maintain a separate 401(k) retirement savings plan for FPU. FPU’s 401(k) plan provides a matching contribution of 50 percent of an employee’s pre-tax contributions, up to six percent of the employee’s salary, for a maximum company contribution of up to three percent. Beginning in 2007, for non-union employees the plan provides a company match of 100 percent for the first two percent of an employee’s contribution, and a match of 50 percent for the next four percent of an employee’s contribution, for a total company match of up to four percent. Employees are automatically enrolled at three percent contribution, with the option of opting out, and are eligible for the company match after six months of continuous service, with vesting of 100 percent after three years of continuous service.
The Company’sOur contributions to the 401(k) plans totaled $1,612,000, $1,681,000$1.6 million (including a $10,000 contribution made to FPU’s 401(k) plan after the merger), $1.6 million, and $1,497,000$1.5 million for the years ended December 31, 2006, 2005,2009, 2008, and 2004,2007, respectively. As of December 31, 2006,2009, there are 77,47910,281 shares reserved to fund future contributions to Chesapeake’s 401(k) plan.
Deferred Compensation Plan
On December 7, 2006, the Retirement SavingsBoard of Directors approved the Chesapeake Utilities Corporation Deferred Compensation Plan (“Deferred Compensation Plan”), as amended, effective January 1, 2007. The Deferred Compensation Plan is a non-qualified, deferred compensation arrangement under which certain executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainer and fees. At December 31, 2009, the Deferred Compensation Plan consisted solely of shares of common stock related to the deferral of executive performance shares and directors’ stock retainers.
Page 96     Chesapeake Utilities Corporation 2009 Form 10-K

Participants in the Deferred Compensation Plan are able to elect the payment of benefits to begin on a specified future date after the election is made in the form of a lump sum or annual installments. Deferrals of executive cash bonuses and directors’ cash retainers and fees are paid in cash. All deferrals of executive performance shares and directors’ stock retainers are paid in shares of our common stock, except that cash is be paid in lieu of fractional shares.
We established a Rabbi Trust in connection with the Deferred Compensation Plan.

The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the Balance Sheet and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Deferred Compensation Plan totaled $739,000 and $1.5 million at December 31, 2009 and 2008, respectively.
L.N. Share-Based Compensation Plans
Effective January 1, 2006,Our non-employee directors and key employees are awarded share-based awards through the Company adopted SFAS No. 123R, “Share-Based Payment,”Company’s Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), respectively. We record these share-based awards as compensation costs over the respective service period for which establishes accountingservices are received in exchange for an award of equity instruments exchanged for employee services. Prior to January 1, 2006, the Company accounted for share-basedor equity-based compensation. The compensation to employees in accordance with Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The Company also followed the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” Commencing January 1, 2006, the Company elected to adopt the modified prospective method as provided by SFAS No. 123R and, accordingly, financial statement amounts for the prior periods presented have not been retrospectively adjusted to reflectcost is based on the fair value of expensing stock-based compensation.


Stock Optionsthe grant on the date it was awarded.
The Companytable below presents the amounts included in net income related to share-based compensation expense, for the restricted stock awards issued under the DSCP and the PIP for the years ended December 31, 2009, 2008 and 2007.
             
For the Years Ended December 31, 2009  2008  2007 
(in thousands)            
Directors Stock Compensation Plan $191  $180  $181 
Performance Incentive Plan  1,115   640   809 
          
Total compensation expense  1,306   820   990 
Less: tax benefit  523   327   386 
          
Share-Based Compensation amounts included in net income $783  $493  $604 
          
Stock Options
We did not have any stock options outstanding at December 31, 20062009, 2008 or December 31, 2005,2007, nor were any stock options issued during 2006.2009, 2008 and 2007.

DirectorDirectors Stock Compensation Plan (“DSCP”)
Under the Company’s DSCP, each of our non-employee director receivesdirectors received in 2009 an annual retainer of 600650 shares of common stock and an additional 150 shares of common stock for servicesserving as a committee chairman, subject to adjustmentchairperson. For 2009, the Corporate Governance and Compensation Committee Chairperson each received 150 additional shares of common stock and the Audit Committee Chairperson received 250 additional shares of common stock. Shares granted under the DSCP are issued in future years consistent with the termsadvance of the DSCP. Shares issued under the DSCPdirectors’ service period; therefore, these shares are fully vested as of the grant date. We record a prepaid expense as of the date of the grant. At the date of grant the Company records a prepaid expense equal to the fair value of the shares issued and amortizesamortize the expense equally over thea service period of one year. Compensation
Chesapeake Utilities Corporation 2009 Form 10-K     Page 97

A summary of stock activity under the DSCP is presented below:
         
     Weighted Average 
  Number of  Grant Date 
  Shares  Fair Value 
Outstanding — December 31, 2007  —   — 
       
Granted
  6,161  $29.43 
Vested  6,161  $29.43 
Forfeited  —   — 
       
Outstanding — December 31, 2008  —   — 
       
Granted(1)
  7,174  $29.83 
Vested  7,174  $29.83 
Forfeited  —   — 
       
Outstanding — December 31, 2009  —   — 
       
(1)On October 28, 2009, the Company added two new members to its Board of Directors; each new board member was awarded 337 shares of common stock.
We recorded compensation expense recorded byof $191,000, $180,000 and $181,000 related to DSCP awards for the Company relating toyears ended December 31, 2009, 2008 and 2007, respectively.
The weighted-average grant-date fair value of DSCP awards granted during 2009 and 2008 was $29.83 and $29.43, per share, respectively. The intrinsic values of the DSCP awards was $165,000 and $140,000 for 2006 and 2005, respectively.
- Page 71 -
Notesare equal to the Consolidated Financial Statements

A summaryfair market value of restricted stock activity forthese awards on the DSCP asdate of grant. At December 31, 20062009, there was $64,000 of unrecognized compensation expense related to DSCP awards that is presented below:


  
Number of Restricted Shares
 
Weighted Average Grant Date Fair Value
 
Outstanding — December 31, 2005 -   
Issued — May 2, 2006  5,850 $30.02 
Vested  5,850    
Outstanding — September 30, 2006  -    

expected to be recognized over the first four months of 2010.
As of December 31, 2006,2009, there were 63,30044,115 shares reserved for issuance under the terms of the Company’s Director’s Stock Compensation Plan.DSCP.

Performance Incentive PlansPlan (“PIP”)
The Company’sOur Compensation Committee of the Board of Directors is authorized to grant to key employees of the Company the rightsright to receive awards of shares of the Company’sour common stock, contingent upon the achievement of established performance goals. These goals consist of annual or three-year performance targets. The awards are made pursuant to the Company’s Performance Incentive Plan, subject to certain post-vesting transfer restrictions, and arerestrictions.
In 2007, the Board of Directors granted each executive officer equity incentive awards, which entitled each to earn shares of common stock to the extent that we achieved pre-established performance goals at the end of a one-year performance period. In 2008, we adopted multi-year performance plans to be used in lieu of the first quarter of each year and are issuedone-year awards. Similar to the one-year plans, the multi-year plans provide incentives based upon the performance achieved inachievement of long-term goals, development and the previous fiscal year or three-year award period. In the first quarters of 2006 and 2005, the Company issued 23,666 and 10,130 shares, respectively, to key employees as PIP stock awards for eachsuccess of the preceding fiscal years. Please note that 2005 concluded the three-year performance periodCompany. The long-term goals have both market-based and these awards were issued in the first quarter of 2006 and included in the 23,666 stock awards.

performance-based conditions or targets.
The Company accrues an expense each month of the fiscal year representing an estimate of the value of the stock awardsshares granted for the current fiscal year. This accrual process matches the compensation expense with the employees’ service period rather than recognizing the expense on the issue date, which occurs in the first quarter of the subsequent year. The shares issued under the PIP in 2007 are fully vested, and the fair value of each share is equal to the estimated market price of the Company’sour common stock on the date issued. Compensation expense recordedof the grant. The shares granted under the 2008 and 2009 long-term plans have not vested as of December 31, 2009, and the fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

Page 98     Chesapeake Utilities Corporation 2009 Form 10-K

A summary of stock activity under the PIP is presented below:
         
  Number of  Weighted Average 
  Shares  Fair Value 
Outstanding — December 31, 2007  33,760  $29.90 
       
Granted  94,200  $27.84 
Vested  31,094  $29.90 
Fortfeited  —   — 
Expired  2,666  $29.90 
       
Outstanding — December 31, 2008  94,200  $27.84 
       
Granted  28,875  $29.19 
Vested  —   — 
Fortfeited  —   — 
Expired  —   — 
       
Outstanding — December 31, 2009  123,075  $28.15 
       
In 2009, no shares under the PIP vested. In 2008, we withheld shares with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives receiving the net shares. The total number of shares withheld (12,511) for 2008 was based on the value of the PIP shares on their vesting date, determined by the Companyaverage of the high and low of our stock price. No payments for the employee’s tax obligations were made to taxing authorities in 20062009 as no shares vested during this period. Total payments for the employees’ tax obligations to the taxing authorities were approximately $383,000 in 2008.
We recorded compensation expense of $1.1 million, $640,000 and 2005 relating$809,000 related to the PIP was $544,000for the years ended December 31, 2009, 2008, and $721,000,2007, respectively.

A summaryThe weighted-average grant-date fair value of restricted stock activity forPIP awards granted during 2009, 2008 and 2007 was $29.19, $27.84 and $29.90, per share respectively. The intrinsic value of the PIP awards was $2.1 million and $1.1 million for 2006 is presented below:


  
Number of Restricted Shares
 
Weighted Average Grant Date Fair Value
 
Outstanding — December 31, 2005 -   
Issued — February 23, 2006  23,666 $30.3999 
Vested  23,666    
Outstanding — September 30, 2006  -    

2009 and 2008, respectively. The intrinsic value of the 2007 awards was equal to the fair market value of these awards on the date of grant.
As of December 31, 2006,2009, there were 293,480371,293 shares reserved for issuance under the terms of the Company’s Performance Incentive Plan.

our PIP.
M.O. Environmental Commitments and Contingencies
Chesapeake isWe are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Companyus to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.

In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former gas manufacturing plant site located in Dover, Delaware. Chesapeake is also currently participatingWe have participated in the investigation, assessment or remediation of two additionaland have certain exposures at six former gas manufacturing plantMGP sites. Those sites are located in Salisbury, Maryland, and Florida. The Company has accrued liabilities for the three sites referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven, Coal Gas sites. The Company hasKey West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”)MDE regarding a fourthseventh former gas manufacturing plantMGP site located in Cambridge, Maryland. The following provides details of each site.
- Page 72 -
Notes to the Consolidated Financial Statements

Dover Gas Light Site
The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action obligationKey West, Pensacola, Sanford and West Palm Beach sites are related to this siteFPU, for which we assumed in the merger any existing and relieves future contingencies.

Chesapeake from liabilityUtilities Corporation 2009 Form 10-K     Page 99

As of December 31, 2009, we had recorded $531,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of the future costs associated with those sites. We had recorded approximately $1.7 million in regulatory and other assets for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to the EPA is received that indicates the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the United States in all liability settlements.

The Company has reviewedrecovery of environmental costs from Chesapeake’s customers through its remediation costs incurred to date for the Dover Gas Light site and has concluded that all costs incurred have been paid. The Company does not expect any future environmental expenditure for this site. Through December 31, 2006, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through December 2006 from other parties or throughapproved rates. As of December 31, 2006, a regulatory liability of2009, we had recorded approximately $294,500, representing$12.3 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily from the over-recovery portionWest Palm Beach site, which represents our estimate of the clean-upfuture costs associated with those sites. FPU is approved to recover its environmental costs up to $14.0 million from insurance and customers through rates. Approximately $5.7 million of FPU’s expected environmental costs has been recorded. recovered from insurance and customers through rates as of December 31, 2009. We also had recorded approximately $6.6 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
The over-recovery is temporary and will be refunded by the Company to customers in future rates.following discussion provides details on each site.

Salisbury, Maryland
Salisbury Town Gas Light Site
In cooperation with the MDE, the Company hasWe have completed remediation of the Salisbury Town Gas Lightthis site located in Salisbury, Maryland, where it was determined that a former manufactured gas plant hadMGP caused localized ground-water contamination. During 1996, the Companywe completed construction and beganof an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake has been reportingWe have reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently decommission the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well thatwhich is being maintained for continued product monitoring and recovery. In November 2002, Chesapeake submitted a letter to the MDE requestingWe have requested and are awaiting a No Further Action determination. The Company has been in discussions with the MDE regarding such request and is awaiting a determination from the MDE.

Through December 31, 2006, the Company has2009, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount,site and do not expect to incur any additional costs. We have recovered approximately $1.8$2.1 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover through its rates charged to customers the remaining $1.1 millionand have $783,000 of the incurred environmental remediation costs.clean-up costs not yet recovered.

Winter Haven, Coal Gas SiteFlorida
The Winter Haven Coal Gas site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven site with the FDEP. The Work Plan described the Company’s proposalPursuant to undertake an AS/SVE pilot study to evaluate the site. After discussionsa Consent Order entered into with the FDEP, the Company filed a modified Work Plan, the description of the scope of workwe are obligated to completeassess and remediate environmental impacts to the site assessment activities andresulting from the former operation of a report describing a limited sediment investigation performed in 1997.MGP on the site. In December 1998, the2001, FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEPrequiring construction and operation of a bio-sparge/soil vapor extraction (“BS/SVE”) treatment system to address the contamination of the subsurface soil and ground-water ingroundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. The Fourteenth Semi-Annual RAP Implementation Status Report was submitted to FDEP approvedin January 2010. The groundwater sampling results through October 2009 show, in general, a reduction in contaminant concentrations over prior years, although the RAP on May 4, 2001. Constructionrate of reduction has declined recently. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. At present, we predict that remedial action objectives may be met for the area being treated by the BS/SVE treatment system in approximately three years.
The BS/SVE treatment system does not address impacted soils in the southwest corner of the AS/SVE system was completed in the fourth quarter of 2002site. We are currently completing additional soil and the system remains fully operational.
- Page 73 -
Notes to the Consolidated Financial Statements

The Company has accrued a liability of $212,000 as of December 31, 2006groundwater sampling at this location for the Winter Haven Coal Gas site. Through December 31, 2006, the Company has incurred approximately $1.7 millionpurpose of environmental costs associated withdesigning a remedy for this site. At December 31, 2006, the Company had collected $90,000 through rates in excess of costs incurred. A regulatory asset of approximately $122,000, representing the uncollected portion of the estimated clean-up costs, has also been recorded. The Company expectssite. Following the completion of this field work, we will submit a soil excavation plan to recover the remaining costs through rates.FDEP for its review and approval.

The FDEP has indicated that the Companywe may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the Winter Haven site. Based on studies performed to date, the Company objectswe object to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’sadversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by the FDEP maycould cost as much as $1$1.0 million. GivenWe believe that corrective measures for the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitudesediments are unwarrantednot warranted and plansintend to oppose any requirementsrequirement that itwe undertake corrective measures in the offshore sediments. Chesapeake anticipates that it will be several years before this issue is resolved. At this time, the Company hasWe have not recorded a liability for sediment remediation. The outcomeremediation, as the final resolution of this matter cannot be predicted at this time.

Page 100     Chesapeake Utilities Corporation 2009 Form 10-K


Through December 31, 2009, we have incurred and paid approximately $1.4 million for this site and estimates an additional cost of $531,000 in the future, which has been accrued. We have recovered through rates $1.1 million of the costs and continue to expect that the remaining $885,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.
OtherKey West, Florida
FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. FDEP has not required any further work at the site as of this time. Our portion of the consulting/remediation costs which may be incurred at this site is projected to be $93,000.
Pensacola, Florida
FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by Gulf Power Corporation (“Gulf Power”). Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional/engineering controls. The group, consisting of Gulf Power, City of Pensacola, FDOT and FPU, is proceeding with preparation of the necessary documentation to submit the NFA justification. Consulting/remediation costs are projected to be $14,000.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, an MGP which was operated by several other entities before FPU acquired the property. FPU was never an owner/operator of the MGP. In late September 2006, the U.S. Environmental Protection Agency (“EPA”) sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the City of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The total estimated remediation costs for this site were projected at the time by EPA to be approximately $12.9 million.
In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of December 31, 2009, FPU paid $300,000 to the Sanford Group escrow account for its share of funding requirements, and in January 2010, the Company paid the remaining $350,000 of this funding requirement.
The Sanford Group, EPA and the U.S. Department of Justice entered into a Consent Decree in March 2008, which was entered by the federal court in Orlando on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.
Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have/will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third party claims.
As of December 31, 2009, FPU’s remaining share of remediation expenses, including attorney’s fees and costs, is estimated to be $401,000, of which $350,000 was paid to the Sanford Group escrow account in January 2010. However, the Company is unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has committed to fund under the Third Participation Agreement.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 101

West Palm Beach, Florida
We are currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida upon which FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the FDEP. On April 30, 2009, FDEP issued a remedial action order, which it subsequently withdrew. In response to the order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s demands for additional information.
The feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, management believes that consulting/remediation costs to address the impacts now characterized at the West Palm Beach site will range from $7.4 million to $18.9 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone, monitored natural attenuation of dissolved impacts in groundwater, or some combination of these remedies.
Negotiations between FPU and the FDEP on a final remedy for the site continue. Prior to the conclusion of those negotiations, we are unable to determine, to a reasonable degree of certainty, the full extent or cost of remedial action that may be required. As of December 31, 2009, and subject to the limitations described above, we estimate the remediation expenses, including attorneys’ fees and costs, will range from approximately $7.8 million to $19.4 million for this site.
We continue to expect that all costs related to these activities will be recoverable from customers through rates.
Other
We are in discussions with the MDE regarding a gas manufacturing plantan MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.

N.P. Other Commitments and Contingencies
Rates and Other Regulatory Activities
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; ESNG, our natural gas transmission operation, is subject to regulation by the FERC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida PSC as separate entities.

Page 102     Chesapeake Utilities Corporation 2009 Form 10-K

Delaware. On September 2, 2008, our Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On September 16, 2008, the Delaware PSC authorized the Delaware division to implement the GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division was required by its natural gas tariff to file a revised application if its projected over-collection of gas costs for the determination period of November 2007 through October 2008 exceeded four and one-half percent (4.5 percent) of total firm gas costs. As a result of a significant decrease in the cost of natural gas, the Delaware division, on January 8, 2009, filed with the Delaware PSC a supplemental GSR Application, seeking approval to change its GSR, effective February 1, 2009. On January 29, 2009, the Delaware PSC authorized the Delaware division to implement the revised GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, the Delaware PSC, our Delaware division and the Division of the Public Advocate. Pursuant to the settlement agreement, our Delaware division, commencing in November 2009, adjusted the margin-sharing mechanism related to its Asset Management Agreement to reduce its proportionate share of such margin. We anticipate a net margin reduction of approximately $8,000 per year from this change.
As part of the settlement, the parties also agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates, and the amount actually received by the Delaware division for capacity released to PESCO. We have estimated that, exclusive of any interest, the amount that would have to be refunded if the Hearing Examiner’s recommendation is approved without modification by the Delaware PSC is approximately $700,000 as of December 31, 2009. The Hearing Examiner has also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles regarding all future capacity releases by the Delaware division to PESCO, if any. Accordingly, if the Hearing Examiner’s recommendation is approved without modification by the Delaware PSC and if the Delaware division temporarily released any capacity to PESCO below the maximum tariff rates, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. We disagree with the Hearing Examiner’s recommendations and filed exceptions to those recommendations on February 5, 2010. The hearing on our exceptions took place before the Delaware PSC on February 18, 2010, but no ruling was made by the Delaware PSC. We anticipate a ruling by the Delaware PSC in March 2010. We believe that the Delaware division has been following proper procedures for capacity release established by the FERC and based on a previous settlement approved by the Delaware PSC and therefore, we have not recorded a liability for this contingency.
On December 2, 2008, our Delaware division filed two applications with the Delaware PSC, requesting approval for a Town of Milton Franchise Fee Rider and a City of Seaford Franchise Fee Rider. These Riders allow the division to recover from natural gas customers located within the Town of Milford or the City of Seaford a proportionate share of the franchise fees paid by the division. The Delaware PSC granted approval of both Franchise Fee Riders on January 29, 2009.
On September 4, 2009, our Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2009. On October 6, 2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC on this application in the second quarter of 2010.
On December 17, 2009, our Delaware division filed an application with the Delaware PSC, requesting approval for an Individual Contract Rate for service to be rendered to a potential large industrial customer. On or about October 2, 2009, the Delaware division entered into a negotiated gas service agreement with a potential customer pursuant to which the Delaware division would provide transportation, balancing, and gas delivery service to the customer’s facilities in Delaware. The Delaware division’s obligations under the agreement are subject to several conditions, including the condition that the agreement be approved by the Delaware PSC. The Delaware division and the potential customer consider the specific terms and conditions of the agreement to be confidential and proprietary. The Delaware division anticipates a final decision by the Delaware PSC on this application in the first quarter of 2010.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 103

Maryland. On December 16, 2008, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by our Maryland division during the 12 months ended September 30, 2008. No issues were raised at the hearing, and on December 19, 2008, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings, which became a final Order of the Maryland PSC on January 21, 2009.
On April 24, 2009, the Maryland PSC issued an Order defining utilities’ payment plan parameters and termination procedures that would increase the likelihood that customers could pay their past due amounts to avoid termination of natural gas service. This Order requires our Maryland division to: (a) provide customers in writing, prior to issuing a termination notice, certain details about their past due balance and information about available payment plans, and (b) continue to offer flexible and tailored payment plans. The Maryland division has implemented procedures to comply with this Order.
On December 1, 2009, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Company’s Maryland division during the 12 months ended September 30, 2009. No issues were raised at the hearing, and on December 9, 2009, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. On January 8, 2010, the Maryland PSC issued an Order affirming the Hearing Examiner’s decisions in the matter, but made certain clarifications and corrections to the text of the proposed Order issued by the Hearing Examiner.
Florida. On July 14, 2009, Chesapeake’s Florida division filed with the Florida PSC its petition for a rate increase and request for interim rate relief. In the application, the Florida division sought approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represented an average base rate increase, excluding fuel costs, of approximately 25 percent for the Florida division’s customers; (c) implementation or modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the pending merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida division’s interim rate request, subject to refund, applicable to all meters read on or after September 1, 2009. On December 15, 2009, the Florida PSC: (a) approved a $2,536,307 permanent rate increase (86 percent of the requested amount) applicable to all meters read on or after January 14, 2010; (b) determined that there is no refund required of the interim rate increase; and (c) ordered Chesapeake’s Florida division and FPU’s natural gas distribution operations to submit data no later than April 29, 2011 (which is 18 months after the merger) that details all known benefits, synergies and cost savings that have resulted from the merger).
Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural gas rate increase of $7,969,000 for FPU’s natural gas distribution operation, which represents approximately 80 percent of the requested base rate increase of $9,917,690 filed by FPU in the fourth quarter of 2008. The Florida PSC had approved an annual interim rate increase of $984,054 on February 10, 2009 and approved the permanent rate increase of $8,496,230 in an order issued on May 5, 2009, with the new rates to be effective beginning on June 4, 2009. On June 17, 2009, however, the Office of Public Counsel entered a protest to the Florida PSC’s order and its final natural gas rate increase ruling, which protest required a full hearing to be held within eight months. Subsequent negotiations led to the settlement agreement between the Office of Public Counsel and FPU, which the Florida PSC approved on December 15, 2009. The rates authorized pursuant to the order approving the settlement agreement became effective on January 14, 2010 and in February 2010, FPU refunded to its natural gas customers approximately $290,000 representing revenues in excess of the amount provided by the settlement agreement that had been billed to customers from June 2009 through January 14, 2010.

Page 104     Chesapeake Utilities Corporation 2009 Form 10-K

On September 1, 2009, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Recovery Clause, which seeks final approval of its 2008 fuel-related revenues and expenses and new fuel rates for 2010. On January 4, 2010, the Florida PSC approved the proposed 2010 fuel rates, effective on or after January 1, 2010.
On September 11, 2009, Chesapeake’s Florida division and FPU’s natural gas distribution operation separately filed their respective annual Energy Conservation Cost Recovery Clause, seeking final approval of their 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. On November 2, 2009, the Florida PSC approved the proposed 2010 conservation surcharge rates for both the Florida division and FPU, effective for meters read on or after January 1, 2010.
Also on September 11, 2009, FPU’s natural gas distribution operation filed its annual Purchased Gas Adjustment Clause, seeking final approval of its 2008 purchased gas-related revenues and expenses and new purchased gas adjustment cap rate for 2010. On November 4, 2009, the Florida PSC approved the proposed 2010 purchased gas adjustment cap, effective on or after January 1, 2010.
The City of Marianna Commissioners voted on July 7, 2009 to enter into a new ten year franchise agreement with FPU effective February 1, 2010. The agreement provides that new interruptible and time of use rates shall become available for certain customers prior to February 2011 or, at the option of the City, the franchise agreement could be voided nine months after that date. The new franchise agreement contains a provision for the City to purchase the Marianna portion of FPU’s electric system. Should FPU fail to make available the new rates, and if the franchise agreement is then voided by the City and the City elects to purchase the Marianna portion of the distribution system, it would require the city to pay FPU severance/reintegration costs, the fair market value for the system, and an initial investment in the infrastructure to operate this limited facility. If the City purchased the electric system, FPU would have a gain in the year of the disposition; but, ongoing financial results would be negatively impacted from the loss of the Marianna area from its electric operations.
ESNG. The following are regulatory activities involving FERC Orders applicable to ESNG and the expansions of ESNG’s transmission system:
System Expansion 2006 — 2008. In accordance with the requirements in the FERC’s Order Issuing Certificate for the 2006 — 2008 System Expansion, ESNG had until June 13, 2009, to construct the remaining facilities that were authorized in the project filing. On February 3, 2009, ESNG requested authorization to modify the previously required completion date and to commence construction of the facilities, which provide for the remaining 6,957 Mcfs of additional firm service capacity previously approved by the FERC. On March 13, 2009, the FERC granted the requested authorization. On October 30, 2009, ESNG received approval from the FERC to commence services in November 2009 on this remaining portion of the 2006-2008 system expansion, which will permit ESNG to realize an additional annualized gross margin of approximately $1.0 million.
Energylink Expansion Project (“E3 Project”). In 2006, ESNG proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with ESNG’s existing facilities in Sussex County, Delaware.
In April 2009, ESNG terminated the E3 Project and initiated billing to recover specified project costs in accordance with the terms of the precedent agreements executed with the two participating customers, one of which is Chesapeake, through its Delaware and Maryland divisions. These billings will reimburse ESNG for the $3.17 million of costs incurred in connection with the E3 Project, including the cost of capital, over a period of 20 years.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 105

Prior Notice Request. On November 25, 2009 ESNG filed a prior notice request, proposing to construct, own and operate new mainline facilities to deliver additional firm entitlements of 1,594 Mcfs per day of natural gas to Chesapeake’s Delaware division. The FERC published notice of this filing on December 7, 2009 and with no protest during the 60-day period following the notice, the proposed activity became effective on February 6, 2010. ESNG expects to realize an annualized margin of approximately $343,000 upon its completion of the facilities and implementation of the new service.
FERC Order Nos. 712 and 712-A. In June and November 2008, the FERC issued Order Nos. 712 and 712-A, which revised its regulations regarding interstate natural gas pipeline capacity release programs. The Orders: (a) remove the rate ceiling on capacity release transactions of one year or less; (b) facilitate the use of asset management arrangements for certain capacity releases; and (c) facilitate state-approved retail open access programs. The Orders required interstate gas pipeline companies to remove any inconsistent tariff provisions within 180 days of the effective date of the rule. On February 2, 2009, ESNG submitted revised tariff sheets to comply with the requirements set forth in the Orders. Amended tariff sheets were subsequently filed on February 26, 2009, which made minor clarifications and corrections. On March 27, 2009, ESNG received FERC approval of these amended tariff sheets with an effective date of March 1, 2009. Implementation of these amended tariff provisions will have no financial impact on ESNG.
ESNG also had developments in the following FERC matters:
On April 30, 2009, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC. ESNG reported in this filing that it refunded to its eligible firm customers a total of $245,500, inclusive of interest, in the second quarter of 2009.
On May 29, 2009, ESNG submitted its annual Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge filings to the FERC. In these filings, ESNG proposed to implement an FRP rate of 0.12 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund a total of $294,540, inclusive of interest, to its eligible customers in the second quarter of 2009 by netting its over-recovered fuel cost against its under-recovered cash-out cost. The FERC approved these proposals, and ESNG refunded $294,540 to customers in July 2009.
On June 1, 2009, ESNG submitted revised tariff sheets to comply with FERC Order No. 587-T, which adopted Version 1.8 of the North American Energy Standards Board Wholesale Gas Quadrant’s standards. FERC found this rule necessary to increase the efficiency of the pipeline grid, make pipelines’ electronic communications more secure and provide consistency with the mandate that agencies provide for electronic disclosure of information. ESNG’s revised tariff sheets were approved on August 11, 2009, by the FERC, which will have no financial impact on ESNG.
On August 21, 2009, ESNG filed revised tariff sheets to reflect an increase in the Annual Charge Adjustment (“ACA”) surcharge from $0.0017 per Dt to $0.0019 per Dt. The ACA surcharge is designed to recover applicable program costs incurred by the FERC. The tariff sheets were accepted as proposed and were made effective on October 1, 2009. As the ACA is passed-through to ESNG’s customers, there will be no financial impact on ESNG.
On December 11, 2009, ESNG filed revised tariff sheets to reflect a new section 42, Consolidation of Service Agreements, to the General Terms and Conditions of its FERC Gas Tariff. Section 42 states that shippers may, at their option and subject to certain conditions, consolidate multiple service agreements under a rate schedule into a new service agreement(s) under that rate schedule. The tariff sheets were accepted by the FERC on January 7, 2010, as proposed and were made effective January 15, 2010. As this new section allows for consolidation of existing service agreements only, there will be no financial impact on ESNG.

Page 106     Chesapeake Utilities Corporation 2009 Form 10-K

Natural Gas, Electric and Propane Supply
The Company’sOur natural gas, electric and propane distribution operations have entered into contractual commitments forto purchase gas and electricity from various suppliers. The contracts have various expiration dates. In November 2004, the CompanyMarch 2009, we renewed itsour contract with an energy marketing and risk management company to manage a portion of the Company’sour natural gas transportation and storage capacity. TheThis contract expires on March 31, 2007.2012.

PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire in May 2010.
FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the result of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 and (b) fixed charge coverage greater than 1.5. If either of the ratios is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s agreement with Gulf requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operation interest coverage (minimum of 2 to 1) and (b) total debt to total capital (maximum of 0.65 to 1). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of action taken or proposed to be taken to be compliant. Failure to comply with the ratios specified in the Gulf agreement could result in FPU providing an irrevocable letter of credit. FPU was in compliance with these requirements as of December 31, 2009.
Corporate Guarantees
The Company hasWe have issued corporate guarantees to certain vendors of itsour subsidiaries, the largest portion of which are for the Company’s propane wholesale marketing subsidiary and its Florida natural gas supply and management subsidiary, and Delmarva propane distributionmarketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements.Statements when incurred. The aggregate amount guaranteed at December 31, 2006 totaled $21.42009 was $22.7 million, with the guarantees expiring on various dates in 2007.

2010.
In addition to the corporate guarantees, the Company haswe have issued a letter of credit to itsthe Company’s primary insurance company for $775,000,$725,000, which expires on MayAugust 31, 2007.2010. The letter of credit is provided as security for claims amounts to satisfy the deductibles under our various insurance policies. There have been no draws on the Company’s policies. The currentthis letter of credit wasas of December 31, 2009. We do not anticipate that this letter of credit will be drawn upon by the counterparty and we expect that it will be renewed duringto the second quarter of 2006 whenextent necessary in the insurance policies were renewed.future.

Other
Other
The Company isWe are involved in certain legal actions and claims arising in the normal course of business. The Company isWe are also involved in certain legal proceedings and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on theour consolidated financial position, results of operations or cash flows of the Company.flows.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 107


- Page 74 -
Notes to the Consolidated Financial Statements

O.Q. Quarterly Financial Data (Unaudited) (Unaudited)
In the opinion of the Company, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods. Due to the seasonal nature of the Company’s business, there are substantial variations in operations reported on a quarterly basis.

                 
For the Quarters Ended March 31  June 30  September 30  December 31 
(in thousands, except per share amounts)                
                 
2009(1)
                
Operating Revenue $104,479  $40,834  $31,758  $91,715 
Operating Income $15,966  $2,856  $2,257  $12,658 
Net Income (Loss) $8,593  $806  $308  $6,190 
Earnings (Loss) per share:                
Basic $1.26  $0.12  $0.04  $0.71 
Diluted $1.24  $0.12  $0.04  $0.71 
                 
2008
                
Operating Revenue $100,274  $69,057  $49,698  $72,415 
Operating Income $14,041  $4,329  $1,170  $8,938 
Net Income (Loss) $7,574  $1,819  $(198) $4,412 
Earnings (Loss) per share:                
Basic $1.11  $0.27  $(0.03) $0.65 
Diluted $1.10  $0.27  $(0.03) $0.64 
(1)The quarter ended December 31, 2009 includes the results from the merger with FPU, which became effective on October 28, 2009.
(2)The sum of the four quarters does not equal the total year due to rounding.

For the Quarters Ended
 
March 31
 
June 30
 
September 30
 
December 31
 
          
2006
         
Operating Revenue 
$
90,950,672
 
$
44,303,752
 
$
35,141,531
 
$
60,804,636
 
Operating Income 
$
11,437,228
 
$
3,205,368
 
$
162,137
 
$
8,126,578
 
Net Income (Loss) 
$
6,096,416
 
$
1,132,509
  
($656,579
)
$
3,934,179
 
Earnings per share:             
Basic 
$
1.03
 
$
0.19
  
($0.11
)
$
0.63
 
Diluted 
$
1.01
 
$
0.19
  
($0.11
)
$
0.62
 
              
2005
             
Operating Revenue $77,845,248 $42,220,377 $35,155,121 $74,408,990 
Operating Income (Loss) $11,504,343 $2,324,945  ($99,149)$7,800,360 
Net Income (Loss) $6,232,796 $795,924  ($693,774)$4,132,668 
Earnings per share:             
Basic $1.08 $0.14  ($0.12)$0.70 
Diluted $1.05 $0.14  ($0.12)$0.69 


- Page 75 -

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
None
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rule 13a-15(e) and 15d - 15(e)15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2006.2009. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2006.2009.

Changes in Internal Controls
DuringOther than the Chesapeake and FPU merger discussed below, there has been no change in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2006, there was no change in the Company’s internal control over financial reporting2009, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting
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 Management’s Report on Internal Control Over Financial Reporting in Item 8 “Financialunder the heading “Notes to the Consolidated Financial Statements — Note B, Acquisitions and Supplemental Data.”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.

Page 108     Chesapeake Utilities Corporation 2009 Form 10-K


CEO and CFO Certifications
The Company’s Chief Executive Officer as well as the Senior Vice President and Chief Financial Officer have filed with the Securities and Exchange CommissionSEC the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006.2009. In addition, on May 26, 2006June 1, 2009 the Company’s CEOChief Executive Officer certified to the New York Stock ExchangeNYSE that he was not aware of any violation by the Company of the NYSE corporate governance listing standards.
Management’s Report on Internal Control Over Financial Reporting
The report of management required under this Item 9A is contained in Item 8 of this Form 10-K under the caption “Management’s Report on Internal Control over Financial Reporting.”
Our independent auditors, ParenteBeard LLC, have audited and issued their report on effectiveness of our internal control over financial reporting. That report appears in the following page.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 109

Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
We have audited Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Chesapeake Utilities Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of 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.
As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, the Company completed a merger with Florida Public Utilities Company (“FPU”) in 2009. As permitted by the Securities and Exchange Commission, management excluded the non-integrated FPU operations from its assessment of internal control over financial reporting as of December 31, 2009. Non-integrated FPU operations constituted approximately 30 percent of total assets (excluding goodwill and other intangible assets) as of December 31, 2009, and 10 percent of operating revenue for the year then ended. Our audit of internal control over financial reporting of Chesapeake Utilities Corporation as of December 31, 2009, did not include an evaluation of the internal controls over financial reporting of the non-integrated operations of FPU.
In our opinion, Chesapeake Utilities Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 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 of Chesapeake Utilities Corporation, and our report dated March 8, 2010 expressed an unqualified opinion.
/s/ ParenteBeard LLC
ParenteBeard LLC
Malvern, Pennsylvania
March 8, 2010

Page 110     Chesapeake Utilities Corporation 2009 Form 10-K



Item 9B. Other Information.
None
The Company filed a Current Report on Form 8-K, dated November 29, 2006, discussing the Compensation Committee’s (the “Committee”) actions on that date, including their approval of the compensation arrangements relating to the executive officers of the Company for 2007.

On November 29, 2006, the Committee approved awards under the Company’s Performance Incentive Plan to John R. Schimkaitis, President and Chief Executive Officer and Michael P. McMasters, Senior Vice President and Chief Financial Officer. According to the terms of the awards, each executive officer is entitled to earn up to a specified number of shares of the Company’s common stock (“Contingent Performance Shares”) depending on the extent to which pre-established performance goals (the “Performance Goals”) are achieved during the year ended December 31, 2007 (the “2007 Award Year”).

On November 29, 2006, the Compensation Committee also approved awards under the Company’s Performance Incentive Plan to (i) Stephen C. Thompson, Senior Vice President, and (ii) S. Robert Zola, President of Sharp Energy, Inc., a Company subsidiary, for the three-year period ending December 31, 2008. For a performance period beginning January 1, 2007 and ending December 31, 2007, each executive officer is entitled to earn, in the form of shares of restricted stock, up to 30 percent of the annual award of Contingent Performance Shares if the Company achieves certain Performance Goals. The second component consists of performance awards pursuant to which the remaining 70 percent of the annual award of Contingent Performance Shares will be earned, if certain Performance Goals for the three-year period ending December 31, 2008 for each of the respective business units for which they are individually responsible, are achieved.

- Page 76 -
Part III

Item 10. Directors, Executive Officers of the Registrant and Corporate Governance.Governanace.
The information required by this Item is incorporated herein by reference to the portions of the Proxy Statement, captioned “Proposal I - Election“Election of Directors (Proposal 1),” “Information Regarding the Board ofConcerning Nominees and Continuing Directors, and Nominees,” “Corporate Governance, Practices and Stockholder Communications - Nomination of Directors,” “Committees of the Board -— Audit Committee” and “Section 16(a) Beneficial Ownership Reporting Compliance”Compliance,” to be filed not later than March 31, 20072010, in connection with the Company’s Annual Meeting to be held on or about May 2, 2007.

5, 2010.
The information required by this Item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Part I of this Form 10-Kreport following Item 4, as Item 4A, under the caption “Executive Officers of the Registrant.Company.”

The Company has adopted a Code of Ethics for Financial Officers, which applies to its principal executive officer, president, principal financial officer, principal accounting officer or controller, or persons performing similar functions. The information set forth under Item 1 hereof concerning the Code of Ethics for Financial Officers is incorporated herein by reference.filed herewith.

Item 11. Executive Compensation.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement, captioned “Director Compensation,” “Executive Compensation” and “Compensation Discussion and Analysis” in the Proxy Statement to be filed not later than March 31, 2007,2010, in connection with the Company’s Annual Meeting to be held on or about May 2, 2007.5, 2010.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement, captioned “Beneficial“Security Ownership of Chesapeake’s Securities”Certain Beneficial Owners and Management” to be filed not later than March 31, 20072010, in connection with the Company’s Annual Meeting to be held on or about May 2, 2007.5, 2010.


-

Chesapeake Utilities Corporation 2009 Form 10-K     Page 77 -111


The following table sets forth information, as of December 31, 2006,2009, with respect to compensation plans of Chesapeake and its subsidiaries, under which shares of Chesapeake common stock are authorized for issuance:

(c)
Number of securities
(a)(b)remaining available for future
Number of securities toWeighted-averageissuance under equity
be issued upon exerciseexercise pricecompensation plans
of outstanding options,of outstanding options,(excluding securities
warrants, and rightswarrants, and rightsreflected in column (a))
Equity compensation plans approved by security holders——439,258(1)
Equity compensation plans not approved by security holders———
Total——439,258
(1)Includes 371,293 shares under the 2005 Performance Incentive Plan, 44,115 shares available under the 2005 Directors Stock Compensation Plan, and 23,850 shares available under the 2005 Employee Stock Awards Plan.

  (a) (b) (c)
  Number of securities to be issued upon exercise of outstanding options, warrants and rights  Weighted average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders  0 
 (1)
  
N/A
 381,431  (2) 
Equity compensation plans not approved by security holders  0  (3)  N/A 0   
Total  0      381,481   
             
(1) All options to purchase shares under the 1992 Performance Incentive Plan, as amended, were exercised as of 12/31/05.
 
(2) Includes 293,481 shares under the 2005 Performance Incentive Plan, 63,300 shares available under the 2005 Directors Stock Compensation Plan, and 24,650 shares available under the 2005 Employee Stock Awards Plan.
 
(3) All warrants were exercised in 2006.
 

Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement captioned, “Corporate Governance,” 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.
None

Item 14. Principal Accounting Fees and Services.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement, captioned “Fees and Services of PricewaterhouseCoopers LLP”Independent Registered Public Accounting Firm,” to be filed not later than March 31, 2007,2010, in connection with the Company’s Annual Meeting to be held on or about May 2, 2007.5, 2010.

Page 112     Chesapeake Utilities Corporation 2009 Form 10-K


- Page 78 -


Part IV

Item 15. Exhibits, Financial Statement Schedules.
(a)The following documents are filed as part of this report:
1.Financial Statements:
·  (a)Report
The following documents are filed as part of Independent Registered Public Accounting Firmthis report:
· Consolidated Statements of Income for each of the three years ended December 31, 2006, 2005 and 20041.
Financial Statements:
Report of Independent Registered Public Accounting Firm;
Consolidated Statements of Income for each of the three years ended December 31, 2009, 2008, and 2007;
Consolidated Balance Sheets at December 31, 2009 and December 31, 2008;
Consolidated Statements of Cash Flows for each of the three years ended December 31, 2009, 2008, and 2007;
Consolidated Statements of Stockholders’ Equity for each of the three years ended December 31, 2009, 2008, and 2007; and
Notes to the Consolidated Financial Statements.
· Consolidated Balance Sheets at December 31, 2006 and December 31, 20052.
Financial Statement Schedules:
·  Consolidated Statements of Cash Flows for each of the three years ended December 31, 2006, 2005 and 2004
·  Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2006, 2005 and 2004
·  Consolidated Statements of Comprehensive Income for each of the three years ended December 31, 2006, 2005 and 2004
·  Consolidated Statements of Income Taxes for each of the three years ended December 31, 2006, 2005 and 2004
·  Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm;
2.
Schedule I — Parent Company Condensed Financial Statement Schedule — Statements; and
Schedule II -— Valuation and Qualifying AccountsAccounts.

All other schedules are omitted, because they are not required, are inapplicable, or the information is otherwise shown in the financial statements or notes thereto.
3.Exhibits
· 3.
Exhibits
•Exhibit 11.1Underwriting Agreement entered into by Chesapeake Utilities Corporation and Robert W. Baird & Co. Incorporated and A.G. Edwards & Sons, Inc., on November 15, 2007, relating to the sale and issuance of 600,300 shares of the Company’sChesapeake’s common stock, is incorporated herein by reference to Exhibit 1.1 of the Company’sour Current Report on Form 8-K, filed November 16, 2007, File No. 001-11590.
· 
•Exhibit 2.1Agreement and Plan of Merger between Chesapeake Utilities Corporation and Florida Public Utilities Company dated April 17, 2009, is incorporated herein by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed April 20, 2009, File No. 001-11590.
•Exhibit 3.1AmendedRestated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of the Company’sour Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590.
· 
•Exhibit 3.2Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective February 24, 2005, isDecember 11, 2008, are incorporated herein by reference to Exhibit 3 of the Company’s AnnualCurrent Report on Form 10-K for the year ended8-K, filed December 31, 2004,16, 2008, File No. 001-11590.
· 
•Exhibit 4.1Form of Indenture between the CompanyChesapeake and Boatmen’s Trust Company, Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of the Company’sour Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 113

· 
•Exhibit 4.2Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593.
- Page 79 -
· Exhibit 4.3     Note Purchase Agreement, entered into by the Company on October 2, 1995, pursuant to which the CompanyChesapeake privately placed $10 million of its 6.91% Senior Notes, due in 2010, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request.
· 
•Exhibit 4.4     4.3Note Purchase Agreement, entered into by the CompanyChesapeake on December 15, 1997, pursuant to which the CompanyChesapeake privately placed $10 million of its 6.85% Senior Notes due in 2012, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request.
· 
•Exhibit 4.5     4.4Note Purchase Agreement entered into by the CompanyChesapeake on December 27, 2000, pursuant to which the CompanyChesapeake privately placed $20 million of its 7.83% Senior Notes, due in 2015, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request.
· 
•Exhibit 4.6     4.5Note Agreement entered into by the CompanyChesapeake on October 31, 2002, pursuant to which the CompanyChesapeake privately placed $30 million of its 6.64% Senior Notes, due in 2017, is incorporated herein by reference to Exhibit 2 of the Company’sour Current Report on Form 8-K, filed November 6, 2002, File No. 001-11590.
· 
•Exhibit 4.7     4.6Note Agreement entered into by the CompanyChesapeake on October 18, 2005, pursuant to which the Company,Chesapeake, on October 12, 2006, privately placed $20 million of its 5.5% Senior Notes, due in 2020, with Prudential Investment Management, Inc., is incorporated herein by reference to Exhibit 4.1 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2005, File No. 001-11590.
· 
•Exhibit 4.7Note Agreement entered into by Chesapeake on October 31, 2008, pursuant to which Chesapeake, on October 31, 2008, privately placed $30 million of its 5.93% Senior Notes, due in 2023, with General American Life Insurance Company and New England Life Insurance Company, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. We hereby agree to furnish a copy of that agreement to the SEC upon request.
•Exhibit 4.8Form of Senior Debt Trust Indenture between Chesapeake Utilities Corporation and the trustee for the debt securities is incorporated herein by reference to Exhibit 4.3.1 of the Company’sour Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.
· 
•Exhibit 4.9Form of Subordinated Debt Trust Indenture between Chesapeake Utilities Corporation and the trustee for the debt securities is incorporated herein by reference to Exhibit 4.3.2 of the Company’sour Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.
· 
•Exhibit 4.10Form of debt securities is incorporated herein by reference to Exhibit 4.4 of the Company’sour Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.
· 
•Exhibit 5.1     4.11OpinionForm of Baker & Hostetler LLPIndenture of Mortgage and Deed of Trust between Florida Public Utilities Company and the trustee, dated September 1, 1942 for the First Mortgage Bonds, is incorporated herein by reference to Exhibit 5.17-A of theFlorida Public Utilities Company’s Registration StatementNo. 2-6087.
•Exhibit 4.12Fourteenth Supplemental Indenture entered into by Florida Public Utilities Company on Form S-3, Reg. No. 333-135602, dated July 5, 2006.
· Exhibit 5.2     OpinionSeptember 1, 2001, pursuant to which Florida Public Utilities Company, on September 1, 2001, privately placed $15,000,000 of Baker & Hostetler LLPits 6.85% First Mortgage Bonds, is incorporated herein by reference to Exhibit 5.14(b) of theFlorida Public Utilities Company’s Registration StatementAnnual Report on Form S-3A, Reg.10-K for the year ended December 31, 2001, File No. 333-135602,001-10608.
•Exhibit 4.13Fifteenth Supplemental Indenture entered into by Florida Public Utilities Company on November 1, 2001, pursuant to which Florida Public Utilities Company, on November 1, 2001, privately placed $14,000,000 of its 4.90% First Mortgage Bonds, is incorporated herein by reference to Exhibit 4(c) of Florida Public Utilities Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-10608

Page 114     Chesapeake Utilities Corporation 2009 Form 10-K

•Exhibit 4.14Twelfth Supplemental Indenture entered into by Florida Public Utilities on May 1, 1988, pursuant to which Florida Public Utilities Company, on May 1, 1988, privately placed $10,000,000 and $5,000,000 of its 9.57% First Mortgage Bonds and 10.03% First Mortgage Bonds, respectively, are incorporated herein by reference to Exhibit 4 to Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1988.
•Exhibit 4.15Thirteenth Supplemental Indenture entered into by Florida Public Utilities Company on June 1, 1992, pursuant to which Florida Public Utilities, on May 1, 1992, privately placed $8,000,000 of its 9.08% First Mortgage Bonds, is incorporated herein by reference to Exhibit 4 to Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1992.
•Exhibit 10.1*Chesapeake Utilities Corporation Cash Bonus Incentive Plan, dated November 6, 2006.January 1, 2005, is incorporated herein by reference to Exhibit 10.3 of our Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.
· 
•Exhibit 10.1*     10.2*Non-Employee DirectorChesapeake Utilities Corporation Directors Stock Compensation Arrangements,Plan, adopted in 2005, is incorporated herein by reference to our Proxy Statement dated March 28, 2005, in connection with our Annual Meeting held on May 5, 2005, File No. 001-11590.
•Exhibit 10.3*Chesapeake Utilities Corporation Employee Stock Award Plan, adopted in 2005, is incorporated herein by reference to our Proxy Statement dated March 28, 2005, in connection with our Annual Meeting held on May 5, 2005, File No. 001-11590.
•Exhibit 10.4*Chesapeake Utilities Corporation Performance Incentive Plan, adopted in 2005, is incorporated herein by reference to our Proxy Statement dated March 28, 2005, in connection with our Annual Meeting held on May 5, 2005, File No. 001-11590.
•Exhibit 10.5*Deferred Compensation Program, amended and restated as of January 1, 2009, is incorporated herein by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004,2008, File No. 001-11590.
· Exhibit 10.2*     Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 2005, is incorporated herein by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.
· Exhibit 10.3*     •Chesapeake Utilities Corporation Directors Stock Compensation Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.
- Page 80 -
· Exhibit 10.4*     Chesapeake Utilities Corporation Employee Stock Award Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.
· Exhibit 10.5*     Chesapeake Utilities Corporation Performance Incentive Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.
· Exhibit 10.6*Deferred Compensation Program (as amended and restated as of December 7, 2006) is incorporated herein by reference to Exhibit 10 of the Company’s Current Report on Form 8-K, filed December 13, 2006, File No. 001-11590.
· Exhibit 10.7*     Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.incorporated herein by reference to Exhibit 10.7 of our Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.
· 
•Exhibit 10.7*Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and S. Robert Zola, is incorporated herein by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
•Exhibit 10.8*Executive Employment Agreement dated December 29, 2006,31, 2009, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 7, 2010, File No. 001-11590.
•Exhibit 10.9*Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is incorporated herein by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 7, 2010, File No. 001-11590.
•Exhibit 10.10*Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed herewith.January 7, 2010, File No. 001-11590.
· 
•Exhibit 10.9*     10.11*Executive Employment Agreement dated December 29, 2006,31, 2009, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed herewith.January 7, 2010, File No. 001-11590.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 115

· 
•Exhibit 10.10*     10.12*Executive Employment Agreement dated December 29, 2006,31, 2009, by and between Chesapeake Utilities Corporation and Joseph Cummiskey, is incorporated herein by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K, filed January 7, 2010, File No. 001-11590.
•Exhibit 10.13*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.11 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
•Exhibit 10.14*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.12 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
•Exhibit 10.15*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.incorporated herein by reference to Exhibit 10.13 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
· 
•Exhibit 10.11*     10.16*Executive EmploymentPerformance Share Agreement dated December 29, 2006,January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis,Michael P. McMasters, is filed herewith.incorporated herein by reference to Exhibit 10.14 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
· 
•Exhibit 10.12*     10.17*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.15 of our Annual Report on Form 10-K for the year ended December 15, 2006,31, 2007, File No. 001-11590.
•Exhibit 10.18*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.16 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
•Exhibit 10.19*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.17 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
•Exhibit 10.20*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.18 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
•Exhibit 10.21*Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.incorporated herein by reference to Exhibit 10.19 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

Page 116     Chesapeake Utilities Corporation 2009 Form 10-K

· 
•Exhibit 10.13*     10.22*Performance Share Agreement dated DecemberJanuary 23, 2006,2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson,S. Robert Zola, is filed herewith.incorporated herein by reference to Exhibit 10.20 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
· 
•Exhibit 10.14*     10.23*Form of Performance Share Agreement dated December 27, 2006,effective January 7, 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Michael P. McMasters, Beth W. Cooper and Stephen C. Thompson, is filed herewith.incorporated herein by reference to Exhibit 10.26 on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
· 
•Exhibit 10.15*     10.24*Form of Performance Share Agreement dated December 29, 2006,effective January 6, 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, and Joseph Cummiskey is filed herewith.
· 
•Exhibit 10.16*     10.25*Performance Share Agreement dated December 29, 2006,January 20, 2010 for the period 2010 to 2011, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis,Joseph Cummiskey is filed herewith.
•Exhibit 10.26*Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.28 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
•Exhibit 10.27*Chesapeake Utilities Corporation Supplemental Executive Retirement Savings Plan, as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.29 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
•Exhibit 10.28*Amended and Restated Electric Service Contract between Florida Public Utilities Company and JEA dated November 6, 2008, is incorporated herein by reference to Exhibit 10.1 of Florida Public Utilities Company’s Current Report on Form 8-K, filed on November 6, 2008, File No. 001-10908.
•Exhibit 10.29*Networking Operating Agreement between Florida Public Utilities Company and Southern Company Services, Inc. dated December 27, 2007 and amended on June 3, 2008, is incorporated herein by reference to Exhibit 10.3 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2008, File No. 001-10608.
•Exhibit 10.30*Network Integration Transmission Service Agreement between Florida Public Utilities Company and Southern Company Services, Inc. dated December 27, 2007 and amended on June 3, 2008, is incorporated herein by reference to Exhibit 10.4 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2008, File No. 001-10608.
•Exhibit 10.31*Form of Service Agreement for Firm Transportation Service between Florida Public Utilities Company and Florida Gas Transmission Company, LLC dated November 1, 2007 for the period November 2007 to February 2016 (Contract No. 107033), is incorporated herein by reference to Exhibit 10.1 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608.
•Exhibit 10.32*Form of Service Agreement for Firm Transportation Service between Florida Public Utilities Company and Florida Gas Transmission Company, LLC dated November 1, 2007 for the period November 2007 to March 2022 (Contract No. 107034), is incorporated herein by reference to Exhibit 10.2 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 117

· 
•Exhibit 10.33*Form of Service Agreement for Firm Transportation Service between Florida Public Utilities Company and Florida Gas Transmission Company, LLC dated November 1, 2007 for the period November 2007 to February 2022 (Contract No. 107035), is incorporated herein by reference to Exhibit 10.3 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608.
•Exhibit 12Computation of Ratio of Earning to Fixed Charges is filed herewith.
· 
•Exhibit 14     14.1Code of Ethics for Financial Officers is filed herewith.
· 
•Exhibit 14.2Business Code of Ethics and Conduct is filed herewith.
•Exhibit 21Subsidiaries of the Registrant is filed herewith.
· 
•Exhibit 23.1Consent of Independent Registered Public Accounting Firm is incorporated herein by reference to Exhibit 23.1 to the Company’s Registration Statement on Form S-3, Reg. No. 333-135602, dated July 5, 2006.
· Exhibit 23.2     Consent of Independent Registered Public Accounting Firm is incorporated herein by reference to Exhibit 23.1 to the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.
· Exhibit 23.3     Consent of Baker & Hostetler LLP (included in Exhibit 5.1).
- Page 81 -
· Exhibit 23.4     Consent of Baker & Hostetler LLP (included in Exhibit 5.2).
· Exhibit 23.5     Consent of Independent Registered Public Accounting Firm, filed herewith.
· Exhibit 24     Power of Attorney is incorporated herein by reference to Exhibit 24.1 of the Company’s Registration Statement on Form S-3, Reg. No. 333-135602, dated July 5, 2006.
· •Exhibit 31.1Certificate of Chief Executive OfficeOfficer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d-14(a), dated March 13, 2007,8, 2010, is filed herewith.
· 
•Exhibit 31.2Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d-14(a), dated March 13, 2007,8, 2010, is filed herewith.
· 
•Exhibit 32.1Certificate of Chief Executive OfficeOfficer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 13, 2007,8, 2010, is filed herewith.
· 
•Exhibit 32.2Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 13, 2007,8, 2010, is filed herewith.
*
*Management contract or compensatory plan or agreement.

Page 118     Chesapeake Utilities Corporation 2009 Form 10-K




- Page 82 -

Signatures

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

Chesapeake Utilities Corporation

By: /s/ John R. Schimkaitis
John R. Schimkaitis
President and Chief Executive Officer
Date: March 13, 2007

Chesapeake Utilities Corporation
By:  /s/ John R. Schimkaitis  
John R. Schimkaitis 
Vice Chairman and Chief Executive Officer
Date: March 8, 2010 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


/s/ Ralph J. Adkins
/s/ John R. Schimkaitis
Ralph J. Adkins, Chairman of the BoardJohn R. Schimkaitis, President,
and DirectorChief Executive Officer and Director
Date: February 21, 2007Date: March 13, 2007
  
/s/ Michael P. McMastersRalph J. Adkins
Ralph J. Adkins,
Chairman of the Board and Director
/s/ Richard BernsteinJohn R. Schimkaitis
Michael P. McMasters, Senior John R. Schimkaitis,
Vice PresidentChairman, Chief Executive Officer and Director		Richard Bernstein, Director
and Chief Financial OfficerDate: February 21, 2007
(Principal Financial and Accounting Officer) 
Date: February 24, 2010Date: March 13, 20078, 2010 
  
/s/ Eugene H. Bayard
/s/ Thomas J. Bresnan
Eugene H. Bayard, DirectorThomas J. Bresnan, Director
Date: February 21, 2007Date: March 13, 2007
  
/s/ Thomas P. HillBeth W. Cooper
Beth W. Cooper, Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
Date: March 8, 2010
/s/ Walter J. ColemanEugene H. Bayard
Eugene H. Bayard, Director
Date: February 24, 2010
Thomas P. Hill, DirectorWalter J. Coleman, Director
Date: February 21, 2007Date: February 21, 2007
  
/s/ J. Peter MartinRichard Bernstein
Richard Bernstein, Director
/s/ Joseph E. Moore, Esq.
Thomas J. Peter Martin,Bresnan
Thomas J. Bresnan, Director		Joseph E. Moore, Esq., Director
Date: February 21, 200724, 2010Date: February 21, 2007March 8, 2010
  
/s/ Calvert A. Morgan,Thomas P. Hill, Jr.
Thomas P. Hill, Jr., Director
 
Calvert A. Morgan, Jr.,/s/ Dennis S. Hudson, III
Dennis S. Hudson, III, Director		 
Date: February 21, 200724, 2010Date: February 24, 2010
/s/ Paul L. Maddock, Jr.
Paul L. Maddock, Jr., Director
/s/ J. Peter Martin
J. Peter Martin, Director
Date: February 24, 2010Date: February 24, 2010
/s/ Michael p. Mcmasters
Michael P. McMasters, President, Chief Operating Officer and Director
Date: March 8, 2010
/s/ Joseph E. Moore, Esq
Joseph E. Moore, Esq., Director
Date: February 24, 2010
/s/ Calvert A. Morgan, Jr
Calvert A. Morgan, Jr., Director
/s/ Dianna F. Morgan
Dianna F. Morgan, Director
Date: February 24, 2010Date: February 24, 2010 

Chesapeake Utilities Corporation 2009 Form 10-K     Page 119



Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
- Page 83 -



Chesapeake Utilities Corporation and Subsidiaries
 
Schedule II
 
Valuation and Qualifying Accounts
 
            
    
Additions
     
For the Year Ended December 31,
 
Balance at Beginning of Year
 
Charged to Income
 
Other Accounts (1)
 
Deductions (2)
 
Balance at End of Year
 
Reserve Deducted From Related Assets
           
Reserve for Uncollectible Accounts
           
2006
 
$
861,378
 
$
381,424
 
$
65,519
  
($646,724
)
$
661,597
 
2005 $610,819 $632,644 $158,409  ($540,494)$861,378 
2004 $682,002 $505,595 $103,020  ($679,798)$610,819 
                 
                 
(1) Recoveries.
                
(2) Uncollectible accounts charged off.
                

Upon written request, Chesapeake will provide, free of charge, a copy of any ExhibitThe audit referred to in our report dated March 8, 2010 relating to the 2006 Annual Report onconsolidated financial statements of Chesapeake Utilities Corporation as of December 31, 2009 and 2008 and for each of the years in the three-year period ended December 31, 2009, which is contained in Item 8 of this Form 10-K notalso included the audits of the financial statement schedules listed in this document.Item 15(a) 2. These financial statement schedules are the responsibility of the Chesapeake Utilities Corporation’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.
In our opinion such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ ParenteBeard LLC
 
ParenteBeard LLC
Malvern, Pennsylvania
March 8, 2010

Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Balance Sheets
         
  December 31,  December 31, 
Assets 2009  2008 
(in thousands)        
         
Total property, plant and equipment $191,440  $185,416 
Less: Accumulated depreciation and amortization  (46,297)  (46,158)
Plus: Construction work in progress  1,338   408 
       
Net property, plant and equipment  146,481   139,666 
       
         
Investments
  1,959   1,601 
Investments in subsidiaries
  160,150   73,410 
       
         
Current Assets
        
Cash and cash equivalents  973   1,534 
Accounts receivable (less allowance for uncollectible accounts of $458 and $398, respectively)  9,356   11,848 
Accrued revenue  4,936   4,721 
Accounts receivable from affiliates  56,587   61,139 
Propane inventory, at average cost  624   648 
Other inventory, at average cost  971   983 
Regulatory assets  1,205   824 
Storage gas prepayments  6,144   9,492 
Income taxes receivable  822   3,547 
Deferred income taxes  1,909   1,743 
Prepaid expenses  3,047   1,974 
Other current assets  79   79 
       
Total current assets  86,653   98,532 
       
         
Deferred Charges and Other Assets
        
Long-term receivables  331   512 
Regulatory assets  3,610   2,060 
Other deferred charges  479   453 
       
Total deferred charges and other assets  4,420   3,025 
       
         
Total Assets
 $399,663  $316,234 
       
The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Balance Sheets
         
  December 31,  December 31, 
Capitalization and Liabilities 2009  2008 
(in thousands)        
         
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  (2,865)  (3,748)
Deferred compensation obligation  739   1,549 
Treasury stock  (739)  (1,549)
       
Total stockholders’ equity  209,440   123,073 
 
Long-term debt, net of current maturities  79,611   86,382 
       
Total capitalization  289,051   209,455 
       
         
Current Liabilities
        
Current portion of long-term debt  6,636   6,636 
Short-term borrowing  30,023   33,000 
Accounts payable  9,157   9,587 
Customer deposits and refunds  4,410   5,558 
Accrued interest  1,003   1,023 
Dividends payable  2,959   2,082 
Accrued compensation  2,450   1,994 
Regulatory liabilities  5,934   2,429 
Other accrued liabilities  1,647   1,602 
       
Total current liabilities  64,219   63,911 
       
         
Deferred Credits and Other Liabilities
        
Deferred income taxes  16,494   13,204 
Deferred investment tax credits  157   193 
Regulatory liabilities  695   598 
Environmental liabilities  531   511 
Other pension and benefit costs  5,674   6,914 
Accrued asset removal cost  18,248   17,740 
Other liabilities  4,594   3,708 
       
Total deferred credits and other liabilities  46,393   42,868 
       
         
Other commitments and contingencies        
         
Total Capitalization and Liabilities
 $399,663  $316,234 
       
The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Statements of Income
             
For the Years Ended December 31, 2009  2008  2007 
(in thousands)            
             
Operating Revenues
 $101,577  $103,733  $119,402 
             
Operating Expenses
            
Cost of sales  62,339   65,446   83,076 
Operations  18,487   16,039   16,454 
Transaction-related costs  1,478   1,153   — 
Maintenance  1,535   1,303   1,409 
Depreciation and amortization  4,194   3,918   4,032 
Other taxes  3,564   3,380   2,989 
          
Total operating expenses  91,597   91,239   107,960 
          
Operating Income
  9,980   12,494   11,442 
Income from equity investments  12,042   7,781   7,679 
Other income (loss), net of other expenses  (30)  (106)  220 
Interest charges  3,066   3,026   3,195 
          
Income Before Income Taxes
  18,926   17,143   16,146 
Income taxes  3,029   3,536   2,948 
          
Net Income
 $15,897  $13,607  $13,198 
          
The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed 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:            
Equity earnings in subsidiaries  (12,042)  (7,781)  (7,679)
Depreciation and amortization  4,190   3,918   4,268 
Depreciation and accretion included in other costs  1,773   1,389   1,646 
Deferred income taxes, net  2,821   5,147   (156)
Gain on sale of assets  —   —   (205)
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  8   11   7 
Changes in assets and liabilities:            
Sale (purchase) of investments  (146)  (201)  229 
Accounts receivable and accrued revenue  (16,770)  (3,016)  (2,315)
Propane inventory, storage gas and other inventory  3,383   (3,854)  1,427 
Regulatory assets  (1,825)  606   (526)
Prepaid expenses and other current assets  (1,050)  (516)  (179)
Other deferred charges  (72)  (8)  (61)
Long-term receivables  181   199   76 
Accounts payable and other accrued liabilities  9,832   3,323   (403)
Income taxes receivable  2,791   (3,113)  147 
Accrued interest  (20)  158   32 
Customer deposits and refunds  (1,147)  34   1,423 
Accrued compensation  352   377   326 
Regulatory liabilities  3,603   (2,379)  1,941 
Other liabilities  886   (23)  (151)
          
Net cash provided by operating activities  14,956   9,359   14,916 
          
             
Investing Activities
            
Property, plant and equipment expenditures  (12,615)  (16,328)  (15,464)
Proceeds from sale of assets  —   —   205 
Proceeds from investments  1,000   500   900 
Cash acquired in the merger, net of cash paid  (16)  —   — 
Environmental expenditures  (86)  (480)  (228)
          
Net cash used by investing activities  (11,717)  (16,308)  (14,587)
          
             
Financing Activities
            
Inter-company receivable (payable)  13,379   4,302   (4,331)
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  (6,637)  (7,637)  (7,637)
          
Net cash provided by (used in) financing activities  (3,800)  6,034   (589)
          
             
Net Decrease in Cash and Cash Equivalents
  (561)  (915)  (260)
Cash and Cash Equivalents — Beginning of Period
  1,534   2,449   2,709 
          
Cash and Cash Equivalents — End of Period
 $973  $1,534  $2,449 
          
The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Notes to Financial Information
These condensed financial statements represent the financial information of Chesapeake Utilities Corporation (parent company).
For information concerning Chesapeake’s debt obligations, see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note J, Long-term Debt, and Note K, Short-term Borrowing.”
For information concerning Chesapeake’s material contingencies and guarantees, see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note O, Environmental Commitments and Contingencies, and Note P, Other Commitments and Contingencies.”
Chesapeake’s wholly-owned subsidiaries are accounted for using the equity method of accounting.

Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts
                     
  Balance at  Additions        
  Beginning of  Charged to  Other      Balance at End 
For the Year Ended December 31, Year  Income  Accounts(1)  Deductions(2)  of Year 
Reserve Deducted From Related Assets Reserve for Uncollectible Accounts
                    
(In thousands)
                    
2009
 $1,159  $1,138  $616  $(1,304) $1,609 
2008 $952  $1,186  $241  $(1,220) $1,159 
2007 $662  $818  $26  $(554) $952 
(1)Recoveries.
(2)Uncollectible accounts charged off.