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, 20082009
Commission File Number: 001-11590
Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)
   
State of Delaware 51-0064146
   
(State or other jurisdiction of
incorporation or organization)		 (I.R.S. Employer
Identification No.)
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including zip code)
302-734-6799
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
   
Title of each class Name of each exchange on which registered
   
Common Stock — par value per share $.4867 New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:

8.25% Convertible Debentures Due 2014

(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso. Noþ.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso. Noþ.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ. Noo.
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.þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting companycompany” in Rule 12b-2 of the Exchange Act. (Check one):
       
Large accelerated filero Accelerated filerþ Non-accelerated filero Smaller Reporting Companyo
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso. Noþ.
The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2008,2009, 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 $168.8$223.5 million.
As of February 28, 2009, 6,833,0662010, 9,436,558 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 20092010 Annual Meeting of Stockholders are incorporated by reference in Part III.
 
 

 

 

 

CHESAPEAKE UTILITIES CORPORATION
FORMChesapeake Utilities Corporation

Form 10-K
YEAR ENDED DECEMBER 31, 20082009
TABLE OF CONTENTS
     
  Page 
Part I
  43 
     
Item 1. Business
  4 
     
Item 1A. Risk Factors
  1214 
     
Item 1B. Unresolved Staff Comments
  1923 
     
Item 2. Properties
  1923 
     
Item 3. Legal Proceedings
  2024 
     
Item 4. Submission of Matters to a Vote of Security Holders
  2024 
     
Item 4A. Executive Officers of the Registrant
  2025 
     
Part II
  2226 
     
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
  2226 
     
Item 6. Selected Financial Data
  2529 
     
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
  2933 
     
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
  5659 
     
Item 8. Financial Statements and Supplementary Data
  5659 
     
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
  99108 
     
Item 9A. Controls and Procedures
  99108 
     
Item 9B. Other Information
  101111 
     
Part III
  101111 
     
Item 10. Directors, Executive Officers of the Registrant and Corporate Governanace
  101111 
     
Item 11. Executive Compensation
  101111 
     
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
  101111 
     
Item 13. Certain Relationships and Related Transactions, and Director Independence
  102112 
     
Item 14. Principal Accounting Fees and Services
  102112 
     
Part IV
  103113 
     
Item 15. Exhibits, Financial Statement Schedules
  103113 
     
Signatures
  108119 
     
 Exhibit 3.210.24
 Exhibit 10.5
Exhibit 10.7
Exhibit 10.9
Exhibit 10.11
Exhibit 10.13
Exhibit 10.15
Exhibit 10.26
Exhibit 10.27
Exhibit 10.2810.25
 Exhibit 12
Exhibit 14.1
 Exhibit 14.2
 Exhibit 21
 Exhibit 23.1
Exhibit 23.2
 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
   
BravePoint
 BravePoint, Inc., a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake Utilities Corporation
Chesapeake
 The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
Company
 The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
ESNG
 Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake
FPU Florida Public Utilities Company, a new wholly-owned subsidiary of Chesapeake, effective October 28, 2009
OnSight
 Chesapeake OnSight Services, LLC, a wholly-owned subsidiary of Chesapeake
PESCO
 Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake
PIPECO
 Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake
Sharp Energy
 Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities Corporation
Sharpgas
Sharpgas, Inc., a wholly-ownedand Sharp’s subsidiary, of Sharp Energy,Sharpgas, Inc.
Skipjack
Skipjack, Inc., a wholly-owned subsidiary of Chesapeake Service Company, which is a wholly-owned subsidiary of Chesapeake Utilities Corporation
Tri-County
Tri-County Gas Co., Inc. a wholly-owned subsidiary of Sharp Energy
Xeron
 Xeron, Inc., a wholly-owned subsidiary of Chesapeake
Regulatory Agencies
   
APB
Accounting Principles Board
Delaware PSC
 Delaware Public Service Commission
DOT
 United States Department of Transportation
EPA
 United States Environmental Protection Agency
FASB
 Financial Accounting Standards Board
FERC
 Federal Energy Regulatory Commission
FDEP
 Florida Department of Environmental Protection
Florida PSC
 Florida Public Service Commission
IRS
 Internal Revenue Service
Maryland PSC
 Maryland Public Service Commission
MDE
 Maryland Department of the Environment
PSC Public Service Commission
SEC
 Securities and Exchange Commission
Chesapeake Utilities Corporation 2009 Form 10-K      Page 1

Other
   
AOCI
 Accumulated Other Comprehensive Income
AS/SVE
Air Sparging and Soil/Vapor Extraction
CGS
Community Gas Systems
Columbia
Columbia Gas Transmission Corporation
DSCP
 Directors Stock Compensation Plan
Dts
Dekatherms
E3 Project
ESNG Energylink Expansion Project
ER
Environmental rider
EITF
Financial Accounting Standards Board Emerging Issues Task Force
FIN
Financial Accounting Standards Board Interpretation Number
FSP
Financial Accounting Standards Board Staff Position
GAAP
Generally Accepted Accounting Principles
GSR
 Gas sales service rates
Chesapeake Utilities Corporation 2008 Form 10-K     Page 1

Gulf
Columbia Gulf Transmission Company
Gulfstream
Gulfstream Natural Gas System, LLC
HDD
 Heating degree-days
Mcf Thousand Cubic Feet
MMBtus
MWH		 One million (1,000,000) British Thermal UnitsMegawatt Hour
MGP Manufactured Gas Plant
NYSE
 New York Stock Exchange
PIP
 Performance Incentive Plan
S&P 500 Index
 Standard & Poor’s 500 Index
SFAS
 Statement of Financial Accounting Standards
Accounting Standards
   
EITF 03-6-1
ASC		 EITF 03-6-1, Determining Whether instruments Granted in Share-based Payment Transactions are Participating Securities
FASB Accounting Standards CodificationTM(Codification)
ASU FASB Accounting Standards Update
EITF 07-05
FSP		 EITF 07-05, Determining Whether an Instrument (of an Embedded Feature) is Indexed to an Entity’s Own Stock
EITF 08-03
EITF 08-03, Accounting for Maintenance Deposits Under Lease Arrangements
EITF 08-05
EITF 08-05, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement
FIN 39-1
FIN 39-1, a modification to FIN 39, Offsetting of Amounts Related to Certain Contracts
FIN 47
FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143
FIN 48
FIN 48, Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109
FSP APB 14-1
FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)
FSP 142-3
FSP 142-3, Determining the Useful Life of Intangible Assets
FSP 157-3
FSP 157-3, Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active
SFAS No. 71
Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of RegulationBoard Staff Position
GAAP 
SFAS No. 87
Statement of FinancialGenerally Accepted Accounting Standards No. 87, Employers’ Accounting for Pensions
SFAS No. 88
Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS No. 106
Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions
SFAS No. 109
Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS No. 112
Statement of Financial Accounting Standards No. 112, Employers’ Accounting for Postemployment Benefits
SFAS No. 115
Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS No. 123
Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation
SFAS No. 123R
Statement of Financial Accounting Standards No. 123R, Share-Based Payment
SFAS No. 128
Statement of Financial Accounting Standards No. 128, Earnings Per Share
SFAS No. 132R
Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS No. 133
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging ActivitiesPrinciples
Page 2      Chesapeake Utilities Corporation 20082009 Form 10-K

SFAS No. 141R
Statement of Financial Accounting Standards No. 141R, Business Combinations
SFAS No. 142
Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
SFAS No. 143
Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations
SFAS No. 157
Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS No. 158
Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of SFAS Nos. 87, 88, 106, and 132R
SFAS No. 159
Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS No. 115
SFAS No. 160
Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin 51
SFAS No. 161
Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133
SFAS No. 162
Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles
Chesapeake Utilities Corporation 2008 Form 10-K     Page 3

 

 

Part I
References in this document to “Chesapeake,” “the Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation and/or its wholly-owned subsidiaries, as appropriate.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,” and“would” or “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, 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.”statements:
•state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries (including deregulation);
•the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates;
•industrial, commercial and residential growth or contraction in our service territories;
•the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and ice storms;
•the timing and extent of changes in commodity prices and interest rates;
•general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control;
•changes in environmental and other laws and regulations to which we are subject;
•the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;
•declines in the market prices of equity securities and resultant cash funding requirements for our defined benefit pension plans;
•the creditworthiness of counterparties with which we are engaged in transactions;
•growth in opportunities for our business units;
•the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;
•the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
•conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;
•the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;
•the ability to manage and maintain key customer relationships;
•the ability to maintain key supply sources;
•the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses; and
•the effect of competition on our businesses.
Chesapeake Utilities Corporation 2009 Form 10-K      Page 3

Item 1. Business.
(a) GeneralOverview
Chesapeake isWe 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”).
Chesapeake is(b)Operating Segments
As a result of the merger with FPU, we changed our operating segments to better align with how the chief operating decision maker (our Chief Executive Officer) views the various operations of the Company. Our three operating segments are now composed of four operating segments:the following:
 • 
Natural Gas.Regulated Energy. The natural gasregulated energy segment includes regulated natural gas distribution, electric distribution and transmission operations and also a non-regulated natural gas marketing operation.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.
 • 
Propane.Unregulated Energy.The propaneunregulated energy segment includes non-regulatednatural gas marketing, propane distribution and propane wholesale marketing operations.operations, which are unregulated as to their rates and services.
 • 
Advanced Information Services.Other. 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.
•
Other.The other“Other” segment consists primarily of non-regulated operationsthe advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other Company subsidiaries.operations.
(b) Financial Information About Business Segments
Our natural gas segment accounts for approximately 91 percent of Chesapeake’s consolidated operating income and approximately 87 percent of the consolidated net property plant and equipment. The following table shows the size of each of our operating segments based on operating income and net property, plant and equipment.equipment:
                 
          Net Property, Plant 
(Thousands) Operating Income  & Equipment 
Natural Gas $25,846   91% $242,882   87%
Propane  1,586   6%  30,180   11%
Advanced information services  695   2%  915   <1%
Other & eliminations  352   1%  6,694   2%
             
Total $28,479   100% $280,671   100%
             
                 
          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%
             
Page 4     Chesapeake Utilities Corporation 2008 Form 10-K

Additional financial information by business segment is included in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note C.C, Segment Information.”
Page 4     Chesapeake Utilities Corporation 2009 Form 10-K

(c) Narrative Description of the Business(i)Regulated Energy
(i)(a) Natural Gas
Chesapeake’s natural gasOur regulated energy segment provides natural gas distribution transmission and marketing services for its customers. Chesapeake conducts its natural gas distribution operations under three divisions:in Delaware, Maryland and Florida, which are basedelectric distribution services in their respective service territories. These threeFlorida and natural gas transmission services in Delaware, Maryland, Pennsylvania and Florida.
Natural Gas Distribution
Our Delaware and Maryland natural gas distribution divisions serve approximately 65,19051,736 residential and commercial customers and 155 industrial customers in central and southern Delaware and Maryland’s Eastern Shore and parts of Florida. The Company’s natural gas transmission subsidiary, ESNG, operates a 379-mile interstate pipeline system that transports gas from various points in Pennsylvania to the Company’s Delaware and Maryland distribution divisions, as well as to other utilities and industrial customers in southern Pennsylvania, Delaware and on the Eastern Shore of Maryland. The Company, through its subsidiary, PESCO, also provides natural gas supply and supply management services in the States of Delaware, Florida and Maryland.
Natural Gas Distribution
Chesapeake distributes natural gas to residential, commercial and industrial customers in central and southern Delaware, the Salisbury and Cambridge areas on Maryland’s Eastern Shore, and parts of Florida. These activities are conducted through three utility divisions, one in Delaware, another in Maryland and a third in Florida.
Delaware and Maryland. Chesapeake’s Delaware and Maryland distribution divisions serve approximately 50,670 customers, of which approximately 50,490 are residential and commercial customers purchasing gas primarily for heating and cooking use. The remaining 180 customers are industrial.Shore. For the year 2008,ended December 31, 2009, operating revenues and deliveries by customer class for our Delaware and Maryland distribution divisions were as follow:follows:
                                
 Operating Revenues Deliveries  Operating Revenues Deliveries 
 (Thousands) (MMcf’s)  (in thousands) (Mcfs) 
Residential $47,994  53% 2,590,425  39% $51,309  58% 2,747,162  36%
Commercial 29,480  33% 2,312,644  34% 31,942  36% 2,693,724  35%
Industrial 2,130  2% 812,224  12% 3,696  4% 1,827,153  24%
                  
Subtotal 79,604  88% 5,715,293  85% 86,947  98% 7,268,039  95%
Interruptible 9,041  10% 1,035,540  15% 977  1% 373,825  5%
Other (1)
 1,934  2% — —  1,291  1% — — 
                  
Total $90,579  100% 6,750,833  100% $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.The Florida division distributes natural gas distribution division provides unbundled natural gas distribution services (the delivery of natural gas separated from the sale of the commodity) to approximately 13,37013,268 residential and 1,1501,176 commercial and industrial customers in the 14 Counties of Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Pasco, Suwannee, Liberty, Washington and Citrus.counties in Florida. For the year 2008,ended December 31, 2009, operating revenues and deliveries by customer class for our Florida distribution division were as follow:follows:
                                
 Operating Revenues Deliveries  Operating Revenues Deliveries 
 (Thousands) (MMcf’s)  (in thousands) (Mcfs) 
Residential $3,725  28% 321,077  2% $3,682  30% 318,420  2%
Commercial 3,108  24% 1,180,507  7% 3,043  25%�� 1,151,071  8%
Industrial 4,684  36% 14,527,786  91% 4,260  34% 13,271,503  90%
Other(1)
 1,637  12% —  0% 1,377  11% — — 
                  
Total $13,154  100% 16,029,370  100% $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 20082009 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 Transmission
ESNG owns and operates ana 384-mile interstate pipeline system that transports natural gas pipelinefrom various points in Pennsylvania to Chesapeake’s Delaware and provides open-access transportation services for affiliatedMaryland natural gas distribution divisions, as well as to other utilities and non-affiliated local distribution companiesindustrial customers in southern Pennsylvania, Delaware and other customers through an integrated gas pipeline system extending from southeastern Pennsylvania through Delaware to its terminus on the Eastern Shore of Maryland. ESNG also provides swing transportation service and contract storage services. For the year 2008,ended December 31, 2009, operating revenues and deliveries by customer class for ESNG were as follow:follows:
                                
 Operating Revenues Deliveries  Operating Revenues Deliveries 
 (Thousands) (MMcf’s)  (in thousands) (Mcfs) 
Local distribution companies $19,280  81% 9,720,864  44% $19,699  76% 9,941,436  38%
Industrial 3,523  15% 11,191,555  50% 4,907  19% 14,471,109  55%
Commercial 968  4% 1,299,878  6% 1,336  5% 1,809,970  7%
Other(1)
 5  <1% — —  35  0% — — 
                  
Subtotal 23,776  100% 22,212,297  100% 25,977  100% 26,222,515  100%
Less: affiliated local distribution companies 11,521  48% 5,978,996  27% (12,709)  (49)% (5,578,918)  (21)%
                  
Total non-affiliated $12,255  52% 16,233,301  73% $13,268  51% 20,643,597  79%
                  
   
(1) Operating revenues from “Other” sources isare from rental of gas properties.
DuringIn 2005, Chesapeakewe formed PIPECO to operate an intrastate pipeline to provide natural gas transportation services to industrial customers in the State of Florida natural gas transportation service as an intrastate pipeline. PIPECO did not have any activity in 2006. OnFlorida. In December 4, 2007, the Florida Public Service Commission (“Florida PSC”) approved PIPECO’s natural gas transmission pipeline tariff, which established its operating rules and regulations. In January 2009, PIPECO began marketing its services to potential industrial customers in 2008.
Natural Gas Marketing
PESCO competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers in the States of Delaware, Maryland, and Florida through competitively-priced contracts. PESCO does not own or operate anyproviding natural gas transmission or distribution assets. The gas that PESCO sells is deliveredservices to retail customersa customer for a period of 20 years at a fixed monthly charge, through affiliated and non-affiliated local distribution company systems and transmission pipelines. PESCO bills its customers through the billing services of the regulated utilities that deliver the gas, or directly, through its own billing capabilities.
an 8-mile pipeline located in Suwanee County, Florida, which PIPECO owns. For the year 2008, PESCO’s customers,ended December 31, 2009, PIPECO had $264,000 in operating revenues and deliveries were as follow:
                         
          Operating Revenues  Deliveries 
State Customers  (Thousands)  (Dts) 
Florida  1,922   99% $76,862   81%  6,275,717   79%
Delmarva  12   1%  18,552   19%  1,683,695   21%
                   
Total  1,934   100% $95,414   100%  7,959,412   100%
                   
under the contract.
Gas Supplies, Firm TransportationTransmission and Storage Capacity
The Company believesWe believe that the availability of gas supply and transportation to its Delaware, Maryland and Floridatransmission of natural gas distribution operations and to ESNG and PESCOelectricity is adequate under existing arrangements to meet the anticipated needs of their customers. The following discussion provides a summary of the gas supplies and pipeline transportation and storage capacities, stated in dekatherms (“Dts”), available to each of the Company’s natural gas operations.
Page 6     Chesapeake Utilities Corporation 2008 Form 10-KNatural Gas Distribution

The Company’sOur Delaware and Maryland natural gas distribution divisions have both firm and interruptible transportation service contracts with four interstate “open access” pipelines,pipeline companies, including ESNG.the ESNG pipeline. These divisions are directly interconnected with the ESNG pipeline, and have contracts with interstate pipelines upstream of ESNG. These interstate pipelines includeESNG, including Transcontinental Gas Pipe Line Corporation (“Transco”), Columbia Gas Transmission Corporation (“Columbia”) and Columbia Gulf Transmission Company (“Gulf”). The Transco and Columbia pipelines are directly interconnected with ESNG;the ESNG pipeline. The Gulf pipeline is directly interconnected with the Columbia pipeline and indirectly interconnected with ESNG.the ESNG pipeline. None of the upstream pipelines is owned or operated by an affiliate of the Company. The Delaware and Maryland divisions use their firm transportation supply resources to meet a significant percentage of their projected demand requirements. In order to meet the difference between firm supplyrequirements and firm demand, the divisionsthey purchase natural gas supplies 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 their interconnections with ESNG. TheThese divisions also have the capability to use propane-air peak-shaving to supplement or displace the spot market purchases.
Delaware.Chesapeake Utilities Corporation 2009 Form 10-K     Page 7

The following table shows the firm transportationtransmission and storage capacity that the Delaware divisionand Maryland divisions currently hashave under contract with ESNG and pipelines upstream of the ESNG pipeline, including the respective contract expiration dates.
           
  Firm transportation      
  capacity maximum  Firm storage capacity   
  peak-day daily  maximum peak-day   
Pipeline deliverability (Dts)  daily withdrawal (Dts)  Expiration
Transco  21,356   6,407  Various dates between 2012 and 2028
Columbia  3,460   8,224  Various dates between 2009 and 2020
Gulf  880   —  Expires in 2009
Eastern Shore  61,637   4,146  Various dates between 2009 and 2023
Delaware
           
  Firm transmission      
  capacity maximum  Firm storage   
  peak-day daily  capacity maximum   
  deliverability  peak-day daily   
Pipeline (Mcfs)  withdrawal (Mcfs)  Expiration
Transco  20,699   6,190  Various dates between 2010 and 2028
Columbia  17,836   7,946  Various dates between 2011 and 2020
Gulf  850   —  Expires in 2014
ESNG  63,482   4,006  Various dates between 2010 and 2024
Maryland
           
  Firm transmission      
  capacity maximum  Firm storage   
  peak-day daily  capacity maximum   
  deliverability  peak-day daily   
Pipeline (Mcfs)  withdrawal (Mcfs)  Expiration
Transco  5,921   2,373  Various dates between 2010 and 2012
Columbia  6,473   3,539  Various dates between 2011 and 2018
Gulf  570   —  Expires in 2014
ESNG  19,834   2,228  Various dates between 2010 and 2023
The Delaware divisionand Maryland divisions currently hashave contracts with several suppliers for the purchase of firm natural gas supply in the amount of its capacitytheir capacities on the Transco and Columbia pipelines. The Delaware divisionThey also hashave contracts for firm peaking gas supplies to be delivered to its systemtheir systems in order to meet the differential between their capacities on the Delaware division’s capacity on ESNG pipeline and capacitycapacities on pipelines upstream of ESNG. These supply contracts provide a maximum firm daily entitlement of 51,066 Dts,13,237 Mcfs and 2,029 Mcfs for the Delaware and Maryland divisions, respectively, delivered on the Transco, Columbia, and/or Gulf systems to ESNG for redelivery to the divisionthese divisions under firm transportationtransmission contracts. These gas supply contracts have various expiration dates, and quantities may vary from day-to-dayday to day and month-to-month.month to month.
Maryland.
The following table shows the firm transportation and storage capacity that the Maryland division currently has under contract with ESNG and pipelines upstream of ESNG, including the respective contract expiration dates.
           
  Firm transportation      
  capacity maximum  Firm storage capacity   
  peak-day daily  maximum peak-day   
Pipeline deliverability (Dts)  daily withdrawal (Dts)  Expiration
Trancso  5,866   2,456  Various dates between 2012 and 2013
Columbia  1,700   3,663  Various dates between 2014 and 2018
Gulf  590   —  Expires in 2009
Eastern Shore  20,528   2,306  Various dates between 2009 and 2023
Chesapeake Utilities Corporation 2008 Form 10-K     Page 7

The Maryland division currently has contracts with several suppliers for the purchase of firm natural gas supply in the amount of its capacity on the Transco and Columbia pipelines. The Maryland division also has contracts for firm peaking gas supplies to be delivered to its system in order to meet the differential between the Maryland division’s capacity on ESNG and capacity on pipelines upstream of ESNG. These supply contracts provide a maximum firm daily entitlement of 16,316 Dts, delivered on the Transco, Columbia, and/or Gulf systems to ESNG for redelivery to the division under firm transportation contracts. These gas supply contracts have various expiration dates, and quantities may vary from day-to-day and month-to-month.
Florida.
TheChesapeake’s Florida natural gas distribution division has firm transportationtransmission service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC.LLC (“Gulfstream”). Pursuant to a program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties,third-parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to Florida Gas Transmission CompanyFGT and Gulfstream, Natural Gas System, LLC. should any party that acquired the capacity through release fail to pay for the service.
Contracts by Chesapeake’s contractsFlorida natural gas distribution division with Florida Gas Transmission CompanyFGT include: (a) a contract, which expires inon July 31, 2010, for daily firm transportationtransmission capacity of 23,519 Dts22,901 Mcfs for the months of November through April, capacity of 20,123 Dts19,594 Mcfs for the months of May through September, and capacity of 22,105 Dts21,524 Mcfs for October; and (b) a contract for daily firm transportationtransmission capacity of 1,000 Dts974 Mcfs daily, which expires in 2015. Chesapeake’s contract with Gulfstream Naturalis for daily firm transmission capacity of 9,737 Mcfs and expires in 2022.
Page 8     Chesapeake Utilities Corporation 2009 Form 10-K

FPU has firm transmission service contracts with FGT and firm transportation contracts with Florida City Gas System, LLC. is(“FCG”) and Indiantown Gas Company (“IGC”). The additional contracts with FGT include (a) a contract which expires on July 2020, for daily firm transmission capacity of 26,500 Mcfs for the months of November through March, 22,411 Mcfs for the month of April, 9,211 Mcfs for the months of May through September and 9,314 Mcfs for the month of October; (b) a contract which expires in 2015 for daily firm transmission capacity of 10,286 Mcfs for the months of November through April and 4,360 Mcfs for the months of May through October; (c) a contract which expires in July 2020 for daily firm transmission capacity of 2,147 Mcfs for the months of November through March, 1,745 Mcfs for the month of April, 470 Mcfs for the months of May through September, and 896 Mcfs for the month of October; and (d) a contract for daily firm transmission capacity of 1,774 Mcfs with various partial expiration dates between 2016 and 2023. The contract with FCG, which expires in 2013, provides daily firm transportation capacity of 10,000 Dts and292 Mcfs on its Pioneer Pipeline. The contract with IGC, which expires in 2022.2016, provides daily firm transportation capacity of 487 Mcfs on its distribution system.
FPU uses gas marketers and producers to procure all its gas supplies for its natural gas distribution operations. FPU also uses TECO Peoples Gas to provide wholesale gas sales service in areas distant from its interconnections with FGT.
ESNG.Natural Gas Transmission
ESNG has three contracts with Transco for a total of 7,292 Dts7,045 Mcfs of firm peak day storage entitlements and total storage capacity of 288,003 Dts,278,264 Mcfs, each of which expireexpires in 2013. ESNG has retained these firm storage services in order to provide swing transportation service and firm storage service to those customers that have requested such service.service(s).
PESCO.Electric Distribution
PESCO currently has contracts with ConocoPhillips, British PetroleumOur electric distribution operation through FPU purchases all of its wholesale electricity from two suppliers: Gulf Power Company and Eagle Energy Partners, LLP for the purchaseJEA (formerly known as Jacksonville Electric Authority). Both of firm natural gas supplies.these contracts are all requirements contracts that expire in December 2017. The ConocoPhillipsJEA contract which provides a maximum firm daily entitlement of 15,000 MMBtus, the British Petroleumgeneration, transmission and distribution service to northeast Florida. The Gulf Power Company contract which provides a maximum firm daily entitlement of 10,000 MMBtus,generation, transmission and the Eagles Energy Partners, LLP contract, which provides for a maximum firm daily entitlement of 10,000 MMBtus expire in May 2009. PESCO is currently in the process of obtaining and reviewing supply proposals from suppliers and anticipates executing agreements priordistribution service to the expiration of the existing contracts.northwest Florida.
Competition
See discussion of competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”
Rates and Regulation
Chesapeake’sOur natural gas and electric distribution divisionsoperations are subject to regulation by the Delaware, Maryland and Florida PSCs with respect to various aspects of their 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 full recovery of such costs. Adjustments under these mechanisms, which are limited to such costs, require periodic filings and hearings with the state regulatory authority having jurisdiction.
Page 8     Chesapeake Utilities Corporation 2008 Form 10-K

ESNG is subject to regulation as an interstate pipeline by the Federal Energy Regulatory Commission (“FERC”),FERC, which regulates the terms and conditions of service and the rates ESNG 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 rates of return of its distribution divisions and ESNGeach of our regulated energy operations in order to ensure timely filing of rate cases.
Regulatory Proceedings
See discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Rate Filings and Other Regulatory Activities.”
Seasonality of Natural Gas and Electric Distribution Revenues
Revenues from the Company’sour residential and commercial natural gas distribution activities are affected by seasonal variations in weather conditions, which directly influence the volume of natural gas sold and delivered. Specifically, customer demand substantially increases during the winter months, when natural gas is used for heating. Accordingly, the volumes sold for this purpose are directly affected by the severity of winter weather and can vary substantially from year to year. Sustained warmer-than-normal temperatures will tend to result in reducedreduce use of natural gas, while sustained colder-than-normal temperatures will tend to result in greater use. The Company measuresincrease consumption. We measure the relative impact of weather by using an accepted degree-day methodology. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one heating degree-day. Normal heating degree-days are based on the most recent 10-year average.
For the electric distribution operations in northeast and northwest Florida, hot summers and cold winters produce year-round electric sales that normally do not have large seasonal fluctuations.
In effortsan effort to stabilize the level of net revenues collected from customers the Companyregardless 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 itsour 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

(i)(b) (ii)  Unregulated Energy
Our unregulated energy segment provides natural gas marketing, propane distribution and propane wholesale marketing services to customers.
Natural Gas Marketing
Our natural gas marketing subsidiary, PESCO, provides natural gas supply and supply management services to 2,123 customers in Florida and 11 customers on the Delmarva Peninsula. It competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers through competitively-priced contracts. PESCO does not own or operate any natural gas transmission or distribution assets. The gas that PESCO sells is delivered to retail customers through affiliated and non-affiliated local distribution company systems and transmission pipelines. PESCO bills its customers through the billing services of the regulated utilities that deliver the gas, or directly, through its own billing capabilities. For the year ended December 31, 2009, PESCO’s operating revenues and deliveries were as follows:
                 
  Operating Revenues  Deliveries 
  (in thousands)  (Mcfs) 
Florida $41,117   72%  7,066,144   71%
Delmarva  16,386   28%  2,818,844   29%
             
Total $57,503   100%  9,884,988   100%
             
PESCO currently has contracts with natural gas production companies for the purchase of firm natural gas supplies. These contracts provide a maximum firm daily entitlement of 35,000 Mcfs, and expire in May of 2010. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements prior to the end of the term of the existing contracts.
Included in PESCO’s operating revenue on the Delmarva Peninsula for 2009 was approximately $10.6 million of various natural gas spot sales and services to Valero Energy Corporation (“Valero”) for its Delaware City refinery operation. We previously reported on November 25, 2009 in a Form 8-K that Valero announced its intention to permanently shut down its Delaware City refinery. Spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
Propane Distribution
Propane is a form of liquefied petroleum gas, which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is a gas at normal pressure, it is easily compressed into liquid form for storage and transportation. Propane is a clean-burning fuel, gaining increased recognition for its environmental superiority, safety, efficiency, transportability and ease of use relative to alternative forms of fossil fuels. Propane is sold primarily in suburban and rural areas, which are not served by natural gas distributors.
Chesapeake’s retail propane distribution group consists of: (1) Chesapeake Utilities Corporation 2009 Form 10-K     Page 11

Sharp, Energy, Inc., (2) Sharpgas, Inc., and (3) Tri-County Gas Co., Inc. The propane wholesale marketing operation consists of Xeron, Inc.
Propane Distribution.
During 2008, our propane distribution operations served approximately 35,170subsidiary, serves 33,088 customers throughout Delaware, the Eastern Shore of Maryland and Virginia and southeastern Pennsylvania andPennsylvania. 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 and delivered approximately 27.9 million retail and wholesale gallons of propane. The propane distribution business is affectedoperation are now being served by many factors, such as seasonality, the absence of price regulation, and competition among local providers.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 9

FPU’s propane distribution operation in an effort to integrate operations. For the year 2008,ended December 31, 2009, operating revenues and total gallons sold and number of customers for ourby Sharp’s Delmarva and Florida propane distribution operations were as follow:follows:
                                        
 Operating Revenues Total Gallons Sold Average No. of  Operating Revenues Total Gallons Sold 
 (Thousands) (Thousands) Customers  (in thousands) (in thousands) 
Delmarva $59,173  95% 26,765  96% 32,889  94% $54,850  96% 30,635  97%
Florida 3,412  5% 1,182  4% 2,280  6% 2,357  4% 853  3%
                      
Total $62,585  100% 27,947  100% 35,169  100% $57,207  100% 31,488  100%
                      
The Company’sFPU has 13,651 propane distribution operations purchase propane primarily from suppliers,customers, 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 purchasethe customers previously served by the Company.
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. The Company’s Delmarva-basedSharp’s propane distribution operation owns bulkin Florida as previously discussed, which increased our propane storage facilities with an aggregate capacity of approximately 2.4customer base in Florida. For the period from the merger closing (on October 28, 2009) to December 31, 2009, operating revenue and total gallons delivered to these new customers were $3.0 million gallons at 42 plant facilitiesand 1.1 million gallons. FPU’s total propane deliveries in Delaware, Maryland, Pennsylvania and Virginia, located on real estate that is either owned or leased. The Company’s Florida-based propane distribution operation owns three bulk propane storage facilities with a total capacity of 66,000the full calendar year 2009, including the deliveries for the period prior to the merger, were 5.7 million gallons. From these storage facilities, propane is delivered primarily by “bobtail” trucks, owned and operated by the Company, to tanks located at the customers’ premises.
Propane Wholesale Marketing.
In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeronour propane wholesale marketing operation, markets propane to large, independent petrochemical companies, resellers and retail propane companies in the southeastern United States. For 2008, Xeron had operating revenues totaling approximately $3.3 million. The propane wholesale marketing business is affected by the propane wholesale price volatility and supply levels. Additional informationIn 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 Xeron’s risks, is included insee Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk.”
Xeron does not own physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.
Supplies, Transportation and Storage
Our propane distribution operations purchase propane primarily from suppliers, including major oil companies, independent producers of natural gas liquids and from Xeron. Supplies of propane from these and other sources are readily available for purchase.
Our propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to our bulk storage facilities. We own bulk propane storage facilities with an aggregate capacity of approximately 3.0 million gallons at various locations in Delaware, Maryland, Pennsylvania, Virginia and Florida. From these storage facilities, propane is delivered by “bobtail” trucks, owned and operated by us, to tanks located at the customers’ premises.
Competition
See discussion of competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”
Rates and Regulation
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 by the Federal Motor Carrier Safety Administration within the United States Department of Transportation (“DOT”) and enforced by the various states in which such operations take place. Propane distribution operations are also subject to state safety regulations relating to “hook-up” and placement of propane tanks.
The Company’s propane operations are subject to operating hazards normally associated with the handling, storage and transportation 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 to cover all potential liabilities.Page 12     Chesapeake Utilities Corporation 2009 Form 10-K

Seasonality of Propane Revenues
Revenues from the Company’sour 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 result in reducedreduce propane use, while sustained colder-than-normal temperatures will tend to result in greater use.increase consumption.
Page 10     Chesapeake Utilities Corporation 2008 Form 10-K

(i)(c) Advanced Information Services(iii)Other
Chesapeake’sThe ”Other” segment consists primarily of our 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.is headquartered in Norcross, Georgia, whichand provides domestic and international clients with information-technology-related businessinformation technology services and solutions for both enterprise and e-business applications.
CompetitionOther Subsidiaries
See discussion of competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”
(i)(d) Other Subsidiaries
Skipjack, Inc. and Eastern Shore Real Estate, Inc. own and lease office buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is an affiliated investment company registered in Delaware. During
(c) Other information about the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services subsidiary, OnSight.Business
(ii)(i) Capital Budget
A discussion of capital expenditures by business segment and capital expenditures for environmental remediation facilities is included in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
(iii)(ii) Employees
As of December 31, 2008, Chesapeake2009, we had 448a total of 757 employees, including 180 in natural gas, 132 in propane and 93 in advanced information services. The remaining 43332 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.
(iv)(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
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; 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 the Company’sour 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 hasUtilities Corporation 2009 Form 10-K     Page 13

We have a Business Code of Ethics and Conduct applicable to all employees, officers and directors and a Code of Ethics for Financial Officers. Copies of the Business Code of Ethics and Conduct and the Financial Officer Code of Ethics are available on our internetInternet 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 SEC and the New York Stock Exchange (“NYSE”). The Board of Directors has also adopted Corporate Governance Guidelines on Director Independence, which conform to the NYSE listing standards on director independence. Each of these documents also is available on 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.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 11

If Chesapeake makeswe make any amendment to, or grantsgrant a waiver of, any provision of the Business Code of Ethics and Conduct or the 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 May 20, 2008June 1, 2009 that, as of that date, he was unaware of any violation by Chesapeake Utilities Corporation 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 anticipated benefits of the merger with FPU may not be realized.
We entered into the merger with FPU with the expectation that the merger would result in various benefits, including, among other things, synergies, cost savings and operating efficiencies. Achieving these synergies, cost savings and operating efficiencies cannot be assured and failure to achieve these benefits will adversely affect expected future performance of the Company. In addition, the regulatory agencies that have jurisdiction over our regulated energy businesses and operations may require us to pass on some, or all, of the achieved cost savings to ratepayers.
Instability and volatility in the financial markets could have a negative impact on our growth strategy.
Our business strategy includes the continued pursuit of growth, both organically and through acquisitions. To the extent that we do not generate sufficient cash from operations, we may incur additional indebtedness to finance our growth. The turmoil experienced in the credit markets duringin 2008 and 2009 and its potential impact on the liquidity of major financial institutions may have an adverse effect on our customers and our ability to fund our business strategy through borrowings, under either existing or newly created arrangements in the public or private markets on terms we believe to be reasonable. Specifically, we rely on access to both short-term and longer-termlong-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flowflows from our operations. Currently, $45$40 million of the total $100 million of short-term lines of credit utilized to satisfy our short-term financing requirements are discretionary, uncommitted lines of credit. We utilize discretionary lines of credit to reduce the cost associated with these short-term financing requirements. We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. However, if we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.
Current levels of market volatility are unprecedented.
The capital and credit markets have been experiencing extreme volatility and disruption for more than twelve months. In recent weeks, the volatility and disruption have reached unprecedented levels. In some cases, the markets have exerted downward pressure on stock prices and credit capacity for certain issuers. There is no assurance that recent government intervention to help stabilize credit markets and financial institutions and restore liquidity will have beneficial effects in the credit markets, will address credit or liquidity issues of companies that participate in the programs or will reduce volatility or uncertainty in the financial markets. If current levels of market disruption and volatility continue or worsen, we would seek to meet our liquidity needs by drawing upon contractually committed lending agreements primarily provided by banks and/or by seeking other funding sources. Under such extreme market conditions, however, there can be no assurance that such agreements and other funding sources would be available or sufficient.
Page 1214     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Difficult conditions in the financial services markets have materially and adversely affected the business and results of operations of many financial institutions, and we do not know when and if these conditions may improve in the near future.
Dramatic declines in the housing market during the past year, with falling home prices and increasing foreclosures and unemployment, have resulted in significant write-downs of asset values by financial institutions, including government-sponsored entities and major commercial and investment banks. These write-downs, initially representing mortgage-backed securities but more recently including credit default swaps and other derivative securities, have caused many financial institutions to seek additional capital, to merge with larger and stronger institutions and, in some cases, to fail. Many lenders and institutional investors have reduced and, in some cases, ceased to provide funding to borrowers, including other financial institutions. This market turmoil and tightening of credit have led to an increased level of commercial and consumer delinquencies, lack of consumer confidence, increased market volatility and widespread reduction of business activity generally.
The unsoundness ofUnsound financial institutions could adversely affect the Company.
The Company hasOur 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 the Companyus 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 the Company’s businessour businesses and results of operations.
A downgrade in our credit rating could adversely affect our access to capital markets.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 Chesapeake’sour 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/orand it may become more difficult for them to pay their gas or propane 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.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 13

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 reliefincreases from regulatory commissions for regulated operations and closely monitor the returns of our unregulated business operations. There can be no assurance that we will be able to obtain adequate and timely rate reliefincreases 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.
Current market conditions have had a negative impact on the return on plan assets for our pension plan, which may require additional funding and negatively affect our cash flows.Chesapeake Utilities Corporation 2009 Form 10-K     Page 15

We have a pension plan that has been closed to new employees since January 1, 1999. The costs of providing benefits and related funding requirements of this plan are subject to changes in the market value of the assets that fund the plan. As a result of the extreme volatility and disruption in the domestic and international equity and bond markets, our pension plan experienced a decline of $4.3 million in its asset values during the year. The funded status of the plan 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. Under the Pension Protection Act of 2006, continued losses of asset values may necessitate accelerated funding of the plan in the future to meet minimum federal government requirements. Continued downward pressure on the asset values of the plan may require us to fund obligations earlier than it had originally planned, which would have a negative impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.
Our operations are exposed to market risks, beyond our control, which could adversely affect our financial results and capital requirements.
Our PESCOnatural gas marketing operation and Xeron operationspropane wholesale marketing operation are subject to market risks beyond ourtheir 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 our 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 usXeron to make assumptions as to future circumstances, including the use of natural gas and/or propane by ourits customers in relation to ourits anticipated market positions. Because the price risk associated with any net open position at the end of such day may increase if the assumptions are not realized, we review these assumptions daily. Net open positions may increase volatility in our financial condition or results of operations if market prices move in a significantly favorable or unfavorable manner, because the timing of the recognition of profits or losses on the economic hedges for financial accounting purposes usually does not match up with the timing of the economic profits or losses on the item being hedged. This volatility may occur, with a resulting increase or decrease in earnings or losses, even though the expected profit margin is essentially unchanged from the date the transactions were consummated.
Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.
Our energy marketing subsidiaries extend credit to counterparties and continually monitor and manage collections aggressively. Each of these subsidiaries is exposed to the risk that it may not be able to collect amounts owed to it. If the counterparty to such a transaction fails to perform, and any underlying collateral is inadequate, we could experience financial losses. These subsidiaries are also dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If financial market conditions decline generally, or the financial condition of these subsidiaries or of the Company declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.
Current market conditions have had an adverse impact on the return on plan assets for our pension plans, which may require significant additional funding and adversely affect the Company’s cash flows.
We have pension plans that have been closed to new employees. The costs of providing benefits and related funding requirements of these plans are subject to changes in the market value of the assets that fund the plans. As a result of the extreme volatility and disruption in the domestic and international equity and bond markets in recent years, the asset values of Chesapeake’s and FPU’s pension plans declined by $2.4 million and $2.8 million, respectively, since 2008. The funded status of the plans and the related costs reflected in our financial statements are affected by various factors that are subject to an inherent degree of uncertainty, particularly in the current economic environment. Future losses of asset values may necessitate accelerated funding of the plans in the future to meet minimum federal government requirements. Downward pressure on the asset values of our pension plans may require us to fund obligations earlier than originally planned, which would have an adverse impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.
Operational Risks
We may be unable to successfully integrate operations after the merger.
The merger between Chesapeake and FPU involves the integration of two companies that have previously operated independently. The difficulties of combining the companies’ operations include, among other things:
the necessity of coordinating geographically separated organizations, systems and facilities;
combining the best practices of the two companies, including operations, financial and administrative functions; and
integrating personnel with diverse business backgrounds and different contractual terms and conditions of employment.
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Operational Risks
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 propane,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 refinery closings.refineries. If we are unable to obtain sufficient natural gas, electricity and propane supplies to meet demand, results in those segmentsbusinesses 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’ transportationtransmission 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, and 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 capacity market,and electric transmission markets, our own on-system resources, as well as the characteristics of our markets. Chesapeake, along with other local natural gas distribution companiesOur financial condition and other participants in the industry, has voiced concern regardingresults of operations would be materially and adversely affected if the future availability of additional upstream interstate pipeline and storage capacity. This is a business issue which we must continuethese capacities were insufficient to manage as ourmeet future customer base grows.
Naturaldemands for natural gas and propane commodityelectricity. 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.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 gasfuel 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 gasgas/electricity as energy sources and consequently have an energy source.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-yearyear 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.
The Company’sOur propane distribution operations own bulk propane storage facilities, with an aggregate capacity of approximately 2.53.0 million gallons. We purchase and store propane based on several factors, including inventory levels and the price outlook. We may purchase large volumes of propane at current market prices during periods of low demand and low prices, which generally occur during the summer months. Propane is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the propane that we purchase can change rapidly over a short period of time. The market price for propane could fall below the price at which we made the purchases, which would adversely affect our profits or cause sales from that inventory to be unprofitable. In addition, falling propane prices may result in inventory write-downs as required by Generally Accepted Accounting PrinciplesU.S. generally accepted accounting principles (“GAAP”) if the market price of propane falls below our weighted average cost of inventory, and therefore,which could adversely affect net income.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 15

Operating events affecting public safety and the reliability of Chesapeake’sour natural gas and electric distribution systemsystems could adversely affect the results of operations, cash flows and financial condition and cash flows.condition.
Chesapeake’sOur business is exposed to operational events, such as major leaks, mechanical problems and accidents, that could affect the public safety and reliability of itsour 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 Chesapeake iswe are unable to recover from customers, through the regulatory process, all or some of these costs and itsour authorized rate of return on these costs, this also could adversely affect the results of operations, financial condition and cash flows.
Our electric operation is subject to various operational risks, including accidents, outages, equipment breakdowns or failures, or operations below expected levels of performance or efficiency. Problems such as the breakdown or failure of electric equipment or processes and interruptions in service which would result in performance below expected levels of output or efficiency, particularly if extended for prolonged periods of time, could have a materially adverse effect on our financial condition and results of operations.
Page 18     Chesapeake Utilities Corporation 2009 Form 10-K

Because we operate in a competitive environment, we may lose customers to competitors.competitors which could adversely affect our results of operations, cash flows and financial condition.
PESCO competesNatural Gas. Our natural gas marketing operations compete with third-party suppliers to sell natural gas to commercial and industrial customers. In ourOur natural gas transportationtransmission and distribution operations our competitors includecompete 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 several other propane distributors, primarily on the basis of service and price, emphasizing reliability of service and responsiveness.price. Some of our competitors have significantly greater resources. The retail propane industry is mature, and we foresee 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, ourOur ability to grow the propane distribution business is contingent upon continued execution of our community gas systems strategy to capturecapturing additional market share, successful penetration ofexpanding new service territories, and successful utilization ofsuccessfully 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.results of operations, cash flows and financial condition.
Xeron competesOur 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.
BravePoint 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.
Changes in technology may adversely affect our advanced information services segment’ssubsidiary’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 segmentoperation depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services, on a timely basis, and by keeping pace with technological developments and emerging industry standards. There is no assurance that we will be able to keep up with technological advancements to the degree necessary to keep our products and services competitive.
Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.
Xeron and PESCO extend credit to counter-parties. While 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.
Page 16     Chesapeake Utilities Corporation 2008 Form 10-K

Xeron and PESCO 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.
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 segmentsoperations 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 for our Delaware and Maryland natural gas distribution divisions, as well as PESCO.risk. While we have a risk management policy and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial conditionscondition may be adversely affected.
Changes in customer growth may affect earnings and cash flows.
Chesapeake’sOur ability to increase gross margins in itsour regulated energy and unregulated propane distribution businesses is dependent upon growth in the residential construction market, adding new commercial and industrial customers and conversion of customers to natural gas, electricity or propane from other fuel sources. Slowdowns in these markets couldhave and will continue to adversely affect the Company’sour gross margin in itsour regulated energy or propane distribution businesses, its earnings and cash flows.
Chesapeake’sOur businesses are capital intensive, and the costs of capital projects may be significant.
Chesapeake’sOur 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 we do not receive full recovery of such capital costs is not permitted in future regulatory proceedings.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 19

Chesapeake’sOur facilities and operations could be targets of acts of terrorism.
Chesapeake’sOur natural gas and electric distribution, natural gas transmission and propane storage facilities may be targets of terrorist activities that could result in a disruption ofdisrupt our ability to meet customer requirements. Terrorist attacks may also disrupt capital markets and Chesapeake’sour ability to raise capital. A terrorist attack on Chesapeake’sour facilities, or those of itsour suppliers or customers, could result in a significant decrease in revenues or a significant increase in repair costs, which could adversely affect our results of operations, financial position and cash flows.
The risk of terrorism and political unrest and the current hostilities in the Middle East may adversely affect the economy and the price and availability of propane, refined fuels, electricity and natural gas.
Terrorist attacks, political unrest and the current hostilities in the Middle East may adversely affect the price and availability of propane, refined fuels and natural gas, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil, electricity or natural gas supplies and markets, (the sources of propane), and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transporttransport/transmit propane, electricity and natural gas if our means of supply transportation, such as rail, power grid or pipeline, become damaged as a result of an attack. A lower level of economic activity following such events could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity and hostilities in the Middle East could likely lead to increased volatility in prices for propane, refined fuels, electricity and natural gas. We maintain insurance policies with insurers in such amounts and with such coverage and deductibles as we believe are reasonable and prudent. There can be no assurance, however, that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 17

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 ournatural 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 and substantial loss to us.operations. The location of pipeline, storage, transmission and storagedistribution 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 financial position, results of operations, cash flows and cash flows.financial condition.
Unionization campaignsOur 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 operations.operation.
The Company may becomeWe are party to collective bargaining agreements with various labor unions at some of our Florida operations. A strike, work stoppage or a target of unionization campaigns. Unions may attemptlabor dispute with a union or employees represented by a union could cause interruption to pressure Chesapeake’s employeesour operations. If a strike, work stoppage or other labor dispute were to choose union representation. Such campaignsoccur, our results could be materially disruptive to our business and could have an adverse effect on our results of operations.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 natural gas distributionutility operations in those States;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 interstate pipelinenatural 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 byfrom 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, transportingtransporting/ 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 such amounts and with such coverages and deductibles asthe 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.third-parties. Compliance with these legal obligations requires us to commit capital. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines.
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To date, we have been able to recover, through regulatory rate mechanisms, the costs associated with the remediation of former manufactured gas plantMGP sites. However, thereThere 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 manufactured gas plantMGP 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 legislatorsregulators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs, including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
result in increased costs associated with our operations;
increase other costs to our business;
affect the demand for natural gas, electricity and propane; and
impact the prices we charge our customers.
Any adoptionaction 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. Properties.
(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; Lecato,Lecanto, Virginia; and West Palm Beach, DeBary, Inglis, Marianna, Lantana, Lauderhill, Fernandina Beach and Winter Haven, Florida. The Company rentsWe rent office space in Dover, Ocean View, and South Bethany, Delaware; Jupiter, Fernandina and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton, Maryland; Honey Brook and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In general, the Company believeswe believe that itsour offices and facilities are adequate for the uses for which they are employed.
(b)Natural Gas Distribution
The CompanyOur Delmarva natural gas distribution operation owns over 1,0761,102 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 754own 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 Florida service areas. The Companyeach of the distribution systems. We also ownsown facilities in Delaware and Maryland, which it useswe use for propane-air injection during periods of peak demand.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 19

(c)Natural Gas Transmission
ESNG owns and operates approximately 379384 miles of transmission pipelines,pipeline, extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania; and Hockessin, Delaware, to approximately 8180 delivery points in southeastern Pennsylvania, Delaware and the Eastern Shore of Maryland.
PIPECO owns and operates approximately eight miles of transmission pipeline in Suwanee County, Florida.
(d)Electric Distribution
The Company’s electric distribution operation owns and operates 20 miles of electric transmission line located in northeast Florida and 1,125 miles of electric distribution line located in northeast and northwest Florida.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 23

(e)Propane Distribution and Wholesale Marketing
The Company’sOur Delmarva-based propane distribution operation owns bulk propane storage facilities, with an aggregate capacity of approximately 2.4 million gallons, at 42 plant facilities in Delaware, Maryland, Pennsylvania and Virginia, located on real estate that is either owned or leased. 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 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 Proceedings.
(a)General
The Company and its subsidiaries are currently involved in various legal actions and claims arising in the normal course of business. The Company is also involved in certain administrative proceedings before various governmental or regulatory agencies concerning rates. In the opinion of management, the ultimate disposition of these current proceedings will not have a material effect on the Company’s consolidated financial position.position and results of operations.
(b)Environmental
See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note N.O, Environmental Commitments and Contingencies.”
Item 4. Submission of Matters to a Vote of Security Holders.
NoneA special meeting of the shareholders of the Company was held on October 22, 2009, to consider and vote upon the following proposals:
(1)A proposal related to adoption of the merger agreement and approval of the merger with Florida Public Utilities Company;
(2)A proposal relating to the issuance of Chesapeake common stock in the merger; and
(3)A proposal to approve adjournments or postponements of the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the end of the time in the special meeting to approve the above proposals.
The proposals were approved as follows:
             
  Votes  Votes Against    
  For  or Withheld  Abstentions 
Adoption of the merger agreement and approval of the merger  5,186,617   85,243   27,204 
Issuance of Chesapeake common stock in the merger  5,186,617   85,243   27,204 
Approve adjournment or postponement  4,846,740   411,960   40,365 
There were no broker non-votes.
Page 24     Chesapeake Utilities Corporation 2009 Form 10-K

Item 4A. Executive Officers of the Registrant.
Set forth below are the names, ages, and positions of executive officers of the registrant at December 31, 2008, with their recent business experience. The age of each officer is as of the filing date of this report.
       
Name Age Position
John R. Schimkaitis  6162  PresidentVice Chairman and Chief Executive Officer
Michael P. McMasters  5051  Executive Vice President and Chief Operating Officer
Beth W. Cooper  4243  Senior Vice President and Chief Financial Officer
Stephen C. Thompson  4849  Senior Vice President and President, ESNG
S. Robert ZolaJoseph Cummiskey  5638  Vice President Sharp Energyand President, PESCO
John R. Schimkaitis is PresidentVice Chairman 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. 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 was appointed as Executive Viceis President and Chief Operating Officer inof 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 this appointment,these appointments, Mr. McMasters served as Senior Vice President since 2004 and Chief Financial Officer of the CompanyChesapeake 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.
Page 20     Chesapeake Utilities Corporation 2008 Form 10-K

Beth W. Cooper was appointed as Senior Vice President and Chief Financial Officer in September of 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 the CompanyChesapeake 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 Utilities Corporation 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.
S. Robert ZolaJoseph Cummiskey was appointed as Vice President of Chesapeake and President of PESCO in December 2009. Mr. Cummiskey joined Sharp EnergyChesapeake in August 2002December 2005 as President.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 Sharp Energy,Chesapeake, Mr. Zola most recently servedCummiskey was employed as Northeasta Natural Gas Liquids Regional ManagerDirector for Ferrell North America. In that position, he was responsible for the purchasing and distribution of Synergy Gas, now Cornerstone MLP, in Philadelphia, PA. During his 27-year career in theFerrell’s propane industry, Mr. Zola also started and successfully developed Bluestreak Propane, in Phoenix, AZ, which was ultimately sold to Ferrellgas.supply.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 2125

 

 

Part II
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
(a)Common Stock Price Ranges, Common Stock Dividends and Shareholder Information:
The Company’s common stock is listed on the NYSE under the symbol “CPK.” The high, low and closing prices of the Company’s common stock and dividends declared per share for each calendar quarter during the years 20082009 and 20072008 were as follows:
                                  
 Dividends  Dividends 
 Declared  Declared 
Quarter EndedQuarter Ended High Low Close Per Share  High Low Close Per Share 
2008
   
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 
 March 31 $33.60 $27.21 $29.64 $0.295          
 June 30 31.88 25.02 25.72 0.305  
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 
 September 30 34.84 24.65 33.21 0.305          
 December 31 34.66 21.93 31.48 0.305 
   
2007
   
 March 31 $31.10 $28.85 $30.94 $0.290 
 June 30 35.58 29.92 34.24 0.295 
 September 30 37.25 28.00 33.94 0.295 
 December 31 36.38 29.59 31.85 0.295 
Holders
At December 31, 2008,2009, there were 1,9142,670 holders of record of Chesapeake Utilities Corporation common stock.
Dividends
Chesapeake hasWe have paid a cash dividend to common stock shareholders for forty-eight49 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 20082009 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 the Company,Chesapeake, each of the Company’sits Unsecured Senior Notes contains a “Restricted Payments” covenant. The most restrictive covenants of this type are included within the 7.83%7.83 percent Senior Notes, due January 1, 2015. The covenant provides that the CompanyChesapeake 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, 2008, the Company’s2009, Chesapeake’s cumulative consolidated net income base was $86.9$102.8 million, offset by Restricted Payments of $54.4$63.8 million, leaving $32.5$39.0 million of cumulative net income free of restrictions.
Page 2226     Chesapeake Utilities Corporation 20082009 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 sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1 2001. As of December 31, 2009, FPU had the cumulative net income base of $32.7 million, offset by restricted payments of $22.1 million, leaving $10.6 million of cumulative net income of FPU free of restrictions based on this covenant. In January 2010, this series of first mortgage bonds were redeemed prior to their maturities. The second most restricted covenant of this type is included in the series that is due in 2022, which provided that FPU cannot make dividend or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. This covenant provided FPU with the cumulative net income base of $56.0 million, offset by restricted payments of $37.6 million, leaving $18.4 million of cumulative net income of FPU free of restrictions as of December 31, 2009.
(b)Purchases of Equity Securities by the Issuer
The following table sets forth information on purchases by or on behalf of Chesapeake of shares of its common stock during the quarter ended December 31, 2008.2009.
                 
  Total      Total Number of Shares  Maximum Number of 
  Number of  Average  Purchased as Part of  Shares That May Yet Be 
  Shares  Price Paid  Publicly Announced Plans  Purchased Under the 
Period Purchased  Per Share  or Programs(2)  Plans or Programs(2) 
October 1, 2008 through October 31, 2008(1)
  594  $31.62   0   0 
November 1, 2008 through November 30, 2008  0  $0.00   0   0 
December 1, 2008 through December 31, 2008  0  $0.00   0   0 
             
Total  594  $31.62   0   0 
             
                 
  Total      Total Number of Shares  Maximum Number of 
  Number  Average  Purchased as Part of  Shares That May Yet Be 
  of Shares  Price Paid  Publicly Announced Plans  Purchased Under the Plans 
Period Purchased  per Share  or Programs(2)  or Programs(2) 
October 1, 2009                
through October 31, 2009(1)
  587  $30.14   —   — 
November 1, 2009                
through November 30, 2009  —   —   —   — 
December 1, 2009                
through December 31, 2009  —   —   —   — 
             
Total  587  $30.14   —   — 
             
   
(1) Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives and Directors under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Note KN to the Consolidated Financial Statements. During the quarter, 594587 shares were purchased through the reinvestment of dividends on deferred stock units.
 
(2) Except for the purposespurpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.
Discussion of compensation plans of Chesapeake and its subsidiaries, for which shares of Chesapeake common stock are authorized for issuance, is included in the portion of the Proxy Statement captioned “Equity Compensation Plan Information” to be filed notno later than March 31, 2009,2010, in connection with the Company’s Annual Meeting to be held on or about May 6, 2009,5, 2010 and, is incorporated herein by reference.
(c)Chesapeake Utilities Corporation Common Stock Performance Graph
The following stock Performance Graph compares cumulative total shareholder return on a hypothetical investment in the Company’sour common stock during the five fiscal years ended December 31, 2008,2009, with the cumulative total shareholder return on a hypothetical investment in both (i) the Standard & Poor’s 500 Index (“S&P 500 Index”), and (ii) an industry index consisting of 13Chesapeake and 11 of the companies in the current Edward Jones Natural Gas Distribution Group, a published listing of selected gas distribution utilities’ results. The Company’s Performance Graph for the previous year included all but one of these same companies. The Company’sOur Compensation Committee utilizes the Edward Jones Natural Gas Distribution Group as itsour peer group to which the Company’sour performance is compared for purposes of determining the level of long-term performance awards earned by the Company’sour named executives.
The thirteeneleven companies in the Edward Jones Natural Gas Distribution Group industry index include: AGL Resources, Inc., Atmos Energy Corporation, Chesapeake Utilities Corporation, Corning Natural Gas Corporation, Delta Natural Gas Company, Inc., Energy West, Inc., The Laclede Group, Inc., New Jersey Resources Corporation, Northwest Natural Gas Company, Piedmont Natural Gas Co., Inc., RGC Resources, Inc., South Jersey Industries, Inc.,Inc, and WGL Holdings, Inc. The Company excluded EnergySouth, Inc. from its comparison due to its recent acquisition by Sempra Energy.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 27

The comparison assumes $100 was invested on December 31, 20032004 in the Company’sour common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of the Company’sour 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 2008 Form 10-K     Page 23

                         
  2003  2004  2005  2006  2007  2008 
Chesapeake
 $100  $107  $128  $133  $143  $147 
Industry Index
 $100  $117  $123  $147  $152  $163 
S&P 500 Index
 $100  $111  $116  $135  $142  $90 
Page 24     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Item 6. Selected Financial Data
                        
For the Years Ended December 31, 2008 2007 2006(3)  2009(3) 2008 2007 
Operating(in thousands of dollars)(1)
 
Operating(1)
(in thousands)
 
Revenues  
Natural gas $211,402 $181,202 $170,374 
Propane 65,877 62,838 48,576 
Advanced informations systems 14,720 15,099 12,568 
Other and eliminations  (556)  (853)  (318)
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 $291,443 $258,286 $231,200  $268,785 $291,443 $258,286 
  
Operating income  
Natural gas $25,846 $22,485 $19,733 
Propane 1,586 4,498 2,534 
Advanced informations systems 695 836 767 
Other and eliminations 352 295 298 
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 $28,479 $28,114 $23,332  $33,736 $28,479 $28,114 
  
Net income from continuing operations $13,607 $13,218 $10,748  $15,897 $13,607 $13,218 
        
 
Assets(in thousands of dollars)
 
Assets
(in thousands)
 
Gross property, plant and equipment $381,688 $352,838 $325,836  $543,746 $381,689 $352,838 
Net property, plant and equipment(2)
 $280,671 $260,423 $240,825  $436,428 $280,671 $260,423 
Total assets(2)
 $385,795 $381,557 $325,585  $617,102 $385,795 $381,557 
Capital expenditures(1)
 $30,844 $30,142 $49,154  $26,294 $30,844 $30,142 
        
 
Capitalization(in thousands of dollars)
 
Capitalization
(in thousands)
 
Stockholders’ equity $123,073 $119,576 $111,152  $209,781 $123,073 $119,576 
Long-term debt, net of current maturities 86,422 63,256 71,050  98,814 86,422 63,256 
              
Total capitalization $209,495 $182,832 $182,202  $308,595 $209,495 $182,832 
  
Current portion of long-term debt 6,657 7,656 7,656  35,299 6,656 7,656 
Short-term debt 33,000 45,664 27,554  30,023 33,000 45,664 
              
Total capitalization and short-term financing $249,152 $236,152 $217,412  $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, SFAS No. 143it 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 20082009 Form 10-K     Page 2529

 

 

                             
  2005  2004  2003  2002  2001  2000  1999 
                             
  $166,582  $124,246  $110,247  $93,588  $107,418  $101,138  $75,637 
   48,976   41,500   41,029   29,238   35,742   31,780   25,199 
   14,140   12,427   12,578   12,764   14,104   12,390   13,531 
   (213)  (218)  (286)  (334)  (113)  (131)  (14)
                      
  $229,485  $177,955  $163,568  $135,256  $157,151  $145,177  $114,353 
                             
  $17,236  $17,091  $16,653  $14,973  $14,405  $12,798  $10,388 
   3,209   2,364   3,875   1,052   913   2,135   2,622 
   1,197   387   692   343   517   336   1,470 
   279   335   359   237   386   816   495 
                      
  $21,921  $20,177  $21,579  $16,605  $16,221  $16,085  $14,975 
                             
  $10,699  $9,686  $10,079  $7,535  $7,341  $7,665  $8,372 
                      
 
  $280,345  $250,267  $234,919  $229,128  $216,903  $192,925  $172,068 
  $201,504  $177,053  $167,872  $166,846  $161,014  $131,466  $117,663 
  $295,980  $241,938  $222,058  $223,721  $222,229  $211,764  $166,958 
  $33,423  $17,830  $11,822  $13,836  $26,293  $22,057  $21,365 
                      
                             
  $84,757  $77,962  $72,939  $67,350  $67,517  $64,669  $60,714 
   58,991   66,190   69,416   73,408   48,409   50,921   33,777 
                      
  $143,748  $144,152  $142,355  $140,758  $115,926  $115,590  $94,491 
                             
   4,929   2,909   3,665   3,938   2,686   2,665   2,665 
   35,482   5,002   3,515   10,900   42,100   25,400   23,000 
                      
  $184,159  $152,063  $149,535  $155,596  $160,712  $143,655  $120,156 
                      
                           
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 
                    
Page 2630     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Item 6. Selected Financial Data
                        
For the Years Ended December 31, 2008 2007 2006(3)  2009(3) 2008 2007 
Common Stock Data and Ratios
  
Basic earnings per share from continuing operations(1)
 $2.00 $1.96 $1.78  $2.17 $2.00 $1.96 
Diluted earnings per share from continuing operations(1)
 $1.98 $1.94 $1.76  $2.15 $1.98 $1.94 
  
Return on average equity from continuing operations(1)
  11.2%  11.5%  11.0%  11.2%  11.2%  11.5%
  
Common equity / total capitalization  58.7%  65.4%  61.0%  68.0%  58.7%  65.4%
Common equity / total capitalization and short-term financing  49.4%  50.6%  51.1%  56.1%  49.4%  50.6%
  
Book value per share $18.03 $17.64 $16.62  $22.33 $18.03 $17.64 
        
 
Market price:  
High $34.840 $37.250 $35.650  $35.000 $34.840 $37.250 
Low $21.930 $28.000 $27.900  $22.020 $21.930 $28.000 
Close $31.480 $31.850 $30.650  $32.050 $31.480 $31.850 
       
  
Average number of shares outstanding 6,811,848 6,743,041 6,032,462  7,313,320 6,811,848 6,743,041 
Shares outstanding at year-end 6,827,121 6,777,410 6,688,084  9,394,314 6,827,121 6,777,410 
Registered common shareholders 1,914 1,920 1,978  2,670 1,914 1,920 
 
Cash dividends declared per share $1.21 $1.18 $1.16  $1.25 $1.21 $1.18 
Dividend yield (annualized)(2)
  3.9%  3.7%  3.8%  3.9%  3.9%  3.7%
Payout ratio from continuing operations(1) (4)
  60.5%  60.2%  65.2%  57.6%  60.5%  60.2%
        
 
Additional Data
  
Customers 
Natural gas distribution and transmission 65,201 62,884 59,132 
Customers(5)
 
Natural gas distribution 117,887 65,201 62,884 
Electric distribution 31,030 — — 
Propane distribution 34,981 34,143 33,282  48,680 34,981 34,143 
        
 
Volumes 
Natural gas deliveries (in MMCF) 39,778 34,820 34,321 
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) 27,956 29,785 24,243  32,546 27,956 29,785 
       
  
Heating degree-days (Delmarva Peninsula)  
Actual HDD 4,431 4,504 3,931  4,729 4,431 4,504 
10 -year average HDD (normal) 4,401 4,376 4,372 
10-year average HDD (normal) 4,462 4,401 4,376 
  
Propane bulk storage capacity (in thousands of gallons) 2,471 2,441 2,315  3,042 2,471 2,441 
  
Total employees(1)
 448 445 437 
       
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 Company closedCompanyclosed 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) SFAS No. 123RThese amounts include the financial position and SFAS No. 158 were adopted in the year 2006; therefore, they were not applicableresults of operation of FPU for the years priorperiod from the merger closing (October 28, 2009) to 2006.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 20082009 Form 10-K     Page 2731

 

 

                             
  2005  2004  2003  2002  2001  2000  1999 
  $1.83  $1.68  $1.80  $1.37  $1.37  $1.46  $1.63 
  $1.81  $1.64  $1.76  $1.37  $1.35  $1.43  $1.59 
                             
   13.2%  12.8%  14.4%  11.2%  11.1%  12.2%  14.3%
                             
   59.0%  54.1%  51.2%  47.8%  58.2%  55.9%  64.3%
   46.0%  51.3%  48.8%  43.3%  42.0%  45.0%  50.5%
                             
  $14.41  $13.49  $12.89  $12.16  $12.45  $12.21  $11.71 
                      
                             
  $35.780  $27.550  $26.700  $21.990  $19.900  $18.875  $19.813 
  $23.600  $20.420  $18.400  $16.500  $17.375  $16.250  $14.875 
  $30.800  $26.700  $26.050  $18.300  $19.800  $18.625  $18.375 
                      
                             
   5,836,463   5,735,405   5,610,592   5,489,424   5,367,433   5,249,439   5,144,449 
   5,883,099   5,778,976   5,660,594   5,537,710   5,424,962   5,297,443   5,186,546 
   2,026   2,026   2,069   2,130   2,171   2,166   2,212 
                             
  $1.14  $1.12  $1.10  $1.10  $1.10  $1.07  $1.03 
   3.7%  4.2%  4.2%  6.0%  5.6%  5.8%  5.7%
   62.3%  66.7%  61.1%  80.3%  80.3%  73.3%  63.2%
                      
                             
   54,786   50,878   47,649   45,133   42,741   40,854   39,029 
   32,117   34,888   34,894   34,566   35,530   35,563   35,267 
                      
                             
   34,981   31,430   29,375   27,935   27,264   30,830   27,383 
   26,178   24,979   25,147   21,185   23,080   28,469   27,788 
                      
                             
   4,792   4,553   4,715   4,161   4,368   4,730   4,082 
   4,436   4,389   4,409   4,393   4,446   4,356   4,409 
 
   2,315   2,045   2,195   2,151   1,958   1,928   1,926 
                             
   423   426   439   455   458   471   466 
                      
                           
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 2832     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
This section provides management’s discussion of Chesapeake 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.” 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 OVERVIEWThe following discussions and those later in the document on operating income and segment results include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated energy operations and under its competitive pricing structure for unregulated natural gas marketing and propane distribution operations. Chesapeake’s management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.
In addition, certain information is presented, which excludes for comparison purposes, result of operations of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009 and all merger-related costs incurred in connection with the FPU merger. Although the non-GAAP measures are not intended to replace the GAAP measures for evaluation of Chesapeake’s performance, we believe that the portions of the presentation which excludes FPU’s financial results for the post-merger period and merger-related costs provide a helpful comparative basis for investors to understand Chesapeake’s performance.
(a) Introduction
Chesapeake is a diversified utility company engaged, directly or through subsidiaries, in natural gas distribution, transmissionregulated energy businesses, unregulated energy businesses, and marketing, propane distribution and wholesale marketing,other unregulated businesses, including advanced information services and other related businesses.services.
The Company’sOur 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 gasregulated energy distribution and transmission businessbusinesses 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 the Company’sour 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 the Companyus to access capital as needed; and
maintaining a consistent and competitive dividend for shareholders.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 following discussions and those latermerger allowed us to become a larger energy company serving approximately 200,000 customers in the document on operating incomeMid-Atlantic and segment results include useFlorida markets, which is twice the number of the term “gross margin.” Gross margin is determinedenergy customers we served previously. The merger increased our overall presence in Florida by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost ofadding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing natural gas and propane distribution operations in Florida. It also introduces us to the electric distribution business as it incorporates FPU’s approximately 31,000 electric customers in northwest and northeast Florida.
Total consideration paid by Chesapeake in the costmerger was approximately $75.7 million, which included approximately $16,000 paid in cash and 2,487,910 shares of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternativecommon stock issued at a price per share of $30.42. Net fair value of the assets acquired and liabilities assumed in the merger was estimated at $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. All of the purchase premium paid in the merger was related to operating income orthe regulated energy segment. Chesapeake also incurred approximately $3.0 million in merger-related costs related to consummating the merger, merger-related litigation costs and costs incurred in integrating operations of the two companies. As we intend to seek recovery through future rates of the premium paid and merger-related costs we incurred, we have deferred approximately $1.5 million of the merger-related costs as a regulatory asset as of December 31, 2009.
Our net income which are determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningfulfor 2009 was $15.9 million, or $2.15 per share (diluted), compared 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 operations and under its competitive pricing structure for non-regulated segments. 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.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 29

Management’s Discussion and Analysis
Chesapeake had a successful 2008, in spite of the state of the global economic and financial markets. For the year, net income increased by three percent as the Company earned $13.6 million, in net income, or $1.98 per share (diluted), comparedfor 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 of $13.2contributed 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 $1.94$2.20 per share (diluted) and $2.08 per share (diluted), earned in 2007. We were able to achieve this growth despite taking a charge of $1.2 million in other operating expenses for costs related to an unconsummated acquisition. Absent this charge, the Company estimates that, compared to 2007, net income would have increased to $14.3 million, or $2.08 per share (diluted).2009 and 2008, respectively.
The higher period-over-period net income was attributable primarily tofollowing is a summary of key factors affecting our natural gas segment. Our natural gas transmissionbusinesses and distribution operations continued to invest capital in current growth initiatives that favorably positioned us for future growth as well. These operations invested $25.6 million in property, plant,their impacts on our 2009 results. More detailed discussion and equipment during 2008, primarily to expand our transmission and distribution systems. These expansions were undertaken pursuant to additional long-term firm transportation service contracts for our transmission operation and continued customer growth for the distribution operations. Collectively, these growth initiatives contributed $2.8 million to gross margin in 2008.
As a result of market conditionsanalysis are provided in the housing industry, the Company continued to see a slowdown in the number“Results of new houses being constructed. Despite this slowdown, the average number of residential customers served by our natural gas distribution operations increased by four percent. While this growth percentage is lower than that experienced in recent years, it is still significantly above the national average.Operations” section.
PESCO experienced a record year as gross margin increased by 91 percent over 2007. This increase was achieved through enhanced sales contract terms, margins on spot sales of approximately $600,000 and a 26-percent growth in its customer base. A 26-percent increase in its customer base
•
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 a 41-percent increase in volumes sold in 2008.
The successful completion of rate proceedings for the Company’s natural gas transmission and Delmarva distribution operations added $387,000 to gross margin in 2008. In addition, these rate proceedings provided for lower depreciation allowances and lower asset removal cost allowances, which contributed to the period-over-period decrease in depreciation expense and asset removal costs of $2.3 million in 2008.
Propane price volatility during 2008 affected our wholesale marketing operation positively and our propane distribution operation negatively. Xeron capitalized on the price volatility, seizing opportunities to sell at prices above cost and to manage effectively the larger spreads between the market (spot) prices and forward propane prices experienced in 2008, which contributed to the operation’s 38-percent year-over-year growth in gross margin.
In contrast, the volatility of wholesale propane prices had a negative impact on our propane distribution operations. Wholesale propane prices rose dramatically during the spring months of 2008, when they are traditionally falling. In efforts to protect the Company from the impact that additional price increases would have on our Pro-Cap (propane price-cap) Plan that we offer to customers, the propane distribution operation entered into a swap agreement. By December 31, 2008, the market price of propane had plummeted well below the unit price in the swap agreement. As a result, the Company marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales by $939,000 for 2008 and resulted in the Company adjusting the valuation of its propane inventory to current market prices in accordance with Accounting Research Bulletin No. 43. Both of these adjustments reduced gross margin during 2008 by a total of $2.3 million compared to 2007. The Company subsequently terminated the swap agreement in January 2009.
Adverse economic conditions severely affected the advanced information services segment. BravePoint experienced lower consulting revenues as customers began to conserve their information technology spending, resulting in a nine percent decline in billable hours in 2008 compared to 2007.
In response to the instability and volatility of the financial markets, we increased the amounts of our committed short-term borrowing capacity from $15.0 million to $55.0 million, while maintaining total short-term line-of-credit capacity of $100.0 million. In addition, on October 31, 2008, the Company executed a $30.0 million long-term debt placement of 5.93 percent Unsecured Senior Notes, maturing on October 31, 2023.
•
Growth. Customer growth continued to be affected by current economic conditions. Despite the slowdown in growth in the region, our Delaware and Maryland natural gas distribution divisions achieved customer growth in 2009 compared to 2008, which contributed $1.2 million in gross margin for the year. Chesapeake’s Florida natural gas distribution division experienced a net customer loss in 2009, which resulted in a gross margin decrease of $190,000. A loss of three large industrial customers in Florida in late 2008 and 2009 contributed primarily to this gross margin decrease. Our natural gas transmission subsidiary, ESNG, experienced continued growth in 2009 through new transmission services and new expansion facilities. New firm services to an industrial customer in 2009 contributed $811,000 to ESNG’s gross margin in 2009 and are expected to contribute approximately $1.1 million to its gross margin in 2010. New system expansions in November 2008 and 2009 also contributed $939,000 to its gross margin growth in 2009.
Page 3034     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Operating Income
•
Propane Prices. A sharp decline in propane prices in late 2008 resulted in inventory and swap valuation adjustments of $1.8 million in 2008, but allowed our Delmarva propane distribution operation to keep its propane cost low during the first half of 2009. The absence of similar inventory valuation adjustments in 2009 and increased margin generated from the low propane cost during the first half of 2009, coupled with sustained retail prices, contributed to increased gross margin of $3.5 million in 2009 compared to 2008 for the Delmarva propane distribution operation. Overall lack of volatility in wholesale propane prices reduced opportunities for our propane wholesale marketing subsidiary, Xeron, and decreased its trading volume by 57 percent in 2009 compared to 2008, which reduced its gross margin by approximately $1.0 million.
The year-over-year increase in operating income for 2008, driven by the strong performance of our natural gas business segment, was partially offset by lower operating income from the propane and advanced information services business segments.
•
Natural Gas Spot Sale Opportunities. Our unregulated natural gas marketing subsidiary, PESCO, was able to identify various spot sale opportunities in 2009, which contributed significantly to the overall gross margin increase of $1.0 million in 2009. During 2009, PESCO sold natural gas and services of $10.6 million to Valero for its Delaware City refinery operation. Late in 2009, Valero announced its intention to permanently shut down that refinery. While PESCO’s sale to Valero in 2009 represented approximately 19 percent of PESCO’s total revenue for the year, spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
                 
              Percentage 
(In thousands) 2008  2007  Change  Change 
Natural gas $25,846  $22,485  $3,361   15%
Propane  1,586   4,498   (2,912)  -65%
Advanced information services  695   836   (141)  -17%
Other & eliminations  352   295   57   19%
             
Total operating income $28,479  $28,114  $365   1%
             
•
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.
The Company’s financial performance is discussed in greater detail below in “Results of Operations.”
•
Information Technology Spending. The state of the economy continued to affect overall information technology spending in 2009. Our advanced information services subsidiary, BravePoint, continued to experience lower consulting revenues as billable consulting hours declined by 28 percent in 2009 compared to 2008. We implemented cost-containment actions, including layoffs and compensation adjustments, which reduced operating costs in 2009 by $1.0 million. BravePoint’s professional database monitoring and support solution services, added $218,000 to its gross margin in 2009.
•
Interest Rates. We continued to experience low short-term interest rates throughout 2009 as our short-term weighted average interest rate decreased to 1.28 percent in 2009, compared to 2.79 percent in 2008. The level of our short-term borrowings in 2009 was reduced by the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008 and a decline in working capital requirements due to lower commodity prices, lower trading volume by the propane wholesale marketing subsidiary, lower income tax payments from bonus depreciation and the timing of our capital expenditures.
(c) Critical Accounting Policies
Chesapeake prepares itsWe prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. Chesapeake bases itsWe base our estimates on historical experience and on various assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Since most of Chesapeake’sour businesses are regulated and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates. Management believes that the following policies require significant estimates or other judgments of matters that are inherently uncertain. These policies and their application have been discussed with Chesapeake’sour Audit Committee.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 35

Regulatory Assets and Liabilities
As a result of the ratemaking process, Chesapeake recordswe record certain assets and liabilities in accordance with Statement of FinancialFASB Accounting Standards Codification (“SFAS”ASC”) No. 71, “Accounting for the Effects of Certain Types of Regulation;Topic 980, “Regulated Operations,” consequently, the accounting principles applied by our regulated utilitiesenergy businesses differ in certain respects from those applied by the unregulated businesses. Costs are deferred when there is a probable expectation that they will be recovered in future revenues as a result of the regulatory process. As more fully described in Note AItem 8 under the heading “Notes to the Consolidated Financial Statements Chesapeake had– Note A, Summary of Accounting Policies,” we have recorded regulatory assets of $3.6$21.1 million and regulatory liabilities of $24.7$46.3 million, at December 31, 2008.2009. 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 an adjustment could have a material effect on the Company’sour results of operations.
Valuation of Environmental Assets and Liabilities
As more fully described in Note N, “Environmental Commitments and Contingencies,” inItem 8 under the Notesheading “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. In addition, there is uncertainty with regard to amounts that may be recovered from other potentially responsible parties.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 31

Management’s Discussion and Analysis
Since the Company’s management believeswe believe that recovery of these expenditures, including any litigation costs, is probable through the regulatory process, the Company haswe have recorded in accordance with SFAS No. 71, a regulatory asset and corresponding regulatoryenvironmental liability. At December 31, 2008, Chesapeake had2009, we have recorded an environmental regulatory asset of $779,000$7.5 million and a liability of $511,000$12.8 million for environmental costs.
Derivatives
Chesapeake mayWe 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 manage the price risk of its natural gas andengage in propane purchasingmarketing activities. The CompanyWe continually monitorsmonitor the use of these instruments to ensure compliance with itsour risk management policies and accountsaccount for them in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” by recording their fair value as assets and liabilities.appropriate GAAP. If the derivative contractsthese instruments do not meet the definition of derivatives or are considered “normal purchasepurchases and normal sale” scope exception of SFAS No. 133, the related activities and servicessales,” they are accounted for on an accrual basis of accounting.
The following is a review of Chesapeake’sour use of derivative instruments at December 31, 20082009 and 2007:2008:
TheDuring 2009 and 2008, our natural gas distribution, electric distribution, propane distribution and natural gas marketing operations during 2008 and 2007, entered into physical contracts for the purchase andor sale of natural gas, which qualified forelectricity 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 normal sales” scope exception under SFAS No. 133 in thatas they provided for the purchase or sale of natural gas, electricity or propane to be delivered in quantities expected to be used orand sold by the Companyour operations over a reasonable period of time in the normal course of business. Accordingly, theythese contracts were not subject toaccounted for on the accounting requirementsaccrual basis of SFAS No. 133.accounting.
During 2008, and 2007, Chesapeake’s propane distribution operations entered into physical contracts to buy propane supplies, which qualified for the “normal purchases and normal sales” scope exception under SFAS No. 133 in that they provided for the purchase or sale of propane to be delivered in quantities expected to be used or sold by the Company over a reasonable period of time in the normal course of business. Accordingly, the related liabilities incurred and assets acquired under these contracts were recorded when title to the underlying commodity passed.
During 2008, but not during 2007, the propane distribution operation entered into a swap agreement to protect the Companyit from the impact of price increases on the Pro-Cap (propane price-cap) Plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as describedpropane prices declined significantly in SFAS No. 133. At the endlate 2008 and we recorded a mark-to-market adjustment of the period, the market priceapproximately $939,000, which increased our cost of propane dropped below the unit price in the swap agreement. As a result of the price drop, the Company marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales in 2008 by approximately $939,000.2008. In January 2009, the Companywe 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

Chesapeake’s
Xeron, our propane wholesale marketing operationsubsidiary, enters into forward, futures and futuresother contracts that are considered derivatives under SFAS No. 133. In accordance with SFAS No. 133, 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 or expense. TheThese contracts generally mature within one year and are almost exclusively for propane commodities, with delivery points at 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. Commodity price volatility may have a significant impact on the gain or loss in any given period. Atyears ended December 31, 2009 and 2008, these contracts had net unrealized losses of $1.6 million and net unrealized gains of $1.4 million, that were recorded in the financial statements. At December 31, 2007, these contracts had net unrealized gains of $179,000 that were recorded in the financial statements.respectively.
Operating Revenues
Revenues for theour natural gas and electric distribution operations of the Company are based on rates approved by the PSCs of the jurisdictions in which we operate. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have 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. In addition, the natural gas transmission operation canThe 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.
Page 32     Chesapeake Utilities Corporation 2008 Form 10-K

For regulated deliveries of natural gas Chesapeake readsand electricity, we read meters and billsbill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accruesWe accrue unbilled revenues for natural gas and electricity that hashave been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, Chesapeakewe must estimate the amountamounts of natural gas and electricity that hashave not been accounted for on itsour delivery systemsystems and must estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers.customers, and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in the Company’sour income statement. TheFor 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.
Chesapeake’sEach of our natural gas distribution operations in Delaware and Maryland, each haveour bundled natural gas distribution service in Florida and our electric distribution operation in Florida has a purchased gasfuel cost recovery mechanism. This mechanism provides the Companyus with a method of adjusting the billing rates with itsto customers forto reflect changes in the cost of purchased gas included in base rates.fuel. The difference between the current cost of gasfuel purchased and the cost of gasfuel recovered in billed rates is deferred and accounted for as either unrecovered purchased gasfuel costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.
The Company chargesWe charge flexible rates to itsindustrial interruptible customers on our natural gas distribution industrial interruptible customerssystems to compete with the price of alternative types of fuel. Based on pricing, these customersfuel that they can choose natural gas or alternative fuels.use. Neither the Company nor theits interruptible customercustomers is contractually obligated to deliver or receive natural gas.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 otherOther 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 returnreturns on plan assets, assumed discount rates, the level of contributions made to the plans, current demographic and actuarial mortality data. The assumed discount raterates and the expected returnreturns on plan assets are the assumptions that generally have the most significant impact on the Company’s pension costs and liabilities. The assumed discount rate,rates, the assumed health care cost trend raterates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Note L, “Employee Benefit Plans,” inItem 8 under the Notesheading “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 $387,000 in 2008, 2007, and 2006, respectively.  The companyCompany expects to record higher pension and postretirement benefit costs in the range of $400,000$900,000 to $600,000$1.0 million for 2009. The increased costs for 2009 represents the significant market decline in the values2010 of the definedwhich $275,000 is attributed to FPU’s pension plan assets when compared to prior years.and medical plans.   Actuarial assumptions affecting 20092010 include an expected long-term raterates of return on plan assets of 6.0 percent consistent with the prior year,and 7.0 percent for Chesapeake’s pension plan and FPU’s pension plan, respectively, and discount rates of 5.25 percent for each of the plans, compared with 5.5and 5.50 percent for the plans a year earlier.Chesapeake’s plan and FPU’s plan, respectively.  The discount ratesrate for each plan werewas determined by the Companymanagement 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 lifelives of the planplans 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 20082009 Form 10-K     Page 33

 

 

Management’s DiscussionThe 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 Analysismerger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining proper accounting treatment for the merger-related costs. During 2009, we incurred approximately $3.0 million to consummate the merger, including the cost associated with merger-related litigation, and to integrate operations following the merger. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at December 31, 2009, which represents our best estimate, based on similar proceedings in Florida in the past, of the costs, which we expect to be permitted to recover when we complete the appropriate rate proceedings. The remaining $1.5 million in costs have been expensed in our 2009 results.
(d) Results of Operations
                         
(in thousands except per share)         Increase          Increase 
For the Years Ended December 31, 2009  2008  (decrease)  2008  2007  (decrease) 
Business Segment:
                        
Regulated Energy $26,900  $24,733  $2,167  $24,733  $21,809  $2,924 
Unregulated Energy  8,158   3,781   4,377   3,781   5,174   (1,393)
Other  (1,322)  (35)  (1,287)  (35)  1,131   (1,166)
                   
Operating Income
  33,736   28,479   5,257   28,479   28,114   365 
                         
Other Income  165   103   62   103   291   (188)
Interest Charges  7,086   6,158   928   6,158   6,590   (432)
Income Taxes  10,918   8,817   2,101   8,817   8,597   220 
                   
Net Income from Continuing Operations  15,897   13,607   2,290   13,607   13,218   389 
Loss from Discontinued Operations  —   —   —   —   (20)  20 
                   
Net Income
 $15,897  $13,607  $2,290  $13,607  $13,198  $409 
                   
Diluted Earnings (Loss) Per Share
                        
Continuing operations $2.15  $1.98  $0.17  $1.98  $1.94  $0.04 
Discontinued operations  —   —   —   —   —   — 
                   
Diluted Earnings Per Share $2.15  $1.98  $0.17  $1.98  $1.94  $0.04 
                   
As a result of the merger with FPU in 2009, we changed our operating segments to better align with how the chief operating decision maker (our Chief Executive Officer) views the various operations of the Company. We revised the segment information for all periods presented to reflect the new operating segments. Also during 2009, we decided not to allocate merger-related costs to our operating segments for the purpose of reporting their operating profitability, because such costs are not directly attributable to their operations. Consequently, all of the $1.5 million and $1.2 million of merger-related costs expensed in 2009 and 2008, respectively, are included in “Other” segment.
2009 compared to 2008
Our net income increased by approximately $2.3 million in 2009 compared to 2008. Net Income & Diluted Earnings Per Share Summaryincome 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.
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
Net Income (Loss)*
                        
Continuing operations $13,607  $13,218  $389  $13,218  $10,748  $2,470 
Discontinued operations  —   (20)  20   (20)  (241)  221 
                   
Total Net Income $13,607  $13,198  $410  $13,198  $10,507  $2,691 
                   
Diluted Earnings (Loss) Per Share
                        
Continuing operations $1.98  $1.94  $0.04  $1.94  $1.76  $0.18 
Discontinued operations  —   —   —   —   (0.04)  0.04 
                   
Total Earnings Per Share $1.98  $1.94  $0.04  $1.94  $1.72  $0.22 
                   
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.
*
Dollars in thousands.
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.
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 Company’sDelmarva propane distribution operation contributed most of the increase in operating income by this segment. Delmarva propane distribution operation recorded $1.8 million in unfavorable propane inventory and swap valuation adjustments in 2008, which did not recur in 2009. These adjustments to the inventory costs in late 2008 and relatively low propane prices during the first half of 2009 allowed the Delmarva propane distribution operation to maintain low propane inventory costs while sustaining its retail margins. Operating income for the “Other” segment decreased by $1.3 million, primarily due to lower operating results by the advanced information services operation and higher merger-related costs expensed in 2009. The operating results of the advanced information services operation continued to be negatively affected by the lower levels of information technology spending experienced in the economy at large.
During 2009, we recognized increased corporate overhead costs of $1.2 million compared to 2008, which were allocated to all of our segments. Payroll and benefits costs in corporate overhead increased by $961,000 and $225,000, respectively, due to higher incentive compensation based on improved operating results and increased costs associated with filling several key corporate positions in 2008 and 2009. Also contributing to the increase were additional costs associated with investor relations and financial reporting activities and increased pension costs as a result of a decline in the value of pension investments in late 2008.
An increase of $928,000 in interest charges in 2009 compared to 2008 partially offset the increased operating results. This increase reflects primarily the interest expense on FPU’s long-term debt and customer deposits and the placement of the $30 million Unsecured Senior Notes in October 2008.
We continued to invest in property, plant and equipment in 2009 to support current and future growth opportunities, expending $26.3 million for such purposes.
2008 Compared to 2007
Our net income from continuing operations increased by $389,000 in 2008 compared to 2007. Net income from continuing operations was $13.6 million, or $1.98 per share (diluted), for 2008, compared to net income from continuing operations of $13.2 million, or $1.94 per share (diluted), in 2007. Our 2008 results include a charge of $1.2 million to other operating expenses for merger-related costs relating to an unconsummated acquisition. The Company initiated discussions in the third quarter of 2007 with a potential acquisition target. These discussions continued through the first part of the second quarter of 2008, at which time, we determined that we would not be able to complete the acquisition. In the course of these negotiations, the Company incurred certain accounting, legal and other professional fees and expenses, which were expensed in the second quarter of 2008 in accordancewhen our initial merger discussions with SFAS No. 141, “Business Combinations.”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).
The Company’s net income from continuing operations increased by $2.5 million in 2007 compared to 2006. Net income from continuing operations was $13.2 million, or $1.94 per share (diluted), for 2007, compared to net income from continuing operations of $10.8 million, or $1.76 per share (diluted) in 2006.Page 40     Chesapeake Utilities Corporation 2009 Form 10-K

During 2007, Chesapeakewe decided to close itsthe distributed energy services company, Chesapeake OnSight Services, LLC (“OnSight”), which consistently experienced operating losses since 2004. The results of operations for OnSight have been reclassifiedwere classified to discontinued operations and shown net of tax for all periods presented.tax. The discontinued operations experienced a net loss of $20,000 for 2007,2007.
Our operating income increased by $365,000 in 2008 compared to a net loss of $241,000, or $0.04 per share (diluted) for 2006. The Company did not have any discontinued operations2007, including $1.2 million in 2008.
Page 34     Chesapeake Utilities Corporationmerger-related costs expensed in 2008, Form 10-K

Operating Income Summary (in thousands)
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
Business Segment:
                        
Natural gas $25,846  $22,485  $3,361  $22,485  $19,733  $2,752 
Propane  1,586   4,498   (2,912)  4,498   2,534   1,964 
Advanced information services  695   836   (141)  836   767   69 
Other & eliminations  352   295   57   295   298   (3)
                   
Operating Income
 $28,479  $28,114  $365  $28,114  $23,332  $4,782 
                         
Other Income  103   291   (188)  291   189   102 
Interest Charges  6,158   6,590   (432)  6,590   5,774   816 
Income Taxes  8,817   8,597   220   8,597   6,999   1,598 
                   
Net Income from Continuing Operations
 $13,607  $13,218  $389  $13,218  $10,748  $2,470 
                   
2008 Compared to 2007
which are included in the “Other” segment. Operating income in 2008from recurring operations increased by approximately $365,000, or one percent,$1.5 million in 2008 compared to 2007. The financial, operational and other highlights or factors affecting the period-over-period changeOur regulated energy segment achieved an increase of $2.9 million in operating income includedfrom new services provided by the following:
For the Company’s natural gas marketing operation, enhanced sales contract terms, margins on spot sales of approximately $600,000 and a 26 percent growth in its customer base produced a period-over-period increase of $1.5 million, or 91 percent, in gross margin.
New long-term, transportation capacity contracts implemented by ESNG in November 2007 provided for 8,300 Dts of additional firm transportation service per day, generating $200,000 of gross margin in 2007 and $1.0 million in 2008 for an annualized gross margin of $1.2 million.
On January 7, 2008, ESNG received authorization from the FERC to commence construction of a portion of the Phase III facilities (approximately 9.2 miles) of the 2006-2008 System Expansion Project. These additional facilities, which were completed and placed in service on November 1, 2008, provided for 5,650 Dts of additional firm transportation service per day, generating $165,000 of gross margin in 2008 and annualized gross margin of $988,000.
The results of rate proceedings for the Company’s natural gas transmission and Delmarvaoperation, four-percent customer growth for Chesapeake’s natural gas distribution operations added $387,000 to gross margin in 2008. Theseand the successful completion of the Delaware rate proceedings also provided for lower depreciation allowances and lower asset removal cost allowances, which contributed to the period-over-periodproceedings. Our unregulated energy segment experienced a decrease in depreciation expense and asset removal costsoperating income of $2.3$1.4 million, in 2008.
Volatile wholesale propane prices in 2008 provided a gross margin increase of $901,000 for the Company’s propane wholesale and marketing subsidiary.
Despite the continued slowdown in new residential housing constructionprimarily as a result of recording $1.8 million in unfavorable economic conditions,propane inventory and swap valuation adjustments for the Company’s natural gasDelmarva propane distribution operations continuedin the second half of 2008. The propane inventory valuation adjustments were recorded to experience strong customer growth with a four percent increase in 2008.
Decliningadjust the value of propane inventory and price swap agreements to current market prices as propane prices declined significantly during the second half of 2008 had a negative impact on operating2008. Operating income for the propane distribution operations as the Company adjusted the valuation of its propane inventory to current market prices in accordance with Accounting Research Bulletin No. 43. These adjustments reduced gross margin“Other” segment decreased by $800,000 during 2008. In addition, the Company recognized a charge of $939,000 to cost of sales as January 2009 and February 2009 gallons in its price swap agreement were marked–to–market as of the end 2008.
As previously discussed, a charge of $1.2 million fordue to the merger-related costs.
During 2008, we experienced increased corporate overhead costs, relatingwhich were allocated to an unconsummated acquisition increased other operating expenses.
Corporate overhead increasedall of our segments. The increase of $519,000 in corporate overhead costs in 2008 duecompared 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. In addition,2008 and increased outside services increasedof $263,000 duewere incurred primarily tofor consulting costs relating to an independent third-party compensation survey, strategic planning and growth initiatives. As a result
A decrease of the compensation survey, the Company implemented salary adjustments, effective January 1, 2009, that will increase payroll related costs by approximately $754,000$432,000 in 2009.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 35

Management’s Discussion and Analysis
The Company continued to invest in property, plant and equipment to support current and future growth opportunities, expending $30.8 millioninterest charges in 2008 for such purposes.
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 current financial crisis, Chesapeake waswe were able to firm up itsour credit lines during this volatile period by increasing itsour total committed short-term borrowing capacity from $15.0 million to $55.0 million. In addition, on October 31, 2008, the Companywe 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 
                   
20072009 Compared to 20062008
Compared to 2006, operatingOperating income in 2007for the regulated energy segment increased by $4.8approximately $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. Factors affecting this improvement included the following:
New transportation capacity contracts implementedFPU’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 transmissiondistribution 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 November 20062009 was lower than the growth experienced in recent years and November 2007 provided for $3.3 million of additional gross marginwe expect that trend to continue in 2007.the near future.
WeatherColder weather on the Delmarva Peninsula was 15 percent colder in 2007 than in 2006, which,contributed $449,000 to the Company estimates contributed approximately $2.0 million in additionalincreased gross margin, for its Delmarva natural gas and propane distribution operations. This amount differs from the $2.2 million of additional gross margin that the Company had expected the colder weather to contribute, as a result of the seasonheating degree days increased by 298, or month that the heating degree-day variance occurred.
Rate increases to customers of the natural gas transmission and distribution operations in Delaware and Maryland added $1.4 million to gross margin in 2007.
Strong period-over-period residential customer growth of seven percent, and five percent, respectively, was achieved for the Delmarva and Florida natural gas distribution operations in 2007.
The average gross margin per retail gallon soldcompared to customers increased by $0.05 in 2007 for the Delmarva propane distribution operations, which contributed $1.1 million to gross margin.2008.
The Delmarva Community Gas Systems continued to experience strong customer growth as the number of customers increased by 22 percent in 2007.
Natural Gas
The natural gas segment recognized operating income of $25.8 million for 2008, $22.5 million for 2007, and $19.7 million for 2006, representing increases of $3.4 million, or 15 percent for 2008, and $2.8 million, or 14 percent for 2007.
Page 3642     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
(in thousands)                        
Revenue $211,402  $181,202  $30,200  $181,202  $170,374  $10,828 
Cost of gas  146,546   121,550   24,996   121,550   117,948   3,602 
                   
Gross margin  64,856   59,652   5,204   59,652   52,426   7,226 
 
Operations & maintenance  26,579   26,024   555   26,024   22,673   3,351 
Unconsummated acquisition costs  828   —   828   —   —   — 
Depreciation & amortization  6,694   6,918   (224)  6,918   6,312   606 
Other taxes  4,909   4,225   684   4,225   3,708   517 
                   
Other operating expenses  39,010   37,167   1,843   37,167   32,693   4,474 
                   
Total Operating Income
 $25,846  $22,485  $3,361  $22,485  $19,733  $2,752 
                   
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.
Heating Degree-Day (HDD) and Customer Analysis
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.
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
Heating degree-day data — Delmarva                        
Actual HDD  4,431   4,504   (73)  4,504   3,931   573 
10-year average HDD  4,401   4,376   25   4,376   4,372   4 
                         
Estimated gross margin per HDD $1,937  $1,937  $0  $1,937  $2,013  $(76)
                   
                         
Estimated dollars per residential customer added:                        
Gross margin $375  $372  $3  $372  $372  $0 
Other operating expenses $103  $106  $(3) $106  $111  $(5)
                   
                         
Average number of residential customers                        
Delmarva  45,570   43,485   2,085   43,485   40,535   2,950 
Florida  13,373   13,250   123   13,250   12,663   587 
                   
Total  58,943   56,735   2,208   56,735   53,198   3,537 
                   
2008 Compared to 2007
Gross margin for the Company’sChesapeake’s Florida natural gas segment increased by $5.2 million, or nine percent, and other operating expenses increased by $1.8 million, or five percent, for 2008. Of the total $5.2 million increasedistribution operation experienced a decrease in gross margin $1.7 millionof $333,000, in 2009. This decrease was generated fromattributable 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 natural gas transmission operation, $2.0 million fromregion. This decrease was partially offset by an increase to gross margin of $99,000 due to implementation of interim rates in the natural gas distribution operations and $1.5 million from the natural gas marketing operation, as further explained below.
Natural Gas Transmissionthird quarter of 2009.
The natural gas transmission operationoperations achieved gross margin growth of $1.7$2.5 million or eight percent, in 2008. Of the $1.7 million2009. The factors contributing to this increase $1.2 million was attributable to new transportation capacity contractsare as follows:
New long-term transmission services implemented by ESNG in November 2007of 2008 and 2008. In 2009, the new transportation capacity contracts implemented in November 2008 are expected to generate additional gross margin of $823,000. In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributedwhich provided for an additional $439,0005,459 Mcfs per day and 3,976 Mcfs per day, respectively, added $939,000 to gross margin in 2008. A further discussion of the FERC rate proceeding is provided in detail within “Rates and Other Regulatory Activities” section of Note O, “Other Commitments and Contingencies,” in the Notes to the Consolidated Financial Statements. The remaining $61,000 increase to gross margin was primarily attributable to higher interruptible sales revenue, net of required margin-sharing.
The 2009 gross margin for the natural gas transmission operation will be impacted by the following construction projects:
The remaining facilities to be constructed under the operation’s multi-year system expansion will be placed into service in November 2009. These services will provide for 7,200 dts of firm service capacity per day and will generate $1.0 million of annualized gross margin. For the years 2009 and 2010, these facilities will contribute $169,300 and $846,700, respectively, to gross margin.
On February 5, 2009, ESNG entered into aNew firm transportation service agreement withtransmission services provided to an industrial customer in Northern Delaware for the period of February 6, 2009 through October 31, 2009. Pursuant to this agreement, ESNG will provide firm transportation service for a maximum of 7,200 Dts and will recognize gross margin of approximately $573,000 for this service. Subsequent to execution of this agreement, the two parties entered into a second Precedent Agreement2009, provided for an additional 10,000 Dts of daily6,957 Mcfs per day and added $574,000 to gross margin. In addition, ESNG entered into two additional firm transportationtransmission service beginningagreements 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 ending(2) 9,662 Mcfs per day from November 1, 2009 through October 31, 2012. In conjunction with providing this service, ESNG expects2012, which added $181,000 to earn additional gross margin of approximately $1.1 million. For the yearsin 2009 and 2010, these two agreements will contribute $753,900 and $1.1 million respectively,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.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 20082009 Form 10-K     Page 3743

 

 

Management’s Discussion
Increased information technology spending to continuously enhance our information technology infrastructure and Analysis
An increaselevel of $669,000 in other operating expenses partially offset thesupport generated increased gross margin. The factors contributing to the increase in other operating expenses included the following:costs of $285,000.
Corporate overhead allocated to the regulated energy segment increased by approximately $420,000$722,000 due to the allocation of the unconsummated acquisition costs and the higher costsfactors previously discussed.
Other Developments
The higher levelfollowing developments, which are not discussed above, may affect the future operating results of capital investmentthe 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 adjusted property assessmentsthe 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 various jurisdictions caused increased property taxesapproximately $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 $311,000.approximately $54,000.
Rent and utility expenses increasedIn 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 $176,000 and $52,000, respectively, as a resultthe Florida PSC in May 2009; however, in June 2009, certain parts of ESNG occupying new office facilities in Januarythe order were protested by the Office of 2008.
Incentive compensation costs increased by $98,000 asPublic Counsel. The settlement provides for an annual rate increase of approximately $8.0 million. As a result of the improved operating resultssettlement, FPU refunded approximately $290,000 to its customers in 2008.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.
CostsThe Delaware division is currently involved in a regulatory proceeding regarding the price it charged for corporate services increasedthe 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 $97,000$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 resultliability for this contingency based on our current assessment of increased information technology spendingthe case. We anticipate a ruling by the Delaware PSC in March 2010. Item 8 under the heading, “Notes to improve the infrastructure, including system performanceConsolidated Financial Statements – Note P, Other Commitments and disaster recovery. In addition, the Company increased its information technology support.Contingencies” provides further discussions on this matter.
Other operating expenses relating2008 Compared to various items2007
Operating income for the regulated energy segment increased by approximately $77,000.
The Company experienced a decrease of $316,000$2.9 million in pipeline integrity costs,2008 compared to those2007, which the Company incurred in 2007was attributable to comply with federal pipeline integrity regulations, issued in May 2004.
Depreciationa gross margin increase of $3.7 million, offset partially by an operating expense and regulatory expense decreased by $110,000 and $136,000, respectively, in 2008 as a resultincrease of the 2007 rate case. As part of the rate case settlement that became effective September 1, 2007, the FERC approved a reduction in depreciation rates for ESNG. The impact of the lower depreciation rates was partially offset by the additional depreciation expense from higher plant balances produced by capital investments in 2007 and 2008. Also, the Company incurred regulatory expenses in the first nine months of 2007 associated with the FERC rate proceeding.
$766,000.
Natural Gas DistributionGross Margin
Gross margin for our regulated segment increased by $3.7 million, or six percent, of which $2.0 million was attributable to the Company’s natural gas distribution operations increased by $2.0and $1.7 million or five percent, for 2008 compared to 2007. Of the $2.0 million increase, $1.8 million was produced by thenatural gas transmission operation.
The Delmarva natural gas distribution operations and $200,000 by the Florida natural gas distribution operations.
Contributinggenerated an increase to the Delmarva distribution operations’ increasegross margin of $1.8 million or seven percent, in gross margin, weredue to the following factors:
The average number of residential customers on the Delmarva Peninsula increased by 2,085, or five percent, for 2008, and the Company estimateswe estimate that these additional residential customers contributed approximately $850,000 to gross margin in 2008. The Company continues to see a slowdown in the new housing market as a result of unfavorable market conditions.
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

The Company estimates
We estimate that weather contributed $122,000 to gross margin, despite temperatures on the Delmarva Peninsula being two percent warmer in 2008. This amount differs from the $141,000 reduction of gross margin that the Company had expected from the warmer weather as a result of the month in which the heating degree day variance occurred.
Page 38     Chesapeake Utilities Corporation 2008, Form 10-Kcompared to 2007.

Partially offsetting these increases to gross margin was the negative impact of lower consumption per customer in 2008 compared to 2007. The Company estimatesWe 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.
The remaining $77,000 net increase to gross margin was attributable to various other items.
Gross margin for the Florida natural gas distribution operation increased by $200,000 or two percent, in 2008, compared to 2007. The higher gross margin for the period was attributable primarily to a one-percent growth in residential customers, an increase in non-residential customer volumes, and higher revenues from third-party natural gas marketers.
Other operating expenses for the natural gas distribution operations increased by $909,000 in 2008 compared to 2007. Among the key components producing this net increase were the following:
Corporate overhead increased approximately $777,000 due to the allocation of the unconsummated acquisition costs and the higher costs previously discussed.
Costs for corporate services increased approximately $420,000 as a result of increased information technology spending to improve the infrastructure, including system performance and disaster recovery. In addition, the Company increased its information technology support.
Property taxes increased by $298,000 as a result of the Company’s continued capital investments.
Incentive compensation increased by $225,000 as the Delmarva and Florida operations experienced improved earnings compared to the prior year.
Costs relating to outside services, such as legal fees and consulting costs, increased by $208,000 to support several new projects.
Payroll and benefits costs for the Delmarva operations increased by $187,000 and $97,000, respectively, from annual salary increases, as compared to the previous year.
Regulatory expenses increased by $126,000 as the natural gas distribution operations incurred costs associated with regulatory filings with their respective PSCs.
Vehicle fuel and depreciation expense increased by $68,000 and $57,000, respectively, compared to the prior year as a result of rising costs of gasoline and diesel fuel, and higher depreciation rates for vehicles.
Depreciation expense and asset removal costs decreased by $114,000 and $1.3 million, respectively, primarily as a result of the Delmarva operations’ rate proceedings, which provided for lower depreciation allowances and lower asset removal cost allowances.
Maintenance costs for the Florida operation decreased by $66,000, compared to 2007, when larger expenditures were required to comply with federal pipeline integrity regulations.
Merchant payment fees decreased by $79,000, which resulted primarily from the Delmarva operations outsourcing the processing of credit card payments in April 2007.
In addition, other operating expenses relating to various other items increased by approximately $5,000.
Natural Gas Marketing
Gross margin for the natural gas marketing operation increased by $1.5 million, or 91 percent, 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 a 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 increased by $264,000, which was attributable to higher incentive compensation incurred as a result of the improved operating results and increases in the allowance for uncollectible accounts that normally accompany customer growth; these expenses were offset slightly by lower payroll-related and benefit costs.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 39

Management’s Discussion and Analysis
2007 Compared to 2006
Gross margin for the Company’s natural gas segment increased by $7.2 million, or 14 percent, and other operating expenses increased by $4.5 million, or 14 percent, for 2007 compared to 2006. Of the total gross margin increase of $7.2 million, $3.9 million was generated by the natural gas transmission operation and $3.5 million was generated by the natural gas distribution operations. These increases were partially offset by a lower gross margin of $207,000 for the natural gas marketing operation, as further explained below.
Natural Gas Transmission
The natural gas transmission operation achieved gross margin growth of $3.9$1.7 million or 22 percent, in 2007 compared to 2006. Of the $3.92008, $1.2 million increase, $3.3 millionof which was attributable to transportationnew transmission capacity contracts implemented in November 20062007 and 2007.2008. In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $563,000$439,000 to gross margin in 2007.2008. The remaining $43,000$61,000 increase to gross margin in 2007 iswas attributable primarily to other factors, such as higher interruptible sales. An increasesales revenue, net of $2.3 million in otherrequired margin-sharing.
Other Operating Expenses
Other operating expenses partially offsetfor the regulated energy segment increased gross margin. The factors contributingby approximately $766,000, due primarily to the increase in other operating expenses were as follows:following factors:
Payroll and benefit costs increased by $282,000$486,000 and $90,000,$152,000, respectively, as the operationreflecting annual compensation increases and increased staff to support compliance with new federal pipeline integrity regulations and to serve the additional growth. The new pipeline integrity regulations require the Company to assess at least 50 percent of the covered segments by December 17, 2007.
ESNG also incurred an additional $385,000Depreciation expense and asset removal costs decreased by approximately $1.5 million, primarily as a result of third-party costs to comply withour Delaware distribution operation’s rate proceedings in 2008 and ESNG’s rate settlement in September 2007, which provided for lower depreciation and asset removal cost allowances. Higher depreciation expense from the new federal pipeline integrity regulations previously discussed.
The increased level of capital investment causedpartially offset this decrease in 2008.
Property taxes increased by approximately $609,000 due to the higher level of capital investment and adjusted property assessments by various jurisdictions.
Vehicle-related costs increased by $132,000 due to higher fuel and depreciation charges.
Information technology costs increased by approximately $517,000 as a result of higher spending to improve the infrastructure, including system performance, disaster recovery and asset removal costs of $371,000 and increased property taxes of $188,000.support.
Corporate overhead costs allocated to the regulated energy segment increased by $568,000approximately $385,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC.previously discussed.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 45

The increase in operating expenses
Unregulated Energy
                         
          Increase          Increase 
For the Years Ended December 31, 2009  2008  (decrease)  2008  2007  (decrease) 
(in thousands)                        
 
Revenue $119,973  $161,290  $(41,317) $161,290  $115,190  $46,100 
Cost of sales  90,408   138,302   (47,894)  138,302   91,727   46,575 
                   
Gross margin  29,565   22,988   6,577   22,988   23,463   (475)
                         
Operations & maintenance  18,016   16,322   1,694   16,322   15,559   763 
Depreciation & amortization  2,415   2,024   391   2,024   1,842   182 
Other taxes  976   861   115   861   888   (27)
                   
Other operating expenses  21,407   19,207   2,200   19,207   18,289   918 
                   
 
Operating Income
 $8,158  $3,781  $4,377  $3,781  $5,174  $(1,393)
                   
Propane Heating Degree-Day (HDD) Analysis — Delmarva
                         
          Increase          Increase 
For the Years Ended December 31, 2009  2008  (decrease)  2008  2007  (decrease) 
Heating degree-days                        
Actual  4,729   4,431   298   4,431   4,504   (73)
10-year average  4,462   4,401   61   4,401   4,376   25 
                         
Estimated gross margin per HDD $3,083  $2,465  $618  $2,465  $1,974  $491 
2009 compared to 2008
Operating income for 2007 was magnified by the FERC’s authorization, in July 2006, to defer certain pre-service costs of ESNG’s Energylink Expansion Project (“E3 Project”), allowing the Company to treat such costs as a regulatory asset. The deferral of these costs resulted in the reduction of $190,000 in other operating expenses in 2006 for expenses incurred in 2005. Please refer to the “Rates and Other Regulatory Activities” section of Note O, “Other Commitments and Contingencies,” in the Notes to the Consolidated Financial Statements further information on the E3 Project.
Other operating expenses relating to various itemsunregulated energy segment increased collectively by approximately $226,000.
$4.4 million in 2009 compared to 2008, which was attributable to a gross margin increase of $6.6 million, offset partially by an operating expense increase of $2.2 million.
Natural Gas DistributionGross 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 Company’speriod from the merger closing (October 28, 2009) to December 31, 2009.
PESCO, our natural gas distribution operations increased by $3.5 million, or eleven percent, for 2007 compared to 2006. The gross margin increases for the Delmarva and Florida natural gas distribution operations are further explained below.
The Delmarva distribution operationsmarketing operation, experienced an increase in gross margin of $3.4$1.0 million or 16 percent. The significant items contributingin 2009. PESCO increased its sales volume by 13 percent in 2009 compared to the increase in gross margin included the following:
Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers2008, as it benefited from increased spot sale opportunities on the Delmarva Peninsula increased by 2,950, or seven percent, for 2007 comparedduring 2009, which contributed significantly to 2006, and the Company estimates that these additional residential customers contributed approximately $1.2 million to gross margin.
Rate increases for both the Delaware and Maryland divisions generated an additional $848,000 in 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 2007 compared to 2006. In October 2006,2009 and lower propane costs, coupled with sustained retail prices, contributed $3.5 million of the Maryland PSC granted the Company a base rate increase, whichgross margin increase. A sharp decline in propane prices in late 2008 resulted in a $693,000 period-over-period increaseloss 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 gross margin in 2007. The Delaware division received approval from the Delaware Public Service Commission (“Delaware PSC”) to implement temporary rates, subject to refund, which contributed an additional $155,000 to gross margin in 2007.
The Company estimates thatkeep its propane cost low. Colder weather contributed $819,000 to gross margin in 2007 compared to 2006, as temperatures on the Delmarva Peninsula in 2009 increased gross margin by $1.2 million, as temperatures were 15seven percent colder in 2007. This amount differs2009, compared to 2008. Gross margin for the Florida propane distribution operation in 2009 remained unchanged from the $1.1 million of additional2008 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 thatof $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 had expectedlarger spreads between the colder weathermarket (spot) prices and forward prices. Overall lack of volatility in wholesale propane prices in 2009, compared to contribute as a result of the month in which the heating degree day variance occurred.
2008, reduced such revenue opportunities and its trading volume by 57 percent.
Page 4046     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Other Operating Expenses
The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in 2007, because the operation’s approved rate structure included a weather normalization adjustment mechanism. The weather normalization adjustment, implemented in October 2006, was designed to reduce excessive revenue swings caused by weather that is warmer or colder than normal.
Growth in commercial and industrial customers contributed $224,000 and $102,000, respectively, to gross margin in 2007.
Increased sales volumes to interruptible customers contributed $224,000 to gross margin in 2007.
The remaining $31,000 increase in gross margin can be attributed to variousTotal other factors.
Gross margin for the Florida distribution operation increased by $88,000, or one percent, in 2007 compared to 2006. The higher gross margin, which resulted from an increase in residential customers, was partially offset by lower volumes sold to industrial customers. The operation experienced a five-percent growth in residential customers in 2007 compared to 2006, which provided for an additional $142,000 in gross margin. The Florida distribution operation also experienced a slowdown in the housing market in 2007.
Other operating expenses for the natural gas distribution operationsunregulated energy segment increased by $2.0$2.2 million in 2007 compared2009, of which $1.2 million was related to 2006. Amongother operating expenses of FPU during the key components ofperiod from the merger closing (October 28, 2009) to December 31, 2009. The remaining increase werein other operating expenses is due primarily to the following:following factors:
Payroll costs increased by $110,000 as vacant positions$301,000 in 2006 were filled in 2007 and new positions were added2009 compared to serve the growth experienced by the operations.2008 due to annual salary increases.
Health careBenefit costs increased by $177,000$167,000, due primarily to increased pension costs in 2009 as a result of additional personnel and a higher costthe decline in the value of claims.
Incentive compensation increased by $229,000 in 2007 as the Delmarva operations experienced improved earnings and increased staffing levels.pension plan assets.
Depreciation and amortization expense asset removal cost and property taxes increased by $316,000, $121,000 and $156,000, respectively,$249,000 as a result ofwe continued to make capital investments.investments in the propane distribution operations.
The Florida distribution operation experienced increased expenseAdditional costs of $227,000approximately $115,000 were incurred in 20072009 to maintain propane tanks in compliance with the new federal pipeline integrity regulations.United States Department of Transportation standards.
Sales and advertising costs increased by $129,000 in 2007, primarilyCorporate overhead allocated to promotethe unregulated energy conservation and customer awareness of the availability of natural gas service.
Regulatory expenses increased by $113,000 as the Delaware and Maryland operations began expensing costs associated with their respective rate cases.
The allowance for uncollectible accounts increased by $183,000 in 2007 due to increased revenues resulting from customer growth and colder temperatures.
Merchant payment fees decreased by $116,000 as the Company’s Delmarva operation outsourced the processing of credit card payments in April 2007.
Other operating expenses relating to various other itemssegment increased by approximately $355,000.$568,000 as previously discussed.
Natural Gas Marketing
Gross margin for the natural gas marketing operation decreased by $207,000, or 11 percent, for 2007 compared to 2006. The decline in gross margin was primarily the result ofThese increases in natural gas supply costs that PESCO was contractually unable to pass through to its customers. In addition, a shift in the market prevented PESCO from selling as much of its available capacity in 2007 as was sold during 2006. Other operating expenses for the marketing operation increased by $258,000 due primarily to increases in payroll and benefit costs, allowance for uncollectible accounts and corporate overhead costs, which were partially offset by lower expenses for consulting services.vehicle-related costs of $176,000, primarily due to a decrease in the cost of fuel.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 41

Management’s Discussion and Analysis
PropaneOther 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 segment earneddistribution subsidiary, purchased the operating incomeassets of $1.6 million for 2008, $4.5 million for 2007,a regional propane distributor serving approximately 1,000 retail customers in Northampton and $2.5 million for 2006, resulting in a decrease of $2.9 million, or 65 percent for 2008, and an increase of $2.0 million, or 78 percent for 2007.Accomack, Virginia.
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
(in thousands)                        
Revenue $65,877  $62,838  $3,039  $62,838  $48,576  $14,262 
Cost of sales  46,066   41,038   5,028   41,038   30,780   10,258 
                   
Gross margin  19,811   21,800   (1,989)  21,800   17,796   4,004 
                         
Operations & maintenance  15,111   14,594   517   14,594   12,823   1,771 
Unconsummated acquisition costs  254   —   254   —   —   — 
Depreciation & amortization  2,024   1,842   182   1,842   1,659   183 
Other taxes  836   866   (30)  866   780   86 
                   
Other operating expenses  18,225   17,302   923   17,302   15,262   2,040 
                   
                         
Total Operating Income
 $1,586  $4,498  $(2,912) $4,498  $2,534  $1,964 
                   
Propane Heating Degree-Day (HDD) Analysis — Delmarva
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
Heating degree-days                        
Actual  4,431   4,504   (73)  4,504   3,931   573 
10-year average  4,401   4,376   25   4,376   4,372   4 
 
Estimated gross margin per HDD $2,465  $1,974  $491  $1,974  $1,743  $231 
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 operating incomegross margin of $475,000, or two percent, for the unregulated energy segment was due primarily to the Delmarva propane distribution operation, which experienced a lower$2.9 million in decreased gross margin from inventory write-downs and marking-to-market its swap agreement, warmer weather on the Delmarva Peninsula, and lower sales volumes.
The gross margin decrease of $3.1 million for the Delmarva propane distribution operations, which was partially offset by higherthe increase to gross margin of $181,000 for the Florida propane distribution operations and $901,000 for the propane wholesale and marketing operation as further explained below:
Delmarva Propane Distributionand $1.5 million for the natural gas marketing operation.
The Delmarva propane distribution operation’s decrease in gross margin of $3.1 million resulted from the following:
Gross margin decreased by $1.1 million in 2008, compared to 2007, primarily because of a $0.04 decrease in the average gross margin per retail gallon attributable to inventory write-downs of approximately $800,000 during 2008 in response to market prices below the Company’s inventory price per gallon. This trend reverses when market prices of propane exceed the Company’s average inventory price per gallon.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 47

Wholesale propane prices rose dramatically during the spring months of 2008, when they are traditionally falling.fall. In efforts to protect the Company from the impact that additional price increases would have on our Pro-Cap (propane price cap) Plan, that we offer to customers, the propane distribution operation entered into a swap agreement. By the end of the period, the market price of propane had plummeted well below the unit price in the swap agreement. As a result, the Companywe marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales by $939,000 in 2008. In January 2009, the Companywe terminated this swap agreement.
Non-weather-related volumes sold in 2008 decreased by 1.2 million gallons, or five percent. This decrease in gallons sold reduced gross margin by approximately $867,000 for the Delmarva propane distribution operation. Factors contributing to this decrease in gallons sold included customer conservation and the timing of propane deliveries.
Page 42     Chesapeake Utilities Corporation 2008 Form 10-K

Margins per gallon on the Pro-Cap planPlan for the last four months of 2008 recovered to a level just $113,000 below the prior year’s levels, with the exception of $113,000, despite the Company realizing a charge to cost of sales of $494,000 as the December gallons related to this plan were valued at current market prices.
Temperatures on the Delmarva Peninsula were two percent warmer in 2008 compared to 2007, which contributed to a decrease of 248,000 gallons sold, or one percent. The Company estimatesWe estimated that the warmer weather and decreased volumes sold had a negative impact of approximately $180,000 on gross margin for the Delmarva propane distribution operation.
Gross margin from miscellaneous fees, including items such as tank and meter rentals and marketing pricing programs, increased by $271,000.
The remaining $172,000 net decrease in gross margin can be attributed to various other items.
Total other operating expenses increased by $503,000 for the Delmarva propane operations in 2008, compared to 2007. The significant items contributing to this increase are explained below:
Corporate overhead increased by approximately $380,000 due to the allocation of the unconsummated acquisition costs and the higher costs previously discussed.
Vehicle fuel and maintenance costs increased by $235,000 as a result of higher gasoline and diesel fuel costs and continued maintenance of our delivery vehicles.
Costs for corporate services increased by approximately $120,000 as a result of increased information technology spending to improve the infrastructure, including system performance and disaster recovery. In addition, the Company increased its information technology support.
Mains fees increased by $81,000 in 2008, compared to 2007, as a result of added Community Gas Systems (“CGS”) customers. This expenditure will continue to increase as more CGS customers are added.
Depreciation and amortization expense increased by $81,000 as a result of an increase in the Company’s capital investments compared to the prior year.
The allowance for uncollectible accounts increased by $65,000 due to increased revenues.
Incentive compensation decreased by $387,000 as a result of the lower operating results in 2008.
Lower expenses of $199,000 were incurred in 2008 for propane tank recertifications and maintenance as the Company incurred these costs in 2007 to maintain compliance with DOT standards, which require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years thereafter.
Other operating expenses relating to various items increased by approximately $127,000.
Florida Propane Distribution
The Florida propane distribution operation experienced an increase in gross margin of $181,000 or 15 percent, in 2008, compared to 2007. The higher gross margin resulted from increases of four percent and ten10 percent in the number of gallons sold to residential and commercial customers, respectively, combined with a higher average gross margin per retail gallon. Other operating expenses increased by $163,000 in 2008, compared to 2007, due primarily to increases in depreciation expense and the allowance for uncollectible accounts.
Propane Wholesale and Marketing
Gross margin for the Company’s propane wholesale marketing operation increased by $901,000 or 38 percent, 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 partially offset by higher otherdue 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 of $257,000,for the unregulated energy segment increased by $918,000 due primarily to higher incentive compensation associated with increased earningsthe following factors:
Payroll and increased corporatebenefit costs associated with updating our annual corporate cost allocations.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 43

Management’s Discussion and Analysis
2007 Compared to 2006
Operating income for the propane segment increaseddecreased by $2.0 million to $4.5 million for 2007 compared to 2006. Gross margin in the Delmarva propane distribution operations increased by $3.2 million, compared to 2006,$186,000, due primarily to increases in the average retail margin per gallon and colder weather on the Delmarva Peninsula. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $100,000 and $677,000, respectively.
Delmarva Propane Distribution
The Delmarva propane distribution operation’s increase in gross margin of $3.2 million, or 22 percent, resulted from the following:
Gross margin increased by $1.1 million in 2007, compared to 2006, because of a $0.05 increase in the average gross margin per retail gallon. This increase occurs when market prices of propane exceed the Company’s average inventory price per gallon and reverses when market prices move closer to the Company’s average inventory price per gallon. Propane gross margin is also affected by changes in the Company’s pricing of sales to its customers.
Temperatures on the Delmarva Peninsula were 15 percent colder in 2007 compared to 2006, which contributed to the increase of 1.7 million retail gallons, or nine percent, sold during 2007. The Company estimates that the colder weather and increased volumes sold contributed $1.1 million to gross marginlower accrual for the Delmarva propane distribution operation in 2007 compared to 2006.
Non-weather related retail volumes sold in 2007 increased by 1.0 million gallons, or six percent. This increase in gallons sold contributed approximately $665,000 to gross margin for the Delmarva propane distribution operation compared to 2006. Contributing to the increase of gallons sold was the continued growth in the average number of CGS customers, which increased by 972 to a total count of 5,330, or a 22-percent increase, compared to 2006.
Wholesale volumes sold in 2007 increased by 2.9 million gallons, or 70 percent, which contributed approximately $119,000 to gross margin for the Delmarva propane distribution operation.
The remaining $216,000 increase in gross margin can be attributed to various other factors, including higher service sales and service fees.
Total other operating expenses increased by $1.5 million for the Delmarva propane operations in 2007, compared to the same period in 2006. The significant items contributing to this increase were:
Increased operating expenses for 2007 were magnified by the Company’s one-time recovery in 2006 of previously incurred costs of $387,000 from one of its propane suppliers in 2006. This recovery reimbursed the Company for fixed costs incurred in the removal of above-normal levels of petroleum by-products contained in approximately 75,000 gallons of propane that it purchased from the supplier. The recovery of these costs reduced other operating expenses in the first nine months of 2006.
Incentiveincentive compensation increased by $361,000 as a result of the improvedlower operating results in 2007.2008.
Health careVehicle-related costs increased by $119,000 as the Company experienced a higher cost of claims during the year.
The operation incurred an additional $233,000 expense for propane tank recertifications and maintenance to maintain compliance with DOT standards, which require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years thereafter.
Mains fees increased by $100,000$207,000 as a result of new CGS customers.higher fuel costs and continued maintenance of our delivery trucks.
Depreciation and amortization expense increased by $107,000$182,000 as a result of increasedan increase in our capital investments.investments, primarily in Community Gas Systems.
In addition, other operating expenses relatingThe allowance for uncollectible accounts increased by $436,000 due to various itemsincreased 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 $193,000.$153,000 as a result of higher spending to improve the infrastructure, including system performance, disaster recovery and support.
Florida Propane Distribution
The Florida propane distribution operation experienced an increase in gross margin of $100,000, or nine percent, in 2007 compared to 2006, primarily because of an increase in the average gross margin per retail gallon and higher service margins. Other operating expenses in 2007, compared to 2006,Corporate overhead costs increased by $223,000, primarily due to increases in payroll costs, insurance and depreciation expense.approximately $204,000 as previously discussed.
Page 4448     Chesapeake Utilities Corporation 20082009 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.
Propane Wholesale and MarketingGross margin
GrossThe period-over-period decrease in gross margin for the Company’s propane wholesale marketing“Other” segment was a result of a decrease in consulting revenues by the advanced information services operation increased by $677,000, or 40 percent,due primarily to a 28-percent decrease in 2007 compared to 2006. This increase reflects the larger number of market opportunities that arosebillable consulting hours, coupled with a decline in 2007, due to price volatilitytraining revenues. The reduction in the propane wholesale market,number of billable consulting hours is a result of current economic conditions in which exceeded the level of price fluctuations experiencedinformation technology spending has not rebounded. The decrease in 2006. The increase in gross marginconsulting revenues was partially offset by higher other operating expenses of $318,000, due primarily to higher incentive compensation based on the increased earnings in 2007.
Advanced Information Services
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. The advanced information services business contributed operating income of $695,000 for 2008, $836,000 for 2007, and $767,000 for 2006 resulting in a decrease of $141,000, or 17 percent for 2008, and an increase of $69,000, or nine percent for 2007.$218,000 from BravePoint’s professional database monitoring and support solution services, and increased product sales of $140,000. While there have been some improvement in recent months, we do not expect customers’ information technology spending to return to historical levels in the foreseeable future given the current economic climate.
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
(in thousands)                        
Revenue $14,720  $15,099  $(379) $15,099  $12,568  $2,531 
Cost of sales  8,033   8,260   (227)  8,260   7,082   1,178 
                   
Gross margin  6,687   6,839   (152)  6,839   5,486   1,353 
                         
Operations & maintenance  5,091   5,225   (134)  5,225   4,119   1,106 
Unconsummated acquisition costs  60   —   60   —   —   — 
Depreciation & amortization  175   144   31   144   113   31 
Other taxes  666   634   32   634   487   147 
                   
Other operating expenses  5,992   6,003   (11)  6,003   4,719   1,284 
                   
                         
Total Operating Income
 $695  $836  $(141) $836  $767  $69 
                   
Operating expenses
Other operating expenses decreased by $90,000 in 2009. The decrease in operating expenses was attributable primarily to the cost containment actions, including layoffs and compensation adjustments, implemented by the advanced information service operation in 2009 to reduce costs to offset the decline in revenues. This decrease was offset by the increased merger-related costs.
2008 Compared to 2007
Operating income for the “Other” segment decreased by approximately $1.2 million in 2008 compared to 2007, which was attributable to a gross margin decrease of $122,000 and an operating expense increase of $1.0 million.
Gross margin
Our advanced information services operation contributed most of the gross margin for the “Other” segment. Gross margin for theour advanced information services businessoperation declined by approximately $152,000, or two percent, and contributed operating income of $695,000 for 2008, a decrease of $141,000, or 17 percent, compared to 2007.
The period-over-period decrease in gross marginwhich was attributable to a decrease of $610,000 in consulting revenues as higher average billing rates were not able to overcome a nine-percent decrease in the number of billable consulting hours. The reduction in the number of billable hours iswas a result of current economic conditions in which information technology spending has broadly declined. The decrease in consulting revenues was partially offset with increased product sales and training revenues of $403,000 and $47,000, respectively. Given the current economic climate, BravePoint does not expect customers’ information technology spending to return to historical levels in the foreseeable future.
Other operating expenses remained relatively unchanged in 2008 compared to the prior year. Absent the unconsummated acquisition costs of $60,000 allocated to the advanced information services segment, other operating expenses in 2008 would have been $71,000, a difference of one percent.
2007 Compared to 2006
The advanced information services business experienced gross margin growth of approximately $1.4 million, or 25 percent, and contributed operating income of $836,000 for 2007, an increase of $69,000, or nine percent, compared to 2006.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 4549

 

 

Management’s Discussion and Analysis
The period-over-period increase of gross margin resultedin other operating expenses in 2008 was primarily from the following:
A strong demand for the segment’s consulting services in 2007 generated an increase of $1.9related to $1.2 million in consulting revenues asmerger-related costs in 2008 that were expensed in the numbersecond quarter of billable hours increased by 15 percent; and
An increase of $276,000 from Managed Database Administration services, which provide clients2008 when initial discussions with professional database monitoring and support solutions during business hours or around the clock.
FPU regarding a potential merger were terminated. Other operating expenses increased by $1.3 million to $6.0 millionfor our advanced information services operation remained relatively unchanged in 2007,2008 compared to $4.7 million for 2006. This increase in operating expenses in 2007 was attributable to the following:
Payroll, incentive compensation and commissions, payroll taxes, benefit claims, and consulting expense accounted for $937,000 of the increase. These costs increased as a result of improved earnings and increased staffing levels to support the growth and customer demand experienced in 2007.
An increase in the allowance for uncollectible accounts of $223,000 associated with a customer in the mortgage-lending business that filed for bankruptcy in the third quarter of 2007.
In addition, other operating expenses relating to various minor items increased by approximately $140,000.
Other Operations and EliminationsIncome
Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries. Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries contributed operating income of $352,000 for 2008, $295,000 for 2007, and $298,000 for 2006.
                         
          Increase          Increase 
For the Years Ended December 31, 2008  2007  (decrease)  2007  2006  (decrease) 
(in thousands)                        
Revenue $652  $622  $30  $622  $618  $4 
Cost of sales  —   —   —   —   —   — 
                   
Gross margin  652   622   30   622   618   4 
                         
Operations & maintenance  116   109   7   109   96   13 
Unconsummated acquisition costs  12   —   12   —   —   — 
Depreciation & amortization  114   160   (46)  160   163   (3)
Other taxes  62   62   —   62   65   (3)
                   
Other operating expenses  304   331   (27)  331   324   7 
                         
Operating Income — Other  348   291   57   291   294   (3)
Operating Income — Eliminations  4   4   —   4   4   — 
                   
                         
Total Operating Income
 $352   295  $57  $295   298  $(3)
                   
Other Income
Other income for the years2009, 2008 and 2007 was $163,000, $103,000 and 2006,$291,000, respectively, was $103,000, $291,000, and $189,000, which includeincludes interest income, late fees charged to customers and gains or losses from the sale of assets.
Interest Expense
2009 Compared to 2008
Total interest expense for 2009 increased by approximately $928,000, or 15 percent, compared to 2008. Total interest expense for 2009 includes approximately $741,000 in FPU’s interest expense for the period from the merger closing (October 28, 2009) to December 31, 2009, which is primarily related to $610,000 in interest on FPU’s long-term debt and $115,000 in interest on customer deposits. FPU’s weighted average interest rate was 7.41 percent for the period from the merger closing to December 31, 2009.
The remaining increase in interest expense in 2009 was attributable to the following factors:
Excluding FPU’s long-term debt, interest expense on long-term debt increased by $990,000 as our average long-term debt balance increased to $92.1 million in 2009 from $76.2 million in 2008. This increase was primarily related to the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008. The weighted average interest rate on our long-term debt remained unchanged at 6.37 percent in 2009, compared to 6.40 percent in 2008.
Interest expense in short-term borrowing decreased by $852,000 in 2009, compared to 2008, as our average short-term borrowing balance decreased to $13.0 million in 2009 from $38.3 million in 2008. The $30.0 million long-term placement in October 2008 contributed to this decrease as well as a decrease in working capital requirements in 2009, compared to 2008, due to lower capital expenditures, lower income tax payments from bonus depreciation, net tax operating losses carried forward from 2008 and lower commodity costs. The impact from these factors was offset slightly by the increased working capital needs as a result of the FPU merger. Also contributing to the decrease in interest expense in short-term borrowing was a decrease in the weighted average short-term interest rate to 1.28 percent in 2009 from 2.79 percent in 2008 as we continued to experience low interest rates throughout 2009.
Other interest charges increased by $49,000.
In January 2010, we redeemed $28.7 million of the secured first mortgage bonds with a carrying value of $27.2 million to increase financial flexibility by reducing the amount of the FPU secured long-term debt and maintaining compliance with the covenants in our unsecured senior notes.
2008 Compared to 2007
Total interest expense for 2008 decreased by approximately $432,000, or seven percent, compared to 2007. The lower interest expense is primarily the result of the following:
Interest on long-term debt decreased by $263,000 in 2008, compared to 2007, as the Companywe reduced itsour average long-term debt balance and its weighted average interest rate. The Company’sOur 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.
Page 46     Chesapeake Utilities Corporation 2008 Form 10-K

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 the Company’sour average short-term borrowing balance. The Company’sOur 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.
Total interestIncome Taxes
2009 Compared to 2008
Income tax expense for 2007 increased approximately $816,000, or 14 percent,was $10.9 million in 2009, compared to 2006.$8.8 million in 2008, representing an increase of $2.1 million. During 2009, we expensed approximately $871,000 in merger-related costs that were determined to be non-deductible for income tax purposes. Excluding the impact of these costs, our effective income tax rate for 2009 and 2008 remained primarily unchanged at 39.4 percent and 39.3 percent, respectively. The higher interest expense was a result of the following developments:
As a result of fewer capital projects in 2007 compared to 2006, the Company capitalized $469,000 less interest on debt in 2007 associated with ongoing capital projects.
The Company’s average long-term debt balance during 2007 was $76.5 million, with a weighted average interest rate of 6.71 percent, compared to $67.2 million, with a weighted average interest rate of 6.98 percent, for 2006. The large year-over-year increase in income tax expense reflects the average long-term debt balance was the result of a debt placement of $20 millionincreased taxable income in Senior Notes at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).
2009.
The average short-term borrowing balance in2008 Compared to 2007 decreased by $6.3 million to $20.6 million compared to an average balance of $26.9 million in 2006. The weighted average interest rates for short-term borrowing of 5.46 percent for 2007 and 5.47 percent for 2006 had minimum impact on the change in short-term borrowing expense.
Income Taxes
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 $8.6 million forand 2007 remained primarily unchanged at 39.3 percent and $7.0 million for 2006.39.4 percent, respectively. The increasesincrease in income tax expense reflectreflects the increased taxable income in each period. The effective federal income tax rate for each of the three years 2008, 2007, and 2006 was 35 percent, and the Company realized a benefit of $235,000, $226,000, and $220,000 in those years, respectively, relating to tax deductions for dividends paid on Company stock held in the Employee Stock Ownership Plan.2008.
Discontinued Operations
During 2007, Chesapeakewe decided to close itsthe distributed energy services subsidiary, OnSight, which had experienced operating losses since its inception in 2004. OnSight was previously reported as part of the Company’s Other Business segment. The results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. The discontinued operations experienced a net loss of $20,000 for 2007, compared to a net loss of $241,000 for 2006. The Company2007. We did not have any discontinued operations in 2008.2008 and 2009.
(e) Liquidity and Capital Resources
Chesapeake’sOur capital requirements reflect the capital-intensive nature of itsour business and are principally attributable to investment in new plant and equipment and 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 2009, net cash provided by operating activities was $45.8 million, cash used in investing activities was $23.1 million, and cash used in financing activities was $21.4 million. Cash provided during 2009 includes approximately $359,000 of net cash acquired in the merger with FPU.
During 2008, net cash provided by operating activities was $28.5 million, cash used by investing activities was $31.2 million, and cash provided by financing activities was $1.7 million.
During 2007, net cash provided by operating activities was $25.7 million, cash used by investing activities was $31.3 million, and cash provided by financing activities was $3.7 million.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 4751

 

 

Management’s Discussion and Analysis
On December 11, 2008, the Board of Directors authorized the Company to borrow up to $65.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of December 31, 2008, Chesapeake2009, we had fivefour unsecured bank lines of credit with threetwo financial institutions, for a total of $90.0 million, none of which requires compensating balances. In January 2010, the total unsecured bank lines of credit increased to $100.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’sour short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of itsthe capital expenditures.expenditure program. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these short-term lines of credit. In response to the instability and volatility of the financial markets during 2008, the Companywe solidified itsour lines of credit by converting $40.0 million of available credit under uncommitted lines to committed lines of credit. At December 31, 2008,Currently, two of the bank lines, totaling $55.0$60.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The outstanding balance of short-term borrowing at December 31, 2009 and 2008 and 2007 was $33.0$30.0 million and $45.7$33.0 million, respectively. The level of short-term debt was reduced in late 2008 and throughout 2009 with funds provided from the placement of $30 million of 5.93 percent Unsecured Senior Notes in October 2008. This reduction was offset in late 2009 by the increased working capital requirements after the FPU merger.
Chesapeake hasWe have budgeted $34.8$53.9 million for capital expenditures during 2009.2010. This amount includes $21.6$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 $8.8 million foroperation ($20.2 million), natural gas transmission $3.6 million for propaneoperation ($25.4 million) and electric distribution and wholesale marketing, $250,000 for advanced information services and $507,000 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 to replacereplacement 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. The Company expectsWe expect to fund the 20092010 capital expenditures program from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital.
Capital Structure
In consummating the FPU merger, Chesapeake issued 2,487,910 shares of its common stock, valued at approximately $75.7 million, in exchange for all outstanding common stock of FPU. We also became subject to FPU’s long-term debt of $47.8 million as a result of the merger. The following presents our capitalization as of December 31, 20082009 and 2007:2008:
                                
December 31, 2008 2007 
 December 31, December 31, 
(in thousands) 2009 2008 
 (In thousands, except percentages)  
Long-term debt, net of current maturities $86,422  41% $63,256  35% $98,814  32% $86,422  41%
Stockholders’ equity $123,073  59% $119,576  65%
Stockholders��� equity 209,781  68% 123,073  59%
                  
Total capitalization, excluding short-term debt $209,495  100% $182,832  100% $308,595  100% $209,495  100%
                  
As of December 31, 2008,2009, common equity represented 5968 percent of total capitalization, compared to 6559 percent at December 31, 2007.2008. 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

The following presents our capitalization as of December 31, 20082009 and 2007,2008, if short-term borrowing and the current portion of long-term debt were included in capitalization:
                                
December 31, 2008 2007 
 December 31, December 31, 
(in thousands) 2009 2008 
 (In thousands, except percentages) 
Short-term debt $33,000  13% $45,664  19% $30,023  8% $33,000  13%
Long-term debt, including current maturities $93,079  38% $70,912  30% 134,113  36% 93,078  38%
Stockholders’ equity $123,073  49% $119,576  51% 209,781  56% 123,073  49%
                  
Total capitalization, including short-term debt $249,152  100% $236,152  100% $373,917  100% $249,151  100%
                  
If short-term borrowingExcluding $75.7 million of the value of Chesapeake’s common stock issued in the merger and the current portion$47.8 million of FPU’s long-term debt were included in capitalization,our Consolidated Balance Sheet at December 31, 2009, total capitalization increased by $13.0$1.3 million in 2008. The increased capitalization was primarily used to fund a portion of the $30.8 million of property, plant, and equipment added in 2008 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 49 percent at December 31, 2008, compared to 51 percent at December 31, 2007.2009.
Page 48     Chesapeake Utilities Corporation 2008 Form 10-K

Chesapeake remainsWe remain committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for the Company’sour regulated operations, is intended to ensure that Chesapeake will be ableour ability to attract capital from outside sources at a reasonable cost. The Company believesWe believe that the achievement of these objectives will provide benefits to our customers, creditors and creditors, as well as its 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 690,345 shares of common stock, which included the underwriter’s exercise of an 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 funding working capital requirements. At December 31, 2008 and 2007, the Company had approximately $20.0 million remaining under this registration statement.
In December 2008, the Company filed a registration statement on Form S-3 with the SEC relating to the registration of 631,756 shares of our common stock under our Dividend Reinvestment and Direct Stock Purchase Plan (the “Plan”). The registration statement was declared effective by the SEC in January 2009 and replaces the prior registration in place for the Plan that had previously expired.
Cash Flows Provided by Operating Activities
Our cash flows provided by (used in) operating activities were as follows:
                        
For the Years Ended December 31, 2008 2007 2006  2009 2008 2007 
(in thousands) 
Net income $13,607,259 $13,197,710 $10,506,525  $15,897 $13,607 $13,198 
Non-cash adjustments to net income 23,024,317 15,723,829 11,386,670  28,319 22,919 15,829 
Changes in assets and liabilities  (8,089,187)  (3,239,655) 8,255,699  1,593  (7,982)  (3,346)
              
Net cash from operating activities
 $28,542,389 $25,681,884 $30,148,894  $45,809 $28,544 $25,681 
              
Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income, depreciation, deferred taxes and working capital. Changes in working capital are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, 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 natural gas and propane distribution operations to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.
Cash Flows From Operating ActivitiesChesapeake Utilities Corporation 2009 Form 10-K     Page 53

In 2009, our net cash flow provided by operating activities was $45.8 million, an increase of $17.3 million compared to 2008. This increase includes $4.7 million in net cash flow provided by the operating activities of FPU after the merger. The remaining increase was due primarily to the following:
Net cash flows from the change in income taxes receivable and non-cash adjustments for deferred income taxes were related to continued higher tax deductions provided by bonus depreciation, which resulted in net federal income tax refunds received in 2009 and continued to create higher book-to-tax timing differences;
Net cash flows from changes in accounts receivable and accounts payable were due primarily to the timing of collections and payments of trading contracts entered into by our propane wholesale marketing operation; and
Net cash flows from the increase in regulatory liabilities were due primarily to higher over-collection of purchased gas costs by our Delmarva natural gas distribution operation.
In 2008, our net cash flow provided by operating activities was $28.5 million, an increase of $2.9 million compared to 2007. The increase was due primarily to the following:
Net cash flows from changes in accounts receivable and accounts payable were due primarily due to the timing of collections and payments of trading contracts entered into by the Company’sour 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;
Chesapeake Utilities Corporation 2008 Form 10-K     Page 49

Management’s Discussion and Analysis
Reduced payments for income taxes payable as a result of higher tax deductions provided by the 2008 Economic Stimulus Act; and
Cash flows provided by non-cash adjustments for deferred income taxes. The increase in deferred income taxes is the result of higher book-to-tax timing differences during the period that were generated by the Economic Stimulus Act, which authorized bonus depreciation for certain assets.
In 2007, net cash flow provided by operating activities was $25.7 million, a decrease of $4.4 million from 2006. The 2007 operating cash flows reflect the favorable timing of payments for accounts payable and accrued liabilities, which increased operating cash flow by $22.1 million. In addition, increased net income and favorable non-cash adjustments, primarily depreciation expense, contributed to the increase in operating cash flow. Partially offsetting these increases in operating cash flow was an increase in accounts receivable of $28.2 million associated with increased revenues and the timing of invoicing by our propane wholesale and marketing operation.
Cash Flows Used in Investing Activities
NetIn 2009, net cash flows used inby investing activities totaled $23.1 million, a decrease of $8.1 million compared to 2008. In 2008, net cash flows used by investing activities totaled $31.2 million, which remained relatively unchanged from net cash flows used by investing activities of $31.3 million and $48.9in 2007.
We acquired $359,000 in cash, net of cash paid, in the merger with FPU in 2009.
We received $3.5 million during fiscal years 2008, 2007, and 2006, respectively.in proceeds from an investment account related to future environmental costs, which was previously included as a non-current investment, as we transferred the amount to our general account that invests in overnight income-producing securities. Our general account is considered cash equivalent.
Cash utilized for capital expenditures was $26.6 million, $30.8 million and $31.3 million and $48.9 million for 2008, 2007, and 2006, respectively. Additions to property, plant and equipment in 2008 were primarily for natural gas transmission ($10.5 million), natural gas distribution ($15.1 million), propane distribution ($3.1 million), advanced information services ($672,000) and other operations ($1.4 million). In both2009, 2008, and 2007, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements; in both periods, the natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system.respectively.
The Company’s environmentalEnvironmental expenditures exceeded amounts recovered through rates charged to customers in 2009, 2008 and 2007 by $418,000, $480,000 and 2006 by $480,000, $228,000, and $16,000, respectively.
Sales of property, plant, and equipment generated $205,000 of cash in 2007.
Page 54     Chesapeake Utilities Corporation 2009 Form 10-K

Cash Flows Provided by Financing Activities
CashIn 2009, net cash flows used by financing activities totaled $21.4 million, compared to net cash flow provided by financing activities totaledof $1.7 million during 2008,and $3.7 million duringin 2008 and 2007, and $20.7 million during 2006.respectively. Significant financing activities included the following:
In OctoberDuring 2009 and 2008, the Company completed the placement of $30.0 million of 5.93 percent Unsecured Senior Notes; in October 2006, the Company also completed the placement of $20.0 million of 5.5 percent Unsecured Senior Notes.
During 2008 and 2006, the Companywe reduced itsour short-term debt by $12.0$3.8 million and $8.0$12.0 million, respectively. During 2007, net borrowing of short-term debt increased by $18.7 million, primarily to support our capital investments.
The CompanyIn October 2008, we completed the placement of $30.0 million of 5.93 percent Unsecured Senior Notes.
We repaid $10.9 million of long-term debt during 2009, compared to $7.7 million of long-term debt repaid during each of 2008 and 2007, compared with $4.9 million during 2006.2007.
During 2008, the CompanyWe paid $8.0 million, $7.8 million and $7.0 million in cash dividends compared with dividend payments of $7.0 million in 2009, 2008 and 2007, and $6.0 million for 2006. Therespectively. An increase in cash dividends paid in 2008 compared to 2007each year reflects the growth in the annualized dividend rate from $1.18 per share in 2007 to $1.22 per share in 2008. The dividends paid in 2007, compared to 2006 reflects both growth in the annualized dividend rate, from $1.16 per share during 2006 to $1.18 per share during 2007, and the increase in shares outstanding following the issuance of additional shares of common stock in the fourth quarter of 2006.
Page 50     Chesapeake Utilities Corporation 2008 Form 10-K

In November 2006, the Company sold 690,345 shares of common stock, which included the underwriter’s exercise of an 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 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.rate.
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2008:2009:
                                        
 Payments Due by Period  Payments Due by Period 
 Less than 1 More than 5    Less than 1 More than 5   
Contractual Obligations year 1 – 3 years 3 – 5 years years Total  year 1 - 3 years 3 - 5 years years Total 
(in thousands) 
 
Long-term debt(1)
 $6,656,364 $14,403,636 $13,454,545 $58,564,091 $93,078,636  $36,765 $17,293 $20,793 $60,818 $135,669 
 
Operating leases(2)
 770,329 1,217,087 929,756 2,446,248 5,363,420  866 1,449 865 2,031 5,211 
 
Purchase obligations(3)
  
Transmission capacity 8,881,750 22,168,145 10,162,156 48,665,180 89,877,231  11,133 38,589 20,447 63,028 133,197 
Storage — Natural Gas 1,507,998 4,145,743 2,719,878 1,707,063 10,080,682  530 6,600 2,001 968 10,099 
Commodities 31,597,588 57,545 — — 31,655,133  54,802 341 — — 55,143 
Electric supply 574 1,149 1,149 2,298 5,170 
Forward purchase contracts — Propane(4)
 10,181,630 — — — 10,181,630  12,570 — — — 12,570 
Other 1,557 16 — — 1,573 
Unfunded benefits(5)
 336,637 1,392,409 659,454 1,810,947 4,199,447  371 1,504 847 4,926 7,648 
Funded benefits(6)
 519,319 120,615 60,308 1,396,143 2,096,385  2,090 79 670 1,170 4,009 
                      
Total Contractual Obligations
 $60,451,615 $43,505,180 $27,986,097 $114,589,672 $246,532,564  $121,258 $67,020 $46,772 $135,239 $370,289 
                      
   
(1) Principal payments on long-term debt, see Note H, “Long-Term Debt,” inItem 8 under the Notesheading “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 $5.7$7.5 million, $10.0$12.6 million, $8.0$10.1 million and $13.1$17.3 million, respectively, for the periods indicated above. Expected interest payments for all periods total $36.8$47.6 million.
 
(2) See Note J, “Lease Obligations,” inItem 8 under the Notesheading “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 N, “OtherP, Other Commitments and Contingencies,” in the Notes to the Consolidated Financial Statements for further information.
 
(4) The Company hasWe have also entered into forward sale contracts. See “Market Risk” of the Management’s Discussion and Analysis for further information.
 
(5) The Company hasWe have recorded long-term liabilities of $4.6$7.6 million at December 31, 20082009 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) The Company hasWe have recorded long-term liabilities of $6.5$12.7 million at December 31, 20082009 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. Thetwo qualified, defined benefit pension plan was closed to new participants on January 1, 1999plans. The assets funding these plans are in a separate trust and participantsare not considered assets of the Company or included in the plan on that date were givenCompany’s balance sheets. The Contractual Obligations table above includes $2.0 million, reflecting the option to leaveexpected payments the plan. See Note K, “Employee Benefit Plans,” in the NotesCompany will make to the Consolidated Financial Statements for further information on the plan. The Company expects to contribute $450,000 to the plantrust funds in 2009.2010. 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

Off-Balance Sheet Arrangements
The Company hasWe have issued corporate guarantees to certain vendors of itsour subsidiaries, primarily itsthe propane wholesale marketing subsidiary and itsthe natural gas supply managementmarketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 20082009 was $22.2$22.7 million, with the guarantees expiring on various dates in 2009.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 51

Management’s Discussion and Analysis2010.
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, 2009.2010. The letter of credit is provided as security to satisfy the deductibles under the Company’sour various insurance policies. There have been no draws on this letter of credit as of December 31, 2008.2009.
(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 their respective PSC; ESNG is subject to regulation by the FERC.FERC; and PIPECO is subject to regulation by the Florida PSC. At December 31, 2008,2009, Chesapeake was involved in rate filings and/or regulatory matters in each of the jurisdictions in which it operates. Each of these rate filings or regulatory matters is fully described in Note O, “Other Commitments and Contingencies,”Item 8 under the heading “Notes to the Consolidated Financial Statements.Statements – Note P, Other Commitments and Contingencies.”
(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 NItem 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 changes in interest rates. The Company’sOur long-term debt consists of fixed-rate senior notes, secured debt and convertible debentures (see Note IItem 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 the Company’sour long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $93.1$134.1 million at December 31, 2008,2009, as compared to a fair value of $92.3$145.5 million, based on a discounted cash flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average maturities with adjustments for duration, optionality, credit risk, and risk profile. The Company evaluatesWe evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.
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 (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, 2008, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the Pro-Cap Plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS No. 133. At the end of 2008, the market price of propane, valued using broker or dealer quotations, or market transactions in either the listed or OTC markets, dropped below the unit price in the swap agreement. As a result of the price drop, the Company marked the January and February gallons in the agreement to market, which resulted in an increase to cost of sales of $939,000. The Company subsequently terminated the swap agreement in January 2009. The Company did not enter into a similar agreement in 2007.
The Company’sPage 56     Chesapeake Utilities Corporation 2009 Form 10-K

Our propane wholesale marketing operation is a party to natural gas liquids forward contracts, primarily propane contracts, with various third parties.third-parties. These contracts require that the propane wholesale marketing operation purchase or sell natural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of natural gas liquids to the Companyus or the counter-party or “booking out” the transaction. Booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy. The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane.
Page 52     Chesapeake Utilities Corporation 2008 Form 10-K

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with the Company’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 the Company’sour oversight officials daily.officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at December 31, 20082009 and 20072008 is presented in the following tables.
                    
 Quantity in Estimated Market Weighted Average  Quantity in Estimated Market Weighted Average 
At December 31, 2008 gallons Prices Contract Prices 
At December 31, 2009 gallons Prices Contract Prices 
Forward Contracts
           
Sale 10,626,000 $0.5450 – $1.9100 $0.9984  11,944,800 $0.6900 — $1.3350 $1.1264 
Purchase 9,949,800 $0.7000 – $1.9600 $1.0233  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 2009.2010.
                    
 Quantity in Estimated Market Weighted Average  Quantity in Estimated Market Weighted Average 
At December 31, 2007 gallons Prices Contract Prices 
At December 31, 2008 gallons Prices Contract Prices 
Forward Contracts
           
Sale 30,941,400 $0.8925 – $1.6025 $1.3555  10,626,000 $0.5450 — $1.9100 $0.9984 
Purchase 30,954,000 $0.8700 – $1.6000 $1.3498  9,949,800 $0.7000 — $1.9600 $1.0233 
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expireexpired in 2008.2009.
At December 31, 2009 and 2008, and 2007, the Companywe marked these forward and other contracts to market, using broker or dealer quotations, or market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:
         
December 31, 2008  2007 
(in thousands)
        
Marked-to-market energy assets $4,482  $7,812 
Marked-to-market energy liabilities $3,052  $7,739 
         
  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.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 53

Management’s Discussion and Analysisaccounted for on an accrual basis.
(i) 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-volume industrial customers that canare able to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements, and our interruptible sales volumes may decline because oil prices are lower than the price of natural gas.decline. Oil prices, as well as the prices of electricity and other fuels, fluctuate 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 sides of this business to compete with alternative fuel price fluctuations. As a result of the transmission operation’s conversion to open access and theChesapeake’s Florida natural gas distribution division’s restructuring of its services, these businesses have shifted from providing bundled transportation and sales service to providing only transportationtransmission 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 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 such 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. With respect to unbundled transportation services, the Company’sour competitors include interstate transmission companies, if the distribution customers are located close enough to a transmission company’s pipeline to make connections economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the Company’sour existing distribution operations in this manner. In certain situations, the Company’sour 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 Company hasWe have also established a natural gas sales and supply managementmarketing operation in Florida, Delaware and Maryland to provide such service to customers eligible for unbundled transportation services.
The Company’sOur propane distribution operations compete with several other propane distributors in their respective geographic markets, primarily on the basis of service and price, emphasizing responsive and reliable service. Our competitors generally include local outlets of national distributors and local independent distributors, whose proximity to customers entails lower costs to provide service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas served by natural gas pipeline or distribution systems.
The propane wholesale marketing operation competes against various regional and national marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.
The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them than does the Company. In addition, changes in the advanced information services business are occurring rapidly, and could adversely affect the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.
Page 58     Chesapeake Utilities Corporation 2009 Form 10-K

(j) Inflation
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the Company’s 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 itsour regulated operations and closely monitorsmonitor the returns of itsour unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts itswe adjust propane selling prices to the extent allowed by the market.
Page 54     Chesapeake Utilities Corporation 2008 Form 10-K

Cautionary Statement
Chesapeake Utilities Corporation has made statements in this Form 10-K that are considered to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are not matters of historical fact and are typically identified by words such as, but not limited to, “believes,” “expects,” “intends,” “plans,” and similar expressions, or future or conditional verbs such as “may,” “will,” “should,” “would,” and “could.” These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trends and decisions, market risks associated with our propane operations, the competitive position of the Company, inflation, and other matters. It is important to understand that these forward-looking statements are not guarantees; rather, they are subject to certain risks, uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. Such factors include, but are not limited to:
the temperature sensitivity of the natural gas and propane businesses;
the effects of spot, forward, futures market prices, and the Company’s use of derivative instruments on the Company’s distribution, wholesale marketing and energy trading businesses;
the amount and availability of natural gas and propane supplies;
the access to interstate pipelines’ transportation and storage capacity and the construction of new facilities to support future growth;
the effects of natural gas and propane commodity price changes on the operating costs and competitive positions of our natural gas and propane distribution operations;
the impact that declining propane prices may have on the valuation of our propane inventory;
third-party competition for the Company’s unregulated and regulated businesses;
changes in federal, state or local regulation and tax requirements, including deregulation;
changes in technology affecting the Company’s advanced information services segment;
changes in credit risk and credit requirements affecting the Company’s energy marketing subsidiaries;
the effects of accounting changes;
changes in benefit plan assumptions, return on plan assets, and funding requirements;
cost of compliance with environmental regulations or the remediation of environmental damage;
the effects of general economic conditions, including interest rates, on the Company and its customers;
the impact of the volatility in the financial and credit markets on the Company’s ability to access credit;
the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues;
the ability of the Company to construct facilities at or below estimated costs;
the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions;
the Company’s ability to obtain necessary approvals and permits from regulatory agencies on a timely basis;
the impact of inflation on the results of operations, cash flows, financial position and on the Company’s planned capital expenditures;
inability to access the financial markets to a degree that may impair future growth; and
operating and litigation risks that may not be covered by insurance.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 55

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,” 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, 2008.2009.
Page 56     Chesapeake Utilities Corporation 20082009 Form 10-K     Page 59

 

 

Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation as of December 31, 20082009 and 2007,2008, and the related consolidated statements of income, stockholders’ equity and cash flows and income taxes for each of the years then ended.in the three-year period ended December 31, 2009. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and subsidiaries as of December 31, 20082009 and 2007,2008, and the results of their operations and their cash flows for each of the years thenin the three-year period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
We also have audited the adjustments to the 2006 consolidated financial statements to retrospectively reflect the discontinued operations described in Note B. In our opinion, such adjustments were appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2006 consolidated financial statements of Chesapeake Utilities Corporation other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2006 consolidated financial statements taken as a whole.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2008,2009, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 9, 20098, 2010 expressed an unqualified opinion.
/s/ Beard Miller Company LLP     
Beard Miller Company LLP
Reading, Pennsylvania
March 9, 2009
/s/ ParenteBeard LLC
ParenteBeard LLC
Malvern, Pennsylvania
March 8, 2010
Page 60     Chesapeake Utilities Corporation 20082009 Form 10-K     Page 57

 

 

Consolidated Statements of Income
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
of Chesapeake Utilities Corporation
In our opinion, the consolidated statements of income, cash flows, stockholders’ equity and income taxes for the year ended December 31, 2006, before the effects of the adjustments to retrospectively reflect the discontinued operations described in Note B, present fairly, in all material respects, the results of operations and cash flows of Chesapeake Utilities Corporation and its subsidiaries for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America (the 2006 financial statements before the effects of the adjustments discussed in Note B are not presented herein). In addition, in our opinion, the financial statement schedule for the year ended December 31, 2006, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements before the effects of the adjustments described above. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit, before the effects of the adjustments described above, 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 financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note L to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans, effective December 31, 2006.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in Note B and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by other auditors.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Boston, MA
March 13, 2007
The accompanying notes are an integral part of the financial statements.
Page 58     Chesapeake Utilities Corporation 2008 Form 10-K

                        
For the Twelve Months Ended December 31, 2008 2007 2006 
For the Years Ended December 31, 2009 2008 2007 
(in thousands, except shares and per share data) 
  
Operating Revenues
 $291,443,477 $258,286,495 $231,199,565  
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
  
Cost of sales, excluding costs below 200,643,518 170,848,211 155,809,747 
Regulated energy cost of sales 64,803 54,789 70,861 
Unregulated energy cost of sales 95,467 145,854 99,987 
Operations 43,475,794 42,242,218 36,612,683  50,706 43,476 42,243 
Unconsummated acquisition costs 1,152,844 — — 
Transaction-related costs 1,478 1,153 — 
Maintenance 2,215,123 2,235,605 2,161,177  3,430 2,215 2,236 
Depreciation and amortization 9,004,911 9,060,185 8,243,715  11,588 9,005 9,060 
Other taxes 6,472,353 5,786,694 5,040,306  7,577 6,472 5,785 
              
Total operating expenses 262,964,543 230,172,913 207,867,628  235,049 262,964 230,172 
              
 
Operating Income
 28,478,934 28,113,582 23,331,937  33,736 28,479 28,114 
 
Other income, net of other expenses 103,039 291,305 189,093  165 103 291 
 
Interest charges 6,157,552 6,589,639 5,773,993  7,086 6,158 6,590 
              
 
Income Before Income Taxes
 22,424,421 21,815,248 17,747,037  26,815 22,424 21,815 
Income taxes 8,817,162 8,597,461 6,999,072  10,918 8,817 8,597 
              
Income from Continuing Operations
 13,607,259 13,217,787 10,747,965 
 
Loss from discontinued operations, net of tax benefit of $0,$10,898 and $162,510 —  (20,077)  (241,440)
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
 $13,607,259 $13,197,710 $10,506,525  $15,897 $13,607 $13,198 
              
  
Weighted Average Common Shares Outstanding:
  
Basic 6,811,848 6,743,041 6,032,462  7,313,320 6,811,848 6,743,041 
Diluted 6,927,483 6,854,716 6,155,131  7,440,201 6,927,483 6,854,716 
 
Earnings Per Share of Common Stock:
  
Basic
  
From continuing operations $2.00 $1.96 $1.78  $2.17 $2.00 $1.96 
From discontinued operations — —  (0.04) — — — 
              
Net Income
 $2.00 $1.96 $1.74  $2.17 $2.00 $1.96 
              
Diluted
  
From continuing operations $1.98 $1.94 $1.76  $2.15 $1.98 $1.94 
From discontinued operations — —  (0.04) — — — 
              
Net Income
 $1.98 $1.94 $1.72  $2.15 $1.98 $1.94 
              
  
Cash Dividends Declared Per Share of Common Stock:
 $1.21 $1.18 $1.16 
Cash Dividends Declared Per Share of Common Stock
 $1.250 $1.210 $1.175 
       
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 5961

 

 

Consolidated Statements of Cash Flows
                        
For the Years Ended December 31, 2008 2007 2006  2009 2008 2007 
(in thousands) 
  
Operating Activities
  
Net Income $13,607,259 $13,197,710 $10,506,525  $15,897 $13,607 $13,198 
Adjustments to reconcile net income to net operating cash:  
Depreciation and amortization 9,004,911 9,060,185 8,243,715  11,588 9,005 9,060 
Depreciation and accretion included in other costs 2,239,018 3,336,506 3,102,066  2,789 2,239 3,337 
Deferred income taxes, net 11,441,660 1,831,030  (408,533) 10,065 11,442 1,831 
Gain on sale of assets —  (204,882) —  — —  (205)
Unrealized (gain) loss on commodity contracts  (1,146,486)  (170,465) 37,110  1,606  (1,252)  (65)
Unrealized (gain) loss on investments 509,084  (122,819)  (151,952)  (212) 509  (123)
Employee benefits and compensation 151,910 1,004,273  (158,825) 1,217 152 1,004 
Share based compensation 820,175 989,945 709,789  1,306 820 990 
Other, net 4,045 56 13,300   (40) 4 — 
Changes in assets and liabilities:  
Sale (purchase) of investments  (200,603) 229,125  (177,990)  (146)  (201) 229 
Accounts receivable and accrued revenue 19,410,552  (28,189,132) 9,705,860   (13,652) 19,411  (28,189)
Propane inventory, storage gas and other inventory  (1,729,641) 1,193,336 354,764  2,597  (1,730) 1,193 
Regulatory assets 410,989  (344,680) 2,498,954   (1,842) 411  (345)
Prepaid expenses and other current assets  (1,182,142)  (1,185,829)  (261,017)  (747)  (1,182)  (1,186)
Other deferred charges  (153,005)  (2,477,879)  (231,822)  (83)  (153)  (2,478)
Long-term receivables 207,324 83,653 137,101  191 207 84 
Accounts payable and other accrued liabilities  (15,139,134) 22,130,049  (11,434,370) 10,185  (15,033) 22,024 
Income taxes receivable  (6,155,239)  (158,556) 1,800,913  5,020  (6,155)  (159)
Accrued interest 158,154 33,112 273,672  66 158 33 
Customer deposits and refunds  (502,479) 2,534,655 2,361,265   (75)  (502) 2,535 
Accrued compensation  (174,946) 946,099  (721,289)  (2,066)  (175) 946 
Regulatory liabilities  (3,107,401) 2,124,091 2,824,068  1,071  (3,107) 2,124 
Other liabilities 68,384  (157,699) 1,125,590  1,074 69  (157)
              
Net cash provided by operating activities 28,542,389 25,681,884 30,148,894  45,809 28,544 25,681 
              
 
Investing Activities
  
Property, plant and equipment expenditures  (30,755,845)  (31,277,390)  (48,845,828)  (26,603)  (30,756)  (31,277)
Proceeds from sale of assets — 204,882 —  — — 205 
Proceeds from investments 3,519 — — 
Cash acquired in the merger, net of cash paid 359 — — 
Environmental expenditures  (479,799)  (227,979)  (15,549)  (418)  (480)  (228)
              
Net cash used by investing activities  (31,235,644)  (31,300,487)  (48,861,377)  (23,143)  (31,236)  (31,300)
              
 
Financing Activities
  
Common stock dividends  (7,956,843)  (7,029,821)  (5,982,531)  (7,957)  (7,810)  (7,030)
Issuance of stock for Dividend Reinvestment Plan 28,541 299,436 321,865  392  (118) 299 
Stock issuance — — 19,698,509 
Cash settlement of warrants — —  (434,782)
Change in cash overdrafts due to outstanding checks  (683,836)  (541,052) 49,047  835  (684)  (541)
Net borrowing (repayment) under line of credit agreements  (11,980,108) 18,651,055  (7,977,347)  (3,812)  (11,980) 18,651 
Proceeds from issuance of long-term debt 29,960,518 — 19,968,104  — 29,961 — 
Repayment of long-term debt  (7,656,623)  (7,656,580)  (4,929,674)  (10,907)  (7,658)  (7,656)
              
Net cash provided by financing activities 1,711,649 3,723,038 20,713,191 
Net cash provided by (used in) financing activities  (21,449) 1,711 3,723 
              
 
Net Increase (Decrease) in Cash and Cash Equivalents
  (981,606)  (1,895,565) 2,000,708  1,217  (981)  (1,896)
 
Cash and Cash Equivalents — Beginning of Period
 2,592,801 4,488,366 2,487,658  1,611 2,592 4,488 
       
        
Cash and Cash Equivalents — End of Period
 $1,611,195 $2,592,801 $4,488,366  $2,828 $1,611 $2,592 
              
Supplemental Cash Flow Disclosures (see Note D)
The accompanying notes are an integral part of the financial statements.
Page 6062     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Consolidated Balance Sheets
                
 December 31, December 31,  December 31, December 31, 
Assets 2008 2007  2009 2008 
(in thousands, except shares and per share data)(in thousands, except shares and per share data) 
 
Property, Plant and Equipment
  
Natural gas $316,124,761 $289,706,066 
Propane 51,827,293 48,506,231 
Advanced information services 1,439,390 1,157,808 
Other plant 10,815,345 8,567,833 
Regulated energy $463,856 $316,125 
Unregulated energy 61,360 51,827 
Other 16,054 12,255 
          
Total property, plant and equipment 380,206,789 347,937,938  541,270 380,207 
Less: Accumulated depreciation and amortization  (101,017,551)  (92,414,289)  (107,318)  (101,018)
Plus: Construction work in progress 1,481,448 4,899,608  2,476 1,482 
          
Net property, plant and equipment 280,670,686 260,423,257  436,428 280,671 
          
  
Investments
 1,600,790 1,909,271  1,959 1,601 
          
  
Current Assets
  
Cash and cash equivalents 1,611,195 2,592,801  2,828 1,611 
Accounts receivable (less allowance for uncollectible accounts of $1,159,014 and $952,074, respectively) 52,905,447 72,218,191 
Accounts receivable (less allowance for uncollectible accounts of $1,609 and $1,159, respectively) 70,029 52,905 
Accrued revenue 5,167,666 5,265,474  12,838 5,168 
Propane inventory, at average cost 5,710,673 7,629,295  7,901 5,711 
Other inventory, at average cost 1,479,249 1,280,506  3,149 1,479 
Regulatory assets 826,009 1,575,072  1,205 826 
Storage gas prepayments 9,491,690 6,042,169  6,144 9,492 
Income taxes receivable 7,442,921 1,237,438  2,614 7,443 
Deferred income taxes 1,577,805 2,155,393  1,498 1,578 
Prepaid expenses 4,679,368 3,496,517  5,843 4,679 
Mark-to-market energy assets 4,482,473 7,812,456  2,379 4,482 
Other current assets 146,820 146,253  147 147 
          
Total current assets 95,521,316 111,451,565  116,575 95,521 
          
  
Deferred Charges and Other Assets
  
Goodwill 674,451 674,451  34,095 674 
Other intangible assets, net 164,268 178,073  3,951 164 
Long-term receivables 533,356 740,680  343 533 
Regulatory assets 2,806,195 2,539,235  19,860 2,806 
Other deferred charges 3,823,448 3,640,480  3,891 3,825 
          
Total deferred charges and other assets 8,001,718 7,772,919  62,140 8,002 
          
  
Total Assets
 $385,794,510 $381,557,012  $617,102 $385,795 
          
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 6163

 

 

Consolidated Balance Sheets
                
 December 31, December 31,  December 31, December 31, 
Capitalization and Liabilities 2008 2007  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) $3,322,668 $3,298,473 
Common stock, par value $0.4867 per share (authorized 12,000,000 shares) $4,572 $3,323 
Additional paid-in capital 66,680,696 65,591,552  144,502 66,681 
Retained earnings 56,817,921 51,538,194  63,231 56,817 
Accumulated other comprehensive loss  (3,748,093)  (851,674)  (2,524)  (3,748)
Deferred compensation obligation 1,548,507 1,403,922  739 1,549 
Treasury stock  (1,548,507)  (1,403,922)  (739)  (1,549)
          
Total stockholders’ equity 123,073,192 119,576,545  209,781 123,073 
  
Long-term debt, net of current maturities 86,422,273 63,255,636  98,814 86,422 
     
     
Total capitalization 209,495,465 182,832,181  308,595 209,495 
          
  
Current Liabilities
  
Current portion of long-term debt 6,656,364 7,656,364  35,299 6,656 
Short-term borrowing 33,000,000 45,663,944  30,023 33,000 
Accounts payable 40,202,280 54,893,071  51,948 40,202 
Customer deposits and refunds 9,534,441 10,036,920  24,960 9,534 
Accrued interest 1,023,658 865,504  1,887 1,024 
Dividends payable 2,082,267 1,999,343  2,959 2,082 
Accrued compensation 3,304,736 3,400,112  3,445 3,305 
Regulatory liabilities 3,227,337 6,300,766  8,882 3,227 
Mark-to-market energy liabilities 3,052,440 7,739,261  2,514 3,052 
Other accrued liabilities 2,967,905 2,500,542  8,683 2,970 
          
Total current liabilities 105,051,428 141,055,827  170,600 105,052 
          
  
Deferred Credits and Other Liabilities
  
Deferred income taxes 37,719,859 28,795,885  66,923 37,720 
Deferred investment tax credits 235,422 277,698  193 235 
Regulatory liabilities 875,106 1,136,071  4,154 875 
Environmental liabilities 511,223 835,143  11,104 511 
Other pension and benefit costs 7,335,116 2,513,030  17,505 7,335 
Accrued asset removal cost 20,641,279 20,249,948 
Accrued asset removal cost — Regulatory liability 33,214 20,641 
Other liabilities 3,929,612 3,861,229  4,814 3,931 
     
     
Total deferred credits and other liabilities 71,247,617 57,669,004  137,907 71,248 
          
  
Other Commitments and Contingencies (Note N)
 
Other commitments and contingencies (Note P) 
  
Total Capitalization and Liabilities
 $385,794,510 $381,557,012  $617,102 $385,795 
          
The accompanying notes are an integral part of the financial statements.
Page 6264     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

Consolidated Statements of Stockholders’ Equity
                                                 
 Common Stock Additional Accumulated
Other		        Common Stock Accumulated Other       
 Number of Paid-In Retained Comprehensive Deferred Treasury    Number of Additional Paid-In Comprehensive Deferred     
 Shares Par Value Capital Earnings Income Compensation Stock Total 
Balances at December 31, 2005
 5,883,099 $2,863,212 $39,619,849 $42,854,894 $(578,151) $794,535 $(797,156) $84,757,183 
Net earnings 10,506,525 10,506,525 
Other comprehensive income, net of tax: 
Minimum pension liability, net of tax(1)
 74,036 74,036 
   
Total comprehensive income 10,580,561 
   
Adjustment to initially apply SFAS No. 158, net of tax (5) (6)
 169,565 169,565 
Dividend Reinvestment Plan 38,392 18,685 1,148,100 1,166,785 
Retirement Savings Plan 29,705 14,457 900,354 914,811 
Conversion of debentures 16,677 8,117 275,300 283,417 
Share based compensation(2) (4)
 29,866 14,536 887,426 901,962 
Stock warrants, net of tax  (233,327)  (233,327)
Deferred Compensation Plan 323,974  (323,974) — 
Purchase of treasury stock  (97)  (51,572)  (51,572)
Sale and distribution of treasury stock 97 54,193 54,193 
Stock issuance 690,345 335,991 19,362,518 19,698,509 
Cash dividends (3)
  (7,090,535)  (7,090,535)
                 
(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 3,254,998 61,960,220 46,270,884  (334,550) 1,118,509  (1,118,509) 111,151,552  6,688,084 $3,255 $61,960 $46,271 $(334) $1,119 $(1,119) $111,152 
Net earnings 13,197,710 13,197,710 
Net Income 13,198 13,198 
Other comprehensive income, net of tax:  
Employee Benefit Plans, net of tax:  
Amortization of prior service costs(5)
  (2,828)  (2,828)
Net loss(6)
  (514,296)  (514,296)
Amortization of prior service costs(4)
  (3)  (3)
Net loss(5)
  (515)  (515)
      
Total comprehensive income 12,680,586  12,680 
      
Dividend Reinvestment Plan 35,333 17,197 1,121,190 1,138,387  35,333 17 1,121 1,138 
Retirement Savings Plan 29,563 14,388 934,295 948,683  29,563 14 935 949 
Conversion of debentures 8,106 3,945 133,839 137,784  8,106 4 135 139 
Share based compensation(2) (4)
 16,324 7,945 1,442,008 1,449,953 
Share based compensation(1) (3)
 16,324 8 1,442 1,450 
Deferred Compensation Plan 285,413  (285,413) —  285  (285) — 
Purchase of treasury stock  (971)  (29,771)  (29,771)  (971)  (30)  (30)
Sale and distribution of treasury stock 971 29,771 29,771  971 30 30 
Cash dividends(3)
  (7,930,400)  (7,930,400)
Cash dividends(2)
  (7,931)  (7,931)
                                  
Balances at December 31, 2007
 6,777,410 3,298,473 65,591,552 51,538,194  (851,674) 1,403,922  (1,403,922) 119,576,545  6,777,410 3,298 65,593 51,538  (852) 1,404  (1,404) 119,577 
Net earnings 13,607,259 13,607,259 
Net Income 13,607 13,607 
Other comprehensive income, net of tax:  
Employee Benefit Plans, net of tax:  
Amortization of prior service costs(5)
  (71,438)  (71,438)
Net loss(6)
  (2,824,981)  (2,824,981)
Amortization of prior service costs(4)
  (71)  (71)
Net loss(5)
  (2,825)  (2,825)
      
Total comprehensive income 10,710,840  10,711 
      
Dividend Reinvestment Plan 9,060 4,410 269,127 273,537  9,060 5 269 274 
Retirement Savings Plan 5,260 2,560 156,195 158,755  5,260 3 156 159 
Conversion of debentures 10,397 5,060 171,680 176,740  10,397 5 171 176 
Share based compensation(2) (4)
 24,994 12,165 441,898 454,063 
Share based compensation(1) (3)
 24,994 12 442 454 
Tax benefit on stock warrants 50,244 50,244  50 50 
Deferred Compensation Plan 144,585  (144,585) —  145  (145) — 
Purchase of treasury stock  (2,425)  (71,573)  (71,573)  (2,425)  (72)  (72)
Sale and distribution of treasury stock 2,425 71,573 71,573  2,425 72 72 
Dividends on stock-based compensation  (79,570)  (79,570)  (81)  (81)
Cash dividends(3)
  (8,247,962)  (8,247,962)
Cash dividends(2)
  (8,247)  (8,247)
                                  
Balances at December 31, 2008
 6,827,121 $   3,322,668 $   66,680,696 $   56,817,921 $(3,748,093) $1,548,507 $   (1,548,507) $   123,073,192  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)Tax expense recognized on the minimum pension liability adjustment for 2006 was $48,889.
(2) Includes amounts for shares issued for Directors’ compensation.
 
(3)(2) Cash dividends per share for the periods ended December 31, 2009, 2008 and 2007 were $1.250, $1.210 and 2006 were $1.22, $1.18 and $1.16,$1.175 respectively.
 
(4)(3) The shares issued under the PIPPerformance 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, 2,420taxes. The Company did not issue any shares for 2007 and 9,054 shares for 2006.the PIP in 2009.
 
(5)(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 2006 were ($51,841), ($1,871) and $11,756,2) respectively.
 
(6)(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 2006($340) respectively.
(6)In May and November 2009, certain participants of the Deferred Compensation Plan received distributions totaling $883. There were ($1.9 million), ($340,449)no distributions in 2008 and $100,217, respectively.2007.
(7)Includes 28,452, 62,221 and 57, 309 shares at December 31, 2009, 2008 and 2007, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 6365

 

 

Notes to the Consolidated Financial Statements of Income Taxes
             
For the Years Ended December 31, 2008  2007  2006 
             
Current Income Tax Expense
            
Federal $(2,551,138) $5,512,071  $5,994,296 
State  —   1,223,145   1,424,485 
Investment tax credit adjustments, net  (42,276)  (50,579)  (54,816)
          
Total current income tax expense (benefit)  (2,593,414)  6,684,637   7,363,965 
          
             
Deferred Income Tax Expense(1)
            
Property, plant and equipment  10,347,035   2,958,758   1,697,024 
Deferred gas costs  781,635   (629,228)  (2,085,066)
Pensions and other employee benefits  (174,365)  (9,154)  (97,436)
Environmental expenditures  144,848   45,872   (5,580)
Other  311,423   (464,322)  (36,345)
          
Total deferred income tax expense (benefit)  11,410,576   1,901,926   (527,403)
          
Total Income Tax Expense
 $8,817,162  $8,586,563  $6,836,562 
          
             
Reconciliation of Effective Income Tax Rates
            
Continuing Operations            
Federal income tax expense(2)
 $7,862,760  $7,635,336  $6,212,237 
State income taxes, net of federal benefit  1,162,081   1,086,680   829,630 
Other  (207,679)  (124,555)  (42,795)
          
Total continuing operations  8,817,162   8,597,461   6,999,072 
Discontinued operations  —   (10,898)  (162,510)
          
Total income tax expense
 $8,817,162  $8,586,563  $6,836,562 
          
             
Effective income tax rate
  39.3%  39.4%  39.4%
         
At December 31, 2008  2007 
         
Deferred Income Taxes
        
Deferred income tax liabilities:
        
Property, plant and equipment $41,248,245  $31,058,050 
Environmental costs  394,869   250,021 
Other  2,414,121   860,993 
       
Total deferred income tax liabilities  44,057,235   32,169,064 
       
         
Deferred income tax assets:
        
Pension and other employee benefits  4,679,075   2,581,853 
Self insurance  370,398   384,009 
Deferred gas costs  364,498   1,146,133 
Other  2,501,210   1,416,577 
       
Total deferred income tax assets  7,915,181   5,528,572 
       
Deferred Income Taxes Per Consolidated Balance Sheet $36,142,054  $26,640,492 
       
(1)Includes $1,588,000, $260,000 and ($60,000) of deferred state income taxes for the years 2008, 2007 and 2006, respectively.
(2)Federal income taxes were recorded at 35% for each year represented.
The accompanying notes are an integral part of the financial statements.
Page 64     Chesapeake Utilities Corporation 2008 Form 10-K

A. Summary of Accounting Policies
Nature of Business
Chesapeake, incorporated in 1947 in Delaware, is a diversified utility company engaged in regulated energy, unregulated energy and other unregulated businesses. On October 28, 2009, we completed a merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. Our regulated energy business delivers natural gas distribution to approximately 65,200118,000 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 anservice 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, subsidiarypropane distribution and propane wholesale marketing operations. The natural gas marketing operation sells natural gas supplies directly to commercial and industrial customers in the States of Florida, Delaware and Maryland. The Company’s propane distribution and wholesale marketing segmentoperation provides distribution service to 35,20049,000 customers in 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-related business services and solutions for both enterprise and e-business applications.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and its wholly-owned subsidiaries. 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 PSCsPSC with respect to their rates for service, maintenance of their accounting records and various other matters. ESNG is an open access pipeline and is subject to regulationregulated by the FERC. Our financial statements are prepared in accordance with GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various regulatory commissions. The 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.rates, as approved by the regulators.
Page 66     Chesapeake Utilities Corporation 20082009 Form 10-K     Page 65

 

 

Notes to the Consolidated Financial Statements
                      
At December 31, 2008 2007 Useful Life(1)
 December 31, December 31,   
(In thousands) 2009 2008 Useful Life(1) 
Plant in service   
Mains $184,124,950 $166,202,413 27-65 years $237,133 $184,125 27-62 years
Services — utility 37,946,690 35,127,633 14-55 years 61,803 37,947 12-48 years
Compressor station equipment 24,980,668 24,959,330 44 years 24,981 24,981 42 years
Liquefied petroleum gas equipment 26,303,832 25,575,213 5-33 years 30,211 26,304 5-31 years
Meters and meter installations 19,479,360 18,111,466 Propane 10-33 years, Natural gas 25-49 years 28,419 19,479 Unregulated energy 3-33 years, regulated energy 14-49 years
Measuring and regulating station equipment 15,092,354 14,067,262 24-54 years 19,131 15,092 14-54 years
Office furniture and equipment 12,536,281 9,947,881 Non-regulated 3-10 years, Regulated 14-25 years 15,587 12,536 Unregulated energy 4-7 years, regulated energy14-25 years
Transportation equipment 11,266,723 11,194,916 3-11 years 16,805 11,267 1-20 years
Structures and improvements 10,601,819 10,024,105 10-79 years(2) 15,007 10,602 3-44 years(2)
Land and land rights 7,901,058 7,404,679 Not depreciable, except certain regulated assets 12,789 7,901 Not depreciable, except certain regulated assets
Propane bulk plants and tanks 6,296,155 5,313,061 15-40 years 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 23,676,899 20,009,979 Various 28,735 23,677 Various
           
Total plant in service 380,206,789 347,937,938   541,270 380,207 
Plus construction work in progress 1,481,448 4,899,608   2,476 1,482 
Less accumulated depreciation  (101,017,551)  (92,414,289)    (107,318)  (101,018) 
           
Net property, plant and equipment $280,670,686 $260,423,257   $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 Public Service CommissionPSC or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage value.
 
  The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.
 
(2) Includes buildings, structures used in connection with natural gas, electric and propane operations, improvements to those facilities and leasehold improvements.
Plant in service includes $1.4 million of assets owned by one of our natural gas transmission subsidiaries, which it uses to provide natural gas transmission service under a contract with a third-party. This contract is accounted for as an operating lease due to exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and provides $264,000 in annual revenues for a term of 20 years. Accumulated depreciation for these assets total $74,000 at December 31, 2009.
Cash and Cash Equivalents
The Company’sOur policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 67

Inventories
The Company usesWe use the average cost method to value propane, and materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.
Regulatory Assets, Liabilities and Expenditures
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.
Page 66     Chesapeake Utilities Corporation 2008 Form 10-K

At December 31, 20082009 and 2007,2008, 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.
         
At December 31, 2008  2007 
Regulatory Assets
        
Current
        
Underrecovered purchased gas costs $650,820  $1,389,454 
Swing transportation imbalances  2,059   — 
PSC Assessment  18,575   22,290 
Flex rate asset  107,943   107,394 
Other  46,612   55,934 
       
Total current  826,009   1,575,072 
         
Non-Current
        
Income tax related amounts due from customers  1,284,552   1,115,638 
Deferred regulatory and other expenses  646,126   446,642 
Deferred gas supply  12,667   15,201 
Deferred post retirement benefits  83,370   111,159 
Environmental regulatory assets and expenditures  779,480   850,594 
       
Total non-current  2,806,195   2,539,234 
       
 
Total Regulatory Assets $3,632,204  $4,114,306 
       
         
Regulatory Liabilities
        
Current
        
Self insurance — current $162,616  $191,004 
Overrecovered purchased gas costs  1,542,174   4,225,845 
Shared interruptible margins  231,919   11,202 
Conservation cost recovery  743,874   395,379 
Swing transportation imbalances  546,754   1,477,336 
       
Total current  3,227,337   6,300,766 
         
Non-Current
        
Self insurance — long-term  749,827   757,557 
Income tax related amounts due to customers  125,279   151,521 
Environmental overcollections  —   226,993 
       
Total non-current  875,106   1,136,071 
         
Accrued asset removal cost  20,641,279   20,249,948 
       
 
Total Regulatory Liabilities $24,743,722  $27,686,785 
       
         
  December 31,  December 31, 
(in thousands) 2009  2008 
 
Regulatory Assets
        
Underrecovered purchased gas costs $1,149  $651 
Income tax related amounts due from customers  1,783   1,285 
Deferred post retirement benefits  3,636   83 
Deferred transaction and transition costs  1,486   — 
Deferred piping and conversion costs  1,061   — 
Deferred development costs  1,698   — 
Environmental regulatory assets and expenditures  7,510   779 
Acquisition adjustment(1)
  795   — 
Loss on reacquired debt  154   — 
Other  1,793   834 
       
Total Regulatory Assets $21,065  $3,632 
       
         
Regulatory Liabilities
        
Self insurance $982  $912 
Overrecovered purchased gas costs  7,304   1,542 
Shared interruptible margins  84   232 
Conservation cost recovery  1,035   744 
Rate refund(2)
  258   — 
Income tax related amounts due to customers  729   125 
Storm reserve  2,554   — 
Accrued asset removal cost  33,214   20,641 
Other  90   547 
       
Total Regulatory Liabilities $46,250  $24,743 
       
(1)Net carrying value of goodwill from FPU’s previous acquisition that is allowed to be amortized pursuant to a rate order.
(2)Refunded to FPU natural gas customers in February 2010.
Included in the current regulatory assets listed above is a flex rate asset of approximately $108,000,$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 $1.7 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, $623,000 will be collected within approximately three to ten years, $83,000 will be collected within approximately 11 to 15 years, and $481,000 will be collected within approximately 16-25 years. In addition, there is approximately $711,000income tax related amounts, for which the Company iswe are awaiting regulatory approval from various jurisdictions for recovery; once approved, this amountrecovery. For certain regulatory assets, such as under-recovered purchased fuel costs, deferred rate case costs and development costs, only recovery of the deferred costs is expected to be collected overallowed in rates and we do not earn a period greater than 12 months.return on those regulatory assets.
As required by SFAS No. 71, the Company monitors itsPage 68     Chesapeake Utilities Corporation 2009 Form 10-K

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.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 67

Notes to the Consolidated Financial Statements
Goodwill and Other Intangible Assets
The Company accounts for its goodwill and other intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Under SFAS No. 142, goodwillGoodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note G,H, “Goodwill and Other Intangible Assets,” to the Consolidated Financial Statements for additional discussion of this subject.
Other Deferred Charges
Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.
Pension and Other Postretirement Plans
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returnreturns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. The CompanyManagement annually reviews the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of a third-party actuarial firm.firms. The assumed discount raterates and the expected returnreturns on plan assets are the assumptions that generally have the most significant impact on the Company’sour pension costs and liabilities. The assumed discount rate, the assumedrates, health care cost trend raterates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rate isrates 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 rate, the Company considersrates, we consider high quality corporate bond rates based on Moody’s Aa bond index, the Citigroup yield curve, changes in those rates from the prior year, and other pertinent factors, such as the expected life of the planeach of our plans and the lump-sum-payment option.their respective payment options.
The expected long-term raterates of return on assets isare utilized in calculating the expected returnreturns on plan assets component of our annual pension and postretirement plan costs. The Company estimatesWe estimate the expected returnreturns 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. The CompanyWe also considersconsider the guidance from itsour investment advisors in making a final determination of itsour expected raterates of return on assets.
The Company estimatesWe estimate the assumed health care cost trend raterates used in determining our postretirement net expense based upon its actual health care cost experience, the effects of recently enacted legislation and general economic conditions. The Company’sOur assumed rate of retirement is estimated based upon itsour annual reviewreviews of its participant census information as of the measurement date.
Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension costs ultimately recognized. A 0.25 percent change in the Company’s discount rate would impact our defined pension cost by approximately $10,000, impact the Pension SERP costs by approximately $2,000 and postretirement costs by approximately $7,000. A 0.25 percent change in the Company’s expected rate of return would impact our defined pension costs by approximately $16,000 and will not have an impact on either the Pension SERP or the other postretirement costs because these plans are unfunded.
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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 the enacted tax 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.
The Company adopted the provisions of FIN 48, “Uncertain Tax Positions,” (“FIN 48”) effective January 1, 2007. FIN 48 clarifies the accountingWe account for uncertainty in income taxes recognized in a Company’sthe financial statements in accordance with SFAS No. 109. FIN 48 requires that an uncertain tax position should be recognized only if it is “more likely than not” that thean uncertain tax position is sustainable based on technical merits. Recognizable tax positions shouldare then be measured to determine the amount of benefit recognized in the financial statements. The Company’s adoption of FIN 48 did not have an impact on its financial condition or results of operations.
Financial Instruments
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 resultingThere were unrealized gainslosses of $1.6 million in 2009 and losses are recorded as assets or liabilities, respectively. There were unrealized gains of $1.4 million and $179,000 at December 31, 2008 and 2007, respectively.in 2008. Trading liabilities are recorded in mark-to-market energy liabilities. Trading assets are recorded in mark-to-market energy assets.
The Company’sOur natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives under 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 may enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. Wholesale propane prices rose dramatically during the spring months ofDuring 2008, when they are traditionally at their lowest. In effortswe entered into a swap agreement to protect the Company from the impact that additionalpropane price increases would have on the Pro-Cap (propane price cap) Plan that we offer to customers, the Delmarva propane distribution operation had entered intooffers to our customers. Propane prices declined significantly in late 2008 and we recorded a mark-to-market loss of approximately $939,000 on the swap agreement. By December 31,agreement in 2008, which increased the market pricecost of propane declined well below the unit price insales. In January 2009, we terminated the swap agreement. AsDuring 2009, we purchased a result,put option related to the Company marked the January 2009Pro-Cap Plan, which we accounted for on a mark-to-market basis, and February 2009 gallons in the agreement to market, which increased 2008 costrecorded a loss of sales by $939,000. The Company terminated this swap agreement in January 2009.$41,000. At December 31, 2007,2009 and 2008, we had $0 in fair value of the Company had not hedged anyput agreement and $(105,000) in fair value of its propane inventories.the swap agreement, respectively.
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Notes to the Consolidated Financial Statements
Earnings Per Share
Chesapeake calculatesBasic earnings per share in accordance with SFAS No. 128.are computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities, such as convertible debt and share-based compensation. The calculations of both basic and diluted earnings per share are presented in the following chart.
                        
For the Periods Ended December 31, 2008 2007 2006 
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 $13,607,259 $13,197,710 $10,506,525  $15,897 $13,607 $13,198 
Weighted average shares outstanding 6,811,848 6,743,041 6,032,462  7,313,320 6,811,848 6,743,041 
              
Basic Earnings Per Share
 $2.00 $1.96 $1.74  $2.17 $2.00 $1.96 
              
  
Calculation of Diluted Earnings Per Share:
  
Reconciliation of Numerator:
  
Net Income $13,607,259 $13,197,710 $10,506,525  $15,897 $13,607 $13,198 
Effect of 8.25% Convertible debentures 88,657 95,611 105,024  79 89 96 
              
Adjusted numerator — Diluted $13,695,916 $13,293,321 $10,611,549  $15,976 $13,696 $13,294 
              
  
Reconciliation of Denominator:
  
Weighted shares outstanding — Basic 6,811,848 6,743,041 6,032,462  7,313,320 6,811,848 6,743,041 
Effect of dilutive securities:  
Share-based Compensation 12,083 — —  34,229 12,083 — 
8.25% Convertible debentures 103,552 111,675 122,669  92,652 103,552 111,675 
              
Adjusted denominator — Diluted 6,927,483 6,854,716 6,155,131  7,440,201 6,927,483 6,854,716 
              
 
Diluted Earnings Per Share
 $1.98 $1.94 $1.72  $2.15 $1.98 $1.94 
              
Common stock issued in connection with the FPU merger (See Note B, “Acquisitions and Dispositions,” to the Consolidated Financial Statements) increased weighted average shares outstanding during 2009.
Operating Revenues
Revenues for theour natural gas and electric distribution operations of the Company are based on rates approved by the PSCs inof the jurisdictionsstates in which the Company operates.they operate. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have allowed the natural gas distributionauthorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. The natural gas transmission operation canFERC has also authorized ESNG to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as a recourse to negotiated rates.
For regulated deliveries of natural gas Chesapeake readsand electricity, we read meters and billsbill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accruesWe accrue unbilled revenues for natural gas and electricity that hashave been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, Chesapeakewe must estimate the amount of natural gas and electricity that hashave not been accounted for on itsour delivery systemsystems and must estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers.customers, and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in the Company’s income statement. Theour consolidated statement of income. For propane distribution customers without meters and advanced information services and other segmentscustomers, we record revenue in the period in which the products are delivered and/or services are rendered.
Chesapeake’sChesapeake Utilities Corporation 2009 Form 10-K     Page 71

Each of our natural gas distribution operations in Delaware and Maryland, havebundled natural gas distribution service in Florida and electric distribution operation in Florida has a PSC-approved purchased gasfuel cost recovery mechanism. This mechanism provides the Company with a method of adjusting the billing rates with its customers forto reflect changes in the cost of purchased gas included in base rates.fuel. The difference between the current cost of gasfuel purchased and the cost of gasfuel recovered in billed rates is deferred and accounted for as either unrecovered purchased gasfuel costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.
Page 70     Chesapeake Utilities Corporation 2008 Form 10-K

The Company chargesWe charge flexible rates to itsour natural gas distribution’sdistribution industrial interruptible customers to compete with prices of alternative types of fuel. Based on pricing,fuels, which these customers can choose natural gas or alternative fuels.are able to use. Neither the Company nor theany of its interruptible customercustomers is contractually obligated to deliver or receive natural gas.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 utilityregulated and non-utility operations.unregulated energy segments. These costs include primarily include 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 segment.operation.
Operations and Maintenance Expenses
Operations and maintenance expenses are costs associated with the operation and maintenance of the Company’s utilityour regulated and non-utilityunregulated 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 the Company’sour collections experiences and the Company’smanagement’s assessment of itsour 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
The Company’sOur financial statements are prepared in conformity with GAAP, thatwhich require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes NNote O, “Environmental Commitments and OContingencies,” 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.
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 amountssuch deferred in accordance with SFAS No. 71amounts 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.
Financial Accounting Standards Board (“FASB”) Statements and Other Authoritative Pronouncements
Recent accounting pronouncements:
In December 2007, the FASB issued SFAS No. 141(R), which retains the fundamental requirements of the original pronouncement requiring that the acquisition method be used for all 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. SFAS No. 141(R) also requires that acquisition-related costs be expensed as incurred. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No.141(R) to have a material impact on its current consolidated financial position and results of operations. However, depending upon the size, nature and complexity of future acquisition transactions, the adoption of SFAS No. 141(R) could materially affect the Company’s consolidated financial statements.
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NotesAcquisition Accounting
The merger with FPU was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in the merger be recognized at their fair value as of the acquisition date. It also establishes that the consideration transferred be measured at the closing date of the merger at the then-current market price. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability and fair value measures for an asset assume the highest and best use by those market participants, rather than the acquirer’s intended use of those assets. Many of these fair value measurements can be highly subjective and it is also possible that others applying reasonable judgment to the same facts and circumstances could develop and support a range of alternative estimated amounts. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature and impact of such regulations on those assets and liabilities as a factor in determining their appropriate fair value. We also considered the existence of a regulatory process that would allow, or sometimes require, regulatory assets and liabilities to be established for fair value adjustment to certain assets and liabilities subject to rate regulation. If a regulatory asset or liability should be established to offset the fair value adjustment based on the current regulatory process, as was the case for fuel contracts and long-term debt, we did not “gross-up” our balance sheet to reflect the fair value adjustment and corresponding regulatory asset/liability, because such “gross-up” would not have resulted in a change to the value of net assets and future earnings of the Company.
Total value of the consideration transferred by Chesapeake in the merger was $75.7 million. Net fair value of the assets acquired and liabilities assumed in the merger was estimated to be $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. Note B, “Acquisitions and Dispositions,” to the Consolidated Financial Statements describes more fully the purchase price allocation.
In December 2007,The acquisition method of accounting also requires acquisition-related costs to be expensed in the FASB issued SFAS No. 160, an amendment of Accounting Research Bulletin No. 51,period in which changes the accounting and reporting for minority interests by recharacterizing them as noncontrolling interests and classifyingthose costs are incurred, rather than including them as a component of equity. This new consolidation method significantly changesconsiderations transferred. It also prohibits an accrual of certain restructuring costs at the accounting for transactions with minority interest holders. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. No other entity has a minority interest in anytime of the Company’s subsidiaries; therefore,merger for the Company does notacquiree. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining proper accounting treatment for the merger-related costs. During 2009, we incurred approximately $3.0 million to consummate the merger, including the cost associated with merger-related litigation, and integrate operations following the merger. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at December 31, 2009, which represents our estimate, based on similar proceedings in Florida in the past, of the costs which we expect to be permitted to recover when we complete the appropriate rate proceedings.
Subsequent Events
We have assessed and reported on subsequent events through the date of issuance of these Consolidated Financial Statements.
Reclassifications
As a result of the merger with FPU in 2009, we changed our operating segments (see Note C, “Segment Information,” to the Consolidated Financial Statements). We revised the 2008 and 2007 segment information to reflect the new segments. We also revised the 2008 segment information by reclassifying transaction costs, which were previously allocated to all segments, to the “Other” segment. We reclassified certain amounts in the statements of income and cash flows for the years ended December 31, 2008 and 2007, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our Consolidated Financial Statements.
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”) ASC, which is now the single source of authoritative accounting principles in the United States. The adoption of SFAS No. 160 tothe ASC did not have a material impact on its current consolidatedour financial position and results of operations. As a result of this adoption, we updated all references to accounting and reporting standards included in this Form 10-K and in some instances provided references to both pre-and post-Codification standards, as appropriate.
FASB Statements and Other Authoritative Pronouncements
Recent Accounting Pronouncements Yet to be Adopted by the Company
In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (IFRS). IFRS is(“IFRS”), a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”). Under the proposed roadmap, the Companywe may be required to prepare financial statements in accordance with IFRS as early as 2014. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. The Company is currently assessingIn July 2009, the impactIASB 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 this potential change would have on its consolidated financial statements, and itarise in the context of cost-of-service regulation, to which we are subject in our rate-regulated businesses. We will continue to monitor the development of the potential implementation of IFRS.
The FASB has issued ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in ASC Subtopic 820-10. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We are currently assessing the potential impact of this pronouncement.
Other Accounting Amendments Adopted by the Company in 2009:
In December 2007, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 141(R), now codified within ASC Topic 805, “Business Combinations.” SFAS No.141(R): (a) defines the acquirer as the entity that obtains control of one or more businesses in a business combination; (b) establishes the acquisition date as the date that the acquirer achieves control; and (c) requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interests at their fair values as of the acquisition date. It also requires that acquisition-related costs be expensed as incurred. Provisions of this standard were adopted effective January 1, 2009. The merger with FPU, effective October 28, 2009, was accounted for using provisions of this standard. For further discussion, see Note B, “Acquisition and Dispositions” to the Consolidated Financial Statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133, which133.” SFAS No. 161 was codified within ASC Sections 815-10-15 and 65, of the Topic, “Derivatives and Hedging,” and it requires enhanced disclosures for derivative instruments including those used inand hedging activities. It is effectiveactivities including: (i) how and why a company uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for fiscal yearsunder the Derivatives and interim periods beginning after November 15, 2008,Hedging Topic, and will be applicable to(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, in the first quartereffective January 1, 2009. Adoption of fiscal 2009. The Company doesthis standard did not expect the adoption of SFAS No. 161 to have a materialan impact on its currentour consolidated financial 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 FSP 142-3. This FSP amendsFASB 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 whichthat should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”).asset. The intent of this FSPthese provisions is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R and other GAAP. This FSP isasset. We adopted this standard, effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The Company doesJanuary 1, 2009. Adoption of this standard did not expect the adoption of FSP SFAS No. 142-3 to have a materialan impact on its currentour consolidated financial position and results of operations.
In May 2008, the FASB issued SFAS No. 162 with the intent to improve financial reporting by identifying a consistent framework, or hierarchy,FSP APB 14-1, “Accounting for selecting accounting principles to be usedConvertible Debt Instruments That May Be Settled in preparing financial statements that are presented in conformity with GAAP in the United States for non-governmental entities. SFAS No. 162 is effective 60 days following approval by the SECCash 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 Public Company Accounting Oversight Board’s amendments to AUTopic, “Debt,” (b) ASC Section 411, “The Meaning815-15-55, of Present Fairly in Conformity with Generally Accepted Accounting Principles.the Topic, “Derivatives and Hedging,” The Company does not expectand (c) ASC Section 825-10-15, of the adoption of SFAS No. 162 to have a material impact on the preparation of its consolidated financial statements.
In May 2008, the FASB issuedTopic, “Financial Instruments.” FSP Accounting Principles Board (“APB”) APB 14-1 which clarifies that companies with convertible debt instruments, thatwhich may be settled in cash upon either mandatory or optional conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants.” In addition, FSP APB 14-1 specifies that issuers of such instruments, 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. FSP APB 14-1 isWe adopted this standard, effective, for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.January 1, 2009. The Company does not expect the adoption of FSP APB 14-1 tothis standard did not have a materialan impact on its currentour consolidated financial position and results of operations.
Page 72     Chesapeake Utilities Corporation 2008 Form 10-K

In JuneSeptember 2008, the FASB issued FSP Emerging Issues Task force (“EITF”)Force 03-6-1, to clarify“Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP, codified within FASB ASC Sections 260-10-45, 55 and 65, of the Topic, “Earnings Per Share,” clarifies that allholders of outstanding unvested share-based payment awards that containcontaining rights to nonforfeitable dividends participate with common shareholders in undistributed earnings with common shareholders.earnings. Awards of this nature are considered participating securities, and the two-class method of computing basic and diluted earnings per share must be applied. This FSP isWe adopted this standard, effective for fiscal years beginning after December 15, 2008.January 1, 2009. The Company does not expect the adoption of EITF 03-6-1 tothis standard did not have a materialan impact on its currentour consolidated financial position and results of operations.
In JuneDecember 2008, the FASB ratified EITF 07-5. EITF 07-5 provides that an entity should useissued 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 two-step approachdefined 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 evaluate whether an equity-linkedmeasure 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 instrument (or embedded feature) is indexed to its own stock, including evaluatingreporting by increasing the instrument’s contingent exercise and settlement provisions. It also clarifies the impactfrequency of foreign-currency-denominated strike prices and market-based employee stock option valuation instruments on the evaluation. EITF 07-5 isfair value disclosures. The provisions of this standard are effective for fiscal years beginninginterim and annual reporting periods ending after DecemberJune 15, 2008.2009, and they did not have an impact on our consolidated financial position and results of operations. The Company does not expectdisclosures 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 EITF 07-5 tothis standard did not have a materialan impact on its currentour consolidated financial position and results of operations.
In June 2008, the FASB ratified EITF 08-3 to provide guidance for accounting for nonrefundable maintenance deposits. It also provides revenue recognition accounting guidance for the lessor. EITF 08-3 is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of EITF 08-3 to have a material impact on its current consolidated financial position and results of operations.
In September 2008, the FASB ratified EITF 08-5 to provide guidance for measuring liabilities issued with an attached third-party credit enhancement (such as a guarantee). It clarifies that the issuer of a liability with a third-party credit enhancement should not include the effect of the credit enhancement in the fair value measurement of the liability. EITF 08-5 is effective for the first reporting period beginning after December 15, 2008. The Company does not expect the adoption of EITF 08-5 to have a material impact on its current consolidated financial position and results of operations.
During 2008, the Company adopted the following accounting standards:
In September 2008, the FASB issued FSP 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (“FSP 133-1/FIN 45-4”). FSP 133-1/FIN 45-4 amends and enhances disclosure requirements for sellers of credit derivatives and financial guarantees. It also clarifies that the disclosure requirements of SFAS No. 161 are effective for quarterly periods beginning after November 15, 2008, and fiscal years that include those periods. FSP 133-1/FIN 45-4 is effective for reporting periods (annual or interim) ending after November 15, 2008. The implementation of this standard did not have a material impact on the Company’s consolidated financial position and results of operations.
In October 2008, the FASB issued FSP 157-3 to clarify the application of the provisions of SFAS No. 157 in an inactive market and how an entity would determine fair value in an inactive market. FSP 157-3 is effective immediately and applied to the Company’s September 30, 2008 financial statements. The application of the provisions of FSP 157-3 did not materially affect the company’s results of operations or financial condition as of and for the period ended December 31, 2008.
Chesapeake Utilities Corporation 20082009 Form 10-K     Page 7375

 

 

Notes to the Consolidated Financial Statements
Effective January 1, 2008, Chesapeake adopted FIN 39-1, which permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. Based on the derivative contracts entered into to date, adoption of this FSP has not materially affected the Company’s consolidated financial statements for the period ended December 31, 2008.
In September 2006,August 2009, the FASB issued SFASFASB Accounting Standards Update (“ASU”) No. 157,2009-05, “Fair Value Measurement and Disclosures — Measuring Liabilities at Fair Value.” This ASU provides clarification that in circumstances in which provides guidancea quoted price in an active market for using fair value to measure assets and liabilities. It also responds to investors’ requests for expanded information about the extent to which companies’ measure assets and liabilities at fair value, the information usedan 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 effectadoption of fair value measurementsthis standard did not have an impact on earnings. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilitiesour consolidated financial position and results of operations.
B. Acquisitions and Dispositions
FPU
On October 28, 2009, we completed the previously announced merger with FPU, pursuant to be measuredwhich FPU became a wholly-owned subsidiary of Chesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes.
The merger allowed us to become a larger energy company serving approximately 200,000 customers in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. The merger increases our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing operations in Florida. It also introduces us to the electric distribution business as we incorporate FPU’s approximately 31,000 electric customers in northwest and northeast Florida.
In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at fair value and does not expand the usea price per share of fair value$30.42 in any new circumstances. In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement No. 13” (“FSP 157-1”), and FSP 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-1 amends SFAS No. 157 to remove certain leasing transactions from its scope. FSP 157-2 delays the effective date of SFAS No. 157 until fiscal years beginning after November 15, 2009exchange for all non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair valueoutstanding common stock of FPU. We also paid approximately $16,000 in lieu of issuing fractional shares in the financial statements on a recurring basis. These non-financial items include assets and liabilities, such as reporting units measured at fairexchange. There is no contingent consideration in the merger. Total value of considerations transferred by Chesapeake in a goodwill impairment test and non-financialthe 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 business combination. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007 and was adopted by the Company, as it applies to its financial instruments, effective January 1, 2008. Adoption of SFAS No. 157 had no financial impact12-year period based on the Company’s consolidated financial statements.expected duration of benefit arising from the relationships. The disclosures required by SFAS No. 157 are discussed inintangible value assigned to favorable propane contracts, will be amortized over a period ranging from one to 14 months based on contractual terms. See Note E — “Fair Value of Financial Instruments” ofH, “Goodwill and Other Intangible Assets,” to the Consolidated Financial Statements.
In February 2007,Current assets of $26.7 million acquired during the FASB issued SFAS No. 159,merger include notes receivable of approximately $5.8 million, for which permits entitieswe expect to elect to measurereceive 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 fair value many financial instrumentsJanuary 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 certain other items that are not currently required to be measured at fair value. This election is irrevocable. SFAS No. 159 became effective innecessarily indicative of what the first quarter of fiscal 2008. The Company has not elected to applyactual results would have been had the fair value option to any of its financial instruments.acquisitions actually occurred on January 1, 2009, and January 1, 2008, respectively.
Reclassification of Prior Years’ AmountsOnSight
The Company reclassified some previously reported amounts to conform to current period classifications.
B. Business Dispositions and Discontinued Operations
During 2007, Chesapeakewe decided to close itsour distributed energy services subsidiary, OnSight, which had experienced operating losses since its inception in 2004. OnSight was previously reported as part of the Company’s Other Business segment. The results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. The discontinued operations experienced a net loss of $20,000 for 2007, compared to a net loss of $241,000 for 2006. The Company2007. We did not have any discontinued operations in 2008.2008 and 2009.
C. Segment Information
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income.
As a result of the merger with FPU, we changed our operating segments to better align with how the chief operating decision maker views the various operations of the Company. Our three operating segments are now composed of the following:
•
Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of ESNG.
•
Unregulated Energy.The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services.
•
Other. The “Other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.
We also reclassified the segment information for 2008 and 2007 to reflect the new segments. During 2009, we also decided not to allocate merger-related transaction costs to different operations for the purpose of reporting their operating profitability because such costs are not directly attributable to their operations. To conform to the current year’s presentation, we revised the 2008 segment information by reclassifying transaction costs, which were previously allocated to all segments, to the “Other” segment.
Page 7478     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

C. Segment Information
The following table presents information about the Company’sour reportable segments. The table excludes financial data related to its former distributed energy company,service subsidiary, OnSight, which was reclassified to discontinued operations for each year presented.2007.
                        
For the Years Ended December 31, 2008 2007 2006  2009 2008 2007 
(in thousands) 
 
Operating Revenues, Unaffiliated Customers
  
Natural gas $210,957,687 $180,842,699 $170,114,512 
Propane 65,873,930 62,837,696 48,575,976 
Advanced information services 14,611,860 14,606,100 12,509,077 
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 $291,443,477 $258,286,495 $231,199,565  $268,785 $291,443 $258,287 
              
 
Intersegment Revenues(1)
  
Natural gas $444,083 $359,235 $259,970 
Propane 2,861 406 — 
Advanced information services 108,596 492,840 58,532 
Regulated Energy $1,252 $924 $359 
Unregulated Energy 254 3 — 
Other 652,296 622,272 618,492  779 761 $1,115 
              
Total intersegment revenues $1,207,836 $1,474,753 $936,994  $2,285 $1,688 $1,474 
              
 
Operating Income
  
Natural gas $25,846,346 $22,485,266 $19,733,487 
Propane 1,586,414 4,497,843 2,534,035 
Advanced information services 694,636 835,981 767,160 
Other and eliminations 351,538 294,492 297,255 
Regulated Energy $26,900 $24,733 $21,809 
Unregulated Energy 8,158 3,781 5,174 
Other  (1,322)  (35) 1,131 
              
Operating Income 28,478,934 28,113,582 23,331,937  33,736 28,479 28,114 
  
Other income 103,039 291,305 189,093  165 103 291 
Interest charges 6,157,552 6,589,639 5,773,993  7,086 6,158 6,590 
Income taxes 8,817,162 8,597,461 6,999,072  10,918 8,817 8,597 
              
Net income from continuing operations $13,607,259 $13,217,787 $10,747,965  $15,897 $13,607 $13,218 
              
 
Depreciation and Amortization
  
Natural gas $6,694,037 $6,917,609 $6,312,277 
Propane 2,024,172 1,842,047 1,658,554 
Advanced information services 175,295 143,706 112,729 
Other and eliminations 111,407 156,823 160,155 
Regulated Energy $8,866 $6,694 $6,918 
Unregulated Energy 2,415 2,024 1,842 
Other 307 287 300 
              
Total depreciation and amortization $9,004,911 $9,060,185 $8,243,715  $11,588 $9,005 $9,060 
              
 
Capital Expenditures
  
Natural gas $25,386,046 $23,086,713 $43,894,614 
Propane 3,416,514 5,290,215 4,778,891 
Advanced information services 678,705 174,184 159,402 
Regulated Energy $22,917 $25,386 $23,087 
Unregulated Energy 1,873 3,417 5,290 
Other 1,362,246 1,591,272 321,204  1,504 2,041 1,765 
              
Total capital expenditures $30,843,511 $30,142,384 $49,154,111  $26,294 $30,844 $30,142 
              
   
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
             
At December 31, 2008  2007  2006 
             
Identifiable Assets
            
Natural gas $297,407,548  $273,500,890  $252,292,600 
Propane  72,954,861   94,966,212   60,170,200 
Advanced information services  3,544,847   2,507,910   2,573,810 
Other  11,849,010   10,533,511   10,503,804 
          
Total identifiable assets $385,756,266  $381,508,523  $325,540,414 
          
         
  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 20082009 Form 10-K     Page 7579

 

 

Notes to the Consolidated Financial Statements
Chesapeake uses the management approach to identify operating segments. Chesapeake organizes its business around differences in products or services, and the operating results of each segment are regularly reviewed by the Company’s chief operating decision maker in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income.
The Company’sOur operations are primarilyalmost 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 and 2006 waswere as follow:follows:
                        
For the Years Ended December 31, 2008 2007 2006  2009 2008 2007 
(in thousands) 
Cash paid for interest $5,835,321 $5,592,279 $5,334,477  $6,703 $5,835 $5,592 
Cash paid for income taxes $3,884,921 $7,009,206 $6,285,272  $1,111 $3,885 $7,009 
Non-cash investing and financing activities during the years ended December 31, 2009, 2008, 2007, and 20062007 were as follow:follows:
                        
For the Years Ended December 31, 2008 2007 2006  2009 2008 2007 
(in thousands) 
Capital property and equipment acquired on account, but not paid as of December 31 $696,268 $365,890 $1,490,890  $1,151 $696 $366 
Merger with FPU $75,682 $— $— 
Retirement Savings Plan $158,756 $948,683 $914,811  $982 $159 $949 
Dividends Reinvestment Plan $208,194 $840,718 $844,920  $692 $208 $841 
Conversion of Debentures $176,740 $137,784 $283,417  $135 $177 $138 
Performance Incentive Plan $568,361 $435,309 $715,494  $— $568 $435 
Director Stock Compensation Plan $181,312 $183,573 $175,617  $214 $181 $184 
Tax benefit on stock warrants $50,244 — $201,455  $— $50 $— 
E. Derivative Instruments
As of December 31, 2009, we had the following outstanding trading contracts which we accounted for as derivatives:
             
  Quantity in  Estimated Market  Weighted Average 
At December 31, 2009 gallons  Prices  Contract Prices 
Forward Contracts
            
Sale  11,944,800  $0.6900 — $1.3350  $1.1264 
Purchase  11,256,000  $0.7275 — $1.3350  $1.1367 
Other Contract
            
Put option  1,260,000  $—  $0.1500 
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in the first quarter of 2010.
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
Effective January 1, 2008, the Company adopted SFAS No. 157 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and liabilities that are measured and reported on a fair value basis. Adoption of SFAS No. 157 had no impact on the Consolidated Balance Sheets and Statements of Income. The primary effect of SFAS No. 157 on the Company was to expand the required disclosures pertaining to the methods used to determine fair values.
SFAS No. 157 alsoGAAP 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 under SFAS No. 157 are the following:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).
The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2009:
                 
      Fair Value Measurements Using: 
          Significant Other  Significant 
      Quoted Prices in  Observable  Unobservable 
      Active Markets  Inputs  Inputs 
(in thousands) Fair Value  (Level 1)  (Level 2)  (Level 3) 
Assets:                
Investments $1,959  $1,959  $—  $— 
Mark-to-market energy assets, including put option $2,379  $—  $2,379  $— 
                 
Liabilities:                
Mark-to-market energy liabilities $2,514  $—  $2,514  $— 
Page 7682     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

The following table summarizes the Company’sour financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2008:
                
 Fair Value Measurements Using:                 
 Significant    Fair Value Measurements Using: 
 Other Significant  Significant Other Significant 
 Quoted Prices in Observable Unobservable  Quoted Prices in Observable Unobservable 
 Active Markets Inputs Inputs  Active Markets Inputs Inputs 
(in thousands) Fair Value (Level 1) (Level 2) (Level 3)  Fair Value (Level 1) (Level 2) (Level 3) 
Assets:  
Investments $1,601 $1,601 — —  $1,601 $1,601 $— $— 
Mark-to-market energy assets $4,482 — $4,482 — 
Mark-to market energy assets $4,482 $— $4,482 $— 
  
Liabilities:  
Mark-to-market energy liabilities $3,052 — $3,052 — 
Price swap agreement $105 — $105 — 
Mark-to market energy liabilities $3,052 $— $3,052 $— 
Propane swap agreement $105 $— $105 $— 
The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of December 31, 2009 and 2008:
Level 1 Fair Value Measurements:
Investments— The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
Level 2 Fair Value Measurements:
Mark-to-market energy assets and liabilities —These forward contracts are valued using market transactions in either the listed or OTC markets.
Propane price swap agreement and put option —The fair value of the propane price swap agreement and put option is valued using market transactions for similar assets and liabilities in either the listed or OTC markets.
In addition, various items within the balance sheet are consideredAt December 31, 2009, there were no non-financial assets or liabilities required to be financial instruments, because they arereported 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 or are to be settled in 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 valuesvalue of these items generallyfinancial assets and liabilities approximates fair value due to their short maturities and because interest rates approximate their fair value. Thecurrent market rates for short-term debt.
At December 31, 2009, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $134.1 million, compared to a fair value of the Company’s long-term debt is estimated$145.5 million, using a discounted cash flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile. The Company’s long-term debt atAt December 31, 2008, including current maturities, had anthe estimated fair value ofwas approximately $92.3 million, compared to a carrying value of $93.1 million. At December 31, 2007, the estimated fair value was approximately $75.0 million compared to a carrying value of $70.9 million.
The Company’s adoption of SFAS No. 157 applies only to its financial instruments and does not apply to those non-financial assets and non-financial liabilities delayed under FSP No. 157-2, which will be implemented for fiscal years beginning after November 15, 2009.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 77

Notes to the Consolidated Financial Statements
F.G. Investments
The investment balances at December 31, 20082009 and 20072008 represent a Rabbi Trust associated with the Company’sour Supplemental Executive Retirement Savings Plan and a Rabbi Trust related to a stay bonus agreement with a former executive. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifiesWe classify these investments as trading securities. As a result of classifyingsecurities and report them as trading securities, the Company is 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. The CompanyWe also hashave an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust.Rabbi Trusts. At December 31, 20082009 and 2007,2008, total investments had a fair value of $1.6$2.0 million and $1.9$1.6 million, respectively.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 83

G.H. Goodwill and Other Intangible Assets
In accordanceOn October 28, 2009, we completed the merger with SFAS No. 142,FPU, which resulted in $33.4 million in goodwill, is tested for impairment at least annually. In addition,the regulated energy segment. The regulated energy segment did not have goodwill prior to the merger. As of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduceDecember 31, 2009 and 2008, the fair value of a reporting unit below its carrying value. The propaneunregulated 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 the two years ended December 31,impairment of goodwill at least annually. The impairment testing for 2009 and 2008 and 2007. Testing for 2008 and 2007 indicated that no impairment of goodwill.
We intend to seek recovery of the purchase premium related to the 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 occurred.been authorized, to a regulatory asset.
The carrying value and accumulated amortization of intangible assets subject to amortization for the years ended December 31, 20082009 and 20072008 are as follow:follows:
                 
  December 31, 2008  December 31, 2007 
  Gross      Gross    
  Carrying  Accumulated  Carrying  Accumulated 
  Amount  Amortization  Amount  Amortization 
 
Customer lists $115,333  $89,481  $115,333  $82,269 
Acquisition costs  263,659   125,243   263,659   118,650 
             
Total $378,992  $214,724  $378,992  $200,919 
             
                 
  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 
             
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 $14,000 for the years ended December 31, 20082010 to 2014 is: $655,000 for 2010, $305,000 for 2011, $302,000 for 2012, $298,000 for 2013, and 2007. The estimated annual amortization of intangibles is $14,000 per year$298,000 for each of the years 2009 through 2013.2014.
Page 7884     Chesapeake Utilities Corporation 20082009 Form 10-K

 

 

H. Stockholders’ EquityI. Income Taxes
ChangesWe 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 common stock sharesour 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 outstanding2006 federal and state corporate income tax returns to reflect the disallowed expense deductions. We are shownno longer subject to income tax examinations by the Internal Revenue Service for years before December 31, 2006. FPU filed a separate federal income tax return for the period prior to the merger and is 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 table below:2008 American Recovery and Reinvestment Act, which allowed bonus depreciation for certain assets. A federal tax net operating loss of $9,049,132 was carried forward to 2009 and fully offset taxable income for the 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 tax net operating losses because we believe they will all be utilized.
             
For the Years Ended December 31, 2008  2007  2006 
             
Common Stock shares issued and outstanding(1)
            
Shares issued — beginning of period balance  6,777,410   6,688,084   5,883,099 
Dividend Reinvestment Plan(2)
  9,060   35,333   38,392 
Retirement Savings Plan  5,260   29,563   29,705 
Conversion of debentures  10,397   8,106   16,677 
Employee award plan  250   350   350 
Share-based compensation(3)
  24,744   15,974   29,516 
Public offering  —   —   690,345 
          
Shares issued — end of period balance(4)
  6,827,121   6,777,410   6,688,084 
Treasury shares — beginning of period balance  —   —   (97)
Purchases  (2,425)  (971)  — 
Deferred Compensation Plan  2,425   971   — 
Other issuances  —   —   97 
          
Treasury Shares — end of period balance  —   —   — 
          
 
Total Shares Outstanding  6,827,121   6,777,410   6,688,084 
          
The tables below provide the following: (a) the components of income tax expense; (b) reconciliation between the statutory federal income tax rate and the effective income tax rate; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2009 and 2008.
Chesapeake 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) 12,000,000 shares are authorized at a par valueIncludes $985,000, $1,588,000 and $260,000 of $0.4867 per share.deferred state income taxes for the years 2009, 2008 and 2007, respectively.
 
(2) Includes shares purchased with reinvested dividends and optional cash payments.
(3)Includes shares issuedFederal income taxes were recorded at 35% for Directors’ compensation.
(4)Includes 62,221, 57,309, and 48,187 shares at December 31, 2008, 2007 and 2006, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.each year represented.
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 $19.7 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.
Page 86     Chesapeake Utilities Corporation 20082009 Form 10-K     Page 79

 

 

Notes to the Consolidated Financial Statements
I.J. Long-term Debt
The Company’sOur outstanding long-term debt is as shown below.
                
At December 31, 2008 2007 
 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:  
7.97% note, due February 1, 2008 $— $1,000,000 
6.91% note, due October 1, 2010 1,818,182 2,727,273  909 1,818 
6.85% note, due January 1, 2012 3,000,000 4,000,000  2,000 3,000 
7.83% note, due January 1, 2015 12,000,000 14,000,000  10,000 12,000 
6.64% note, due October 31, 2017 24,545,455 27,272,727  21,818 24,545 
5.50% note, due October 12, 2020 20,000,000 20,000,000  20,000 20,000 
5.93% note, due October 31, 2023 30,000,000 —  30,000 30,000 
Convertible debentures:  
8.25% due March 1, 2014 1,655,000 1,832,000  1,520 1,655 
Promissory note 60,000 80,000  40 60 
          
Total long-term debt 93,078,637 70,912,000  134,113 93,078 
Less: current maturities  (6,656,364)  (7,656,364)  (35,299)  (6,656)
          
Total long-term debt, net of current maturities $86,422,273 $63,255,636  $98,814 $86,422 
          
Annual maturities of consolidated long-term debt are as follows: $6,656,364$36,765 for 2009, $6,656,3642010; $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 $7,747,273of $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 2011, $6,727,273$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 2012, $6,727,273 for 2013, and $58,564,091 thereafter.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 20082009 and 2007,2008, debentures totaling $177,000$135,000 and $138,000,$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 20082009 and 2007,2008, no debentures were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.
On October 31, 2008, the Company issued $30 million of 5.93 percent Unsecured Senior Notes to two institutional investors (General American Life Insurance Company and New England Life Insurance Company). The terms of the Senior Notes require principal repayments of $1.5 million on the 30th day of April and 31st day of October in 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.
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. In connection with the merger, the uncollateralized senior notes were amended to include an additional covenant requiring the Company to 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, 2008, the Company is2009, 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.
In termsEach of restrictions which limit the payment of dividends by the Company, each of the Company’s Unsecured Senior NotesChesapeake’s uncollateralized senior notes contains a “Restricted Payments” covenant.covenant as defined in the note agreements. The most restrictive covenants of this type are included within the 7.83% Senior Notes,7.83 percent senior notes, due January 1, 2015. The covenant provides that the Companywe 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, 2008,2009, the Company’s cumulative consolidated net income base was $86.9$102.8 million, offset by Restricted Payments of $54.4$63.8 million, leaving $32.5$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 addition, the Company’s subsidiaries are not restricted from transferring fundsJanuary 2010, this series of first mortgage bonds were redeemed prior to the Companytheir maturities. The second most restrictive covenant of this type is included in the form of loans, advancesseries that is due in 2022, which provided that FPU cannot make dividend or cash dividends under the termsother restricted payments in excess of the covenantssum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. This covenant provides FPU with the Company’s various Unsecured Senior Notes.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 80     Chesapeake Utilities Corporation 2008 Form 10-K

J.K. Short-term Borrowing
At December 31, 2009 and 2008, and 2007, wethe Company had $33.0$30.0 million and $45.7$33.0 million, respectively, of short-term borrowing outstanding under our bank credit facilities. The annual weighted average interest rates on ourits short-term borrowing were 1.28 percent and 2.79 percent for 2009 and 5.46 percent for 2008, respectively. We incurred commitment fees of $79,000 and 2007,$16,000 in 2009 and 2008, respectively.
The Company also had a letterIn 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 outstanding with its primary insurance company in the amount of $775,000 as security to satisfy the deductibles under the Company’s various insurance policies. This letter of credit reduced the amounts available under the Company’s lines of credit and is scheduled to expirewas terminated on May 31,November 23, 2009. The Company does not anticipate that this letter of credit will be drawn upon by the counterparty, and the Company expects that it will be renewed as necessary.
Credit facilitiesPage 88     Chesapeake Utilities Corporation 2009 Form 10-K

As of December 22, 2008, the Board of Directors has authorized the Company to borrow up to $65.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit.
As of December 31, 2008, Chesapeake2009, we had fivefour unsecured bank lines of credit with threetwo financial institutions, totaling $100.0$90.0 million, none of which requires 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 temporarily portions of itsour capital expenditures. 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. We maintain both committed and uncommitted credit facilities. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks.
Committed credit facilities
As of December 31, 2008,2009 we had two committed revolving credit facilities totaling $55.0 million.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 0.751.25 percent per annum. At December 31, 2008,2009, there was $17.0$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 125 basis points,1.25 percent, if requested and advanced on the same day, or LIBOR for the applicable period plus 125 basis points1.25 percent if requested three days prior to the advance date. At December 31, 2008, the entire borrowing capacity of $25.02009, there was $18.3 million was 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 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. We areThe 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.
a funded indebtedness ratio of no greater than 65 percent; and
The Company is
a fixed charge coverage ratio of at least 1.20 to 1.0.
We are in compliance with all of itsour debt covenants.
Uncommitted credit facilities
As of December 31, 2008,2009, we had threetwo uncommitted lines of credit facilities totaling $45.0 million.$35.0 million, which were subsequently increased to $40.0 million in January 2010. Advances offered under the uncommitted lines of credit 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, 2008, the Company has reached the $20.0 million borrowing capacity under this credit facility.
The second facility is a $10.0 million uncommitted revolving line of credit that bears interest at either the Prime Rate or the daily LIBOR Rate for the applicable period. At December 31, 2008,2009, the entire borrowing capacity of $10.0$20.0 million was available under this credit facility.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 81

Notes to the Consolidated Financial Statements
The finalsecond facility is a $15.0 million uncommitted line of credit that bears interest at a rate per annum as offered by the bank’s base rate orbank for the respective LIBOR rate, plus 1.25 percent per annum.applicable period. At December 31, 2008,2009, there was $14.2$14.3 million available under this credit facility, which was reduced by $775,000$725,000 for a letter of credit issued to our primary insurance company. The letter of credit is provided as security to satisfy the deductibles under the Company’sour various insurance policies and expires on MayAugust 31, 2009. The Company does2010. We do not anticipate that this letter of credit will be drawn upon by the counter-party and it expectswe 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 total uncommitted revolving credit facilities of $40.0 million.
K.L. Lease Obligations
The Company hasWe have entered into several operating lease arrangements for office space, equipment and pipeline facilities. Rent expense related to these leases was $997,000, $880,000 and $736,000 for 2009, 2008 and $680,000 for 2008, 2007, and 2006, respectively. Future minimum payments under the Company’sour current lease agreements are $770,000, $612,000, $605,000, $560,000$866,000, $771,000, $677,000, $502,000 and $369,000$364,000 for the years 20092010 through 2013,2014, respectively; and $2.4$2.0 million thereafter, with an aggregate total of $5.4$5.2 million.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 89

L.M. Employee Benefit Plans
Retirement Plans
Before 1999, Company employees generally participated in bothWe sponsor a defined benefit pension plan (“DefinedChesapeake Pension Plan”) and a Retirement Savings Plan. Effective January 1, 1999, 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 decreased and was approaching the minimum number needed for the Defined Pension Plan to maintain its tax-qualified status. To avoid jeopardizing the tax-qualified status 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 would continue 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 would: (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) be 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 would not accrue any additional benefits under that plan. These changes were communicated to the Company’s employees during the first week of November 2004.
The Company also provides an unfunded pension supplemental executive retirement plan (“PensionChesapeake SERP”), formerly called the Executive Excess Retirement Plan. This plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the plan were based on each participant’s years of service and highest average compensation, prior to the freeze. In December 2008, the Pension SERP was amended to allow participants to elect a lump sum payment and to add the other optional forms of benefit payments currently available under the Defined Pension Plan.
In addition to the Defined Pension Plan and the Pension SERP, the Company provides an unfunded postretirement health care and life insurance plan that covers employees who have met certain age and service requirements. The measurement date for each(“Chesapeake Postretirement Plan”). As a result of the three plans was December 31, 2008merger with FPU, we now sponsor and 2007.
Page 82     Chesapeake Utilities Corporation 2008 Form 10-K

In September 2006, the FASB issued SFAS No. 158, which the Company adopted, prospectively, for the Defined Pension, Pension SERP and Other Postretirement Benefits on December 31, 2006. SFAS No. 158 requires that we recognize all obligations related tomaintain a separate defined benefit pensionspension plan for FPU (“FPU Pension Plan”) and a separate unfunded postretirement medical plan for FPU (“FPU Medical Plan”).
We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits and that we quantifyplans to determine the plans’ funded status as of the end of the year as an asset or a liability on our consolidated balance sheets.
SFAS No. 158 further 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 cost,costs, 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 or SFAS No. 106.
Atthe future pursuant to a previous order by the Florida PSC. The measurement dates were December 31, 2008, the funded status of the Company’s Defined Pension Plan was a liability of $4.9 million; at December 31, 2007, it was a liability of $275,000. In order to account for the decrease in the funded status in accordance with SFAS No. 158, the Company recorded a charge of $2.8 million, net of tax, to Comprehensive Income. In addition, the funded status of the postretirement health2009 and life insurance plan was a liability of $2.2 million at December 31, 2008 compared to $1.8 million at December 31, 2007. To adjust for the increased liability for the postretirement health and life insurance plan, as required by SFAS No. 158, the Company took a charge of $30,400, net of tax, to Comprehensive Income.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 20092010 are set forth in the following table.
                                    
 Defined Other  Chesapeake FPU Chesapeake FPU   
 Benefit Pension Postretirement  Pension Pension Chesapeake Postretirement Medical   
 Pension SERP Benefit 
(in thousands) Plan Plan SERP Plan Plan Total 
Prior service cost (credit) $(4,699) $13,176 —  $(5) $— $19 $— $— $14 
Net loss $268,276 $59,089 $158,378 
Net (gain) loss $(137) $— $47 $71 $— $(19)
The following table presents the amounts not yet reflected in net periodic benefit cost and included in AOCIaccumulated other comprehensive income/loss as of December 31, 2008.2009.
                                    
 Defined Other  Chesapeake FPU Chesapeake FPU   
 Benefit Pension Postretirement  Pension Pension Chesapeake Postretirement Medical   
 Pension SERP Benefit 
(in thousands) Plan Plan SERP Plan Plan Total 
Prior service cost (credit) $(20,162) $118,580 —  $(15) $— $102 $— $— $87 
Net loss (gain) 4,319,514  (175,725) 1,049,291  2,672  (540) 673 1,351  (14) 4,142 
                    
Subtotal 4,299,352  (57,145) 1,049,291  2,657  (540) 775 1,351  (14) 4,229 
Tax expense (benefit)  (1,721,460) 20,041  (420,136)  (1,065) 208  (311)  (542) 5  (1,705)
                    
AOCI $2,577,892 $(37,104) $629,155 
Accumulated other comprehensive (income) loss $1,592 $(332) $464 $809 $(9) $2,524 
                    
Defined Benefit Pension PlanPlans
As previously described,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 wasWe were not required to make any funding payments to the DefinedChesapeake Pension Plan in 2008.2009 or to the FPU Pension Plan subsequent to the merger closing in October 2009.
Page 90     Chesapeake Utilities Corporation 20082009 Form 10-K     Page 83

 

 

Notes to the Consolidated Financial Statements
The following schedule summarizes the assets of the DefinedChesapeake Pension Plan, by investment type, at December 31, 2009, 2008 and 2007 and 2006:the assets of the FPU Pension Plan, by investment type, at December 31, 2009:
                
 Chesapeake FPU 
             Pension Plan Pension Plan 
At December 31, 2008 2007 2006  2009 2008 2007 2009 
Asset Category
  
Equity securities  48.70%  49.03%  77.34%  66.22%  48.70%  49.03%  63.00%
Debt securities  51.24%  50.26%  18.59%  33.76%  51.24%  50.26%  29.00%
Other  0.06%  0.71%  4.07%  0.02%  0.06%  0.71%  8.00%
                
Total  100.00%  100.00%  100.00%  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
•Repurchase agreements that are fully collateralized by such obligations.
United States government obligations; and
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 3060 percent and debt at 7040 percent, but allowing for a variance of 20 percent in either direction. 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; short selling and margin transactions are prohibited as well. Investment allocation decisions are made by the Employee Benefits committee. During 2007,2004, 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, 2009 and 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%
(1)FPU Pension Plan’s beginning balance reflects the benefit obligations as of the merger date of October 28, 2009.
Net periodic pension cost (benefit) for the plans for 2009, 2008, and 2007:2007 include the components shown below:
         
At December 31, 2008  2007 
Change in benefit obligation:
        
Benefit obligation — beginning of year $11,073,520  $11,449,725 
Interest cost  593,723   622,057 
Change in assumptions  267,953   — 
Actuarial loss  83,704   282,684 
Benefits paid  (426,652)  (1,280,946)
       
Benefit obligation — end of year  11,592,248   11,073,520 
       
         
Change in plan assets:
        
Fair value of plan assets — beginning of year  10,798,781   12,040,287 
Actual return on plan assets  (3,683,183)  39,440 
Benefits paid  (426,652)  (1,280,946)
       
Fair value of plan assets — end of year  6,688,946   10,798,781 
       
         
Reconciliation:
        
Funded status  (4,903,302)  (274,739)
       
Accrued pension cost
 $(4,903,302) $(274,739)
       
         
Assumptions:
        
Discount rate  5.25%  5.50%
Expected return on plan assets  6.00%  6.00%
                 
  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

Pension Supplemental Executive Retirement Plan
The Company reviewedChesapeake SERP was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the Chesapeake SERP were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. The accumulated benefit obligation for the Chesapeake SERP, which is unfunded, was $2.5 million at both December 31, 2009 and 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 Chesapeake SERP for 2009, 2008, and 2007 include the components 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%
Chesapeake Utilities Corporation 2009 Form 10-K     Page 93

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 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

Assumptions
The assumptions used for the discount rate to calculate the benefit obligation of all the plan and has elected a rate of 5.25 percent in 2008, reflecting a reduction of 25 basis points inplans were based on the interest rates of high-quality bonds in 2008, and2009, reflecting the expected life of the plan, in light of the lump-sum-payment option.plans. In addition,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 DefinedChesapeake’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, remained constant at six percent due todifferent discount rate and expected return on plan asset assumptions were selected for Chesapeake’s plans and FPU’s plans. Since all of 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 ispension plans are frozen with respect to additional years of service and compensation, the rate of assumed compensation rate increases is not applicable. The accumulated benefit obligation was $11.6 million and $11.1 million at December 31, 2008 and 2007, respectively.
Page 84     Chesapeake Utilities Corporation 2008 Form 10-K

Net periodic pension benefit for the Defined Pension Plan for 2008, 2007, and 2006 include the components shown below:
             
For the Years Ended December 31, 2008  2007  2006 
Components of net periodic pension cost:
            
Interest cost $593,723  $622,057  $635,877 
Expected return on assets  (629,432)  (696,398)  (690,533)
Amortization of prior service cost  (4,699)  (4,699)  (4,699)
          
Net periodic pension benefit
 $(40,408) $(79,040) $(59,355)
          
             
Assumptions:
            
Discount rate  5.50%  5.50%  5.25%
Expected return on plan assets  6.00%  6.00%  6.00%
Pension Supplemental Executive Retirement Plan
As previously described, this plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the plan were based on each participant’s years of service and highest average compensation, prior to the freeze. The accumulated benefit obligation for the Pension SERP, which is unfunded, was $2.5 million and $2.3 million at December 31, 2008 and 2007, respectively.
The following schedule sets forth the status of the Pension SERP:
         
At December 31, 2008  2007 
Change in benefit obligation:
        
Benefit obligation — beginning of year $2,326,250  $2,286,970 
Interest cost  124,771   123,361 
Actuarial (gain) loss  39,227   5,123 
Amendments  118,580   — 
Benefits paid  (89,204)  (89,204)
       
Benefit obligation — end of year  2,519,624   2,326,250 
       
         
Change in plan assets:
        
Fair value of plan assets — beginning of year  —   — 
Employer contributions  89,204   89,204 
Benefits paid  (89,204)  (89,204)
       
Fair value of plan assets — end of year  —   — 
       
         
Reconciliation:
        
Funded status  (2,519,624)  (2,326,250)
       
Accrued pension costs
 $(2,519,624) $(2,326,250)
       
         
Assumptions:
        
Discount rate  5.25%  5.50%
The Company reviewed the assumptions used for the discount rate of the plan to calculate the benefit obligation and has elected a rate of 5.25 percent, reflecting a reduction of 25 basis points in the interest rates of high-quality bonds in 2008 and a reduction in the expected life of the plan. Since the Plan is frozen in regard to additional years of service and compensation, the rate of assumed pay-rate increases is not applicable. The measurement dates for the Pension SERP were December 31, 2008 and 2007.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 85

Notes to the Consolidated Financial Statements
Net periodic pension costs for the Pension SERP for 2008, 2007, and 2006 include the components shown below:
             
For the Years Ended December 31, 2008  2007  2006 
Components of net periodic pension cost:
            
Interest cost $124,771  $123,361  $119,588 
Amortization of actuarial loss  45,416   51,734   57,039 
          
Net periodic pension cost
 $170,187  $175,095  $176,627 
          
Assumptions:
            
Discount rate  5.50%  5.50%  5.25%
Other Postretirement Benefits
The Company sponsors an unfunded postretirement health care and life insurance plan that covers substantially all employees. The following schedule sets forth the status of the postretirement health care and life insurance plan:
         
At December 31, 2008  2007 
Change in benefit obligation:
        
Benefit obligation — beginning of year $1,755,564  $1,763,108 
Retirees  551,684   56,123 
Fully-eligible active employees  (19,329)  21,012 
Other active  (109,852)  (84,679)
       
Benefit obligation — end of year $2,178,067  $1,755,564 
       
         
Change in plan assets:
        
Fair value of plan assets — beginnning of year  —   — 
Employer contributions  39,598   243,660 
Plan participant’s contributions  103,572   100,863 
Benefits paid  (143,170)  (344,523)
       
Fair value of plan assets — end of year  —   — 
       
         
Reconciliation:
        
Funded status $(2,178,067) $(1,755,564)
       
Accrued OPRB costs
 $(2,178,067) $(1,755,564)
       
         
Assumptions:
        
Discount rate  5.25%  5.50%
Net periodic postretirement costs for 2008, 2007, and 2006 include the following components:
             
For the Years Ended December 31, 2008  2007  2006 
Components of net periodic postretirement cost:
            
Service cost $2,826  $6,203  $9,194 
Interest cost  114,282   101,776   93,924 
Amortization of:            
Transition obligation  —   —   22,282 
Actuarial loss  289,838   166,423   144,694 
          
Net periodic postretirement cost
 $406,946  $274,402  $270,094 
          
The health care inflation rate for 20082009 used to calculate the benefit obligation is assumed to be five7.50 percent for medical and six8.50 percent for prescription drugs.drugs for the Chesapeake Postretirement Plan; and 10.50 percent for the FPU Medical Plan. A one-percentage-pointone-percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $347,300$708,000 as of January 1, 2009,2010, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2009 by approximately $20,000.$30,000. A one-percentage-pointone-percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $282,500$594,000 as of January 1, 2009,2010, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2009 by approximately $16,000. The measurement dates were December 31, 2008 and 2007.$24,000.
Page 86     Chesapeake Utilities Corporation 2008 Form 10-K

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 2009 through 2013 and the aggregate of the next five years for each of theour plans previously described.described:
                                
 Defined Pension Other Post-  Chesapeake FPU Chesapeake FPU 
 Benefit Supplemental Retirement  Pension Pension Chesapeake Postretirement Medical 
 Pension Plan(1) Executive Retirement(2) Benefits(2) 
2009 $1,116,199 $87,810 $224,683 
(in thousands) Plan(1) Plan(1) SERP(2) Plan(2) Plan(2)(3) 
2010 936,064 805,978 237,850  $763 $2,176 $88 $115 $144 
2011 441,760 84,623 215,670  429 2,308 797 113 158 
2012 1,351,260 82,833 226,548  1,228 2,452 84 123 181 
2013 491,266 80,911 220,874  484 2,617 82 127 176 
Years 2014 through 2018 3,643,521 585,796 1,201,769 
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.
InChesapeake Utilities Corporation 2009 the Company expects to contribute $450,000 to the Defined Pension Plan and $87,810 to the Pension SERP and $224,683 to the Other Postretirement Benefit Plan for these two plans are unfunded.Form 10-K     Page 95

Retirement Savings Plan
The Company sponsors aWe sponsor two 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 80 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.savings plans and one non-qualified supplemental employee retirement savings plan.
Effective January 1, 1999, the Company began offering an enhancedChesapeake’s 401(k) Planplan is offered to all neweligible employees, as well as existingexcept for those FPU employees, who electedhave the opportunity to no longer participate in the Defined Pension Plan. The Company makesFPU’s 401(k) plan. We make matching contributions on up to six percent of each Chesapeake employee’s eligible pre-tax compensation for the year, except for the employees of 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 the employee’s age and years of service. The first 100 percent is matched with Chesapeake common stock; the remaining match is invested in the Company’sChesapeake’s 401(k) Plan according to each employee’s election options. Employees are automatically enrolled at a two percent contribution, with the 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 Company’sour contribution made on behalf of the Advanced Information Services segmentadvanced 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.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 87

Notes to the Consolidated Financial Statements
Effective January 1, 1999, the Companywe began offering a non-qualified supplemental employee retirement savings plan (“401(k) SERP”) open to Companyour executives over a specific income threshold. Participants receive a cash-only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the mutual funds available for investment. These same funds are available for investment of employee contributions within the Retirement Savings Plan.Chesapeake’s 401(k) plan. All obligations arising under the 401(k) SERP are payable from theour general assets, of Chesapeake, although Chesapeake haswe have established a Rabbi Trust for the 401(k) SERP. As discussed further in Note FG — “Investments,” to the Consolidated Financial Statements, the assets held in the Rabbi Trust hadincluded a fair value of $1.6$1.9 million and $1.9$1.4 million at December 31, 2009 and 2008, and 2007, respectively.respectively, related to the 401(k) SERP. The assets of the Rabbi Trust are at all times subject to the claims of Chesapeake’sour general creditors.
The Company’sWe 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.
Our contributions to the 401(k) plans totaled $1.55$1.6 million $1.48(including a $10,000 contribution made to FPU’s 401(k) plan after the merger), $1.6 million, and $1.61$1.5 million for the years ended December 31, 2009, 2008, 2007, and 2006,2007, respectively. As of December 31, 2008,2009, there are 42,65610,281 shares reserved to fund future contributions to the Retirement Savings Plan.Chesapeake’s 401(k) plan.
Deferred Compensation Plan
On December 7, 2006, the Board 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 partall or alla part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainer and fees. At December 31, 2008,2009, the Deferred Compensation Plan consistsconsisted 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 the Company’sour common stock, except that cash shallis be paid in lieu of fractional shares.
The CompanyWe established a Rabbi Trust in connection with the Deferred Compensation Plan. The value of the Company’sour 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 $1.5 million$739,000 and $1.4$1.5 million at December 31, 20082009 and 2007,2008, respectively.
M.N. Share-Based Compensation Plans
The Company accounts for itsOur non-employee directors and key employees are awarded share-based compensation arrangements under SFAS No. 123R, which requires companies toawards through the Company’s Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), respectively. We record these share-based awards as compensation costs for all share-based awards over the respective service period for employeewhich services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. The Company currently has two share-based compensation plans, the Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), that require accounting under SFAS 123R.
The table 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.PIP for the years ended December 31, 2009, 2008 and 2007.
                        
For the year ended December 31, 2008 2007 2006 
For the Years Ended December 31, 2009 2008 2007 
(in thousands) 
Directors Stock Compensation Plan $180,037 $180,920 $165,340  $191 $180 $181 
Performance Incentive Plan 640,138 809,030 544,450  1,115 640 809 
              
Total compensation expense 820,175 989,950 709,790  1,306 820 990 
Less: tax benefit 326,585 386,080 276,820  523 327 386 
              
Amounts included in net income $493,590 $603,870 $432,970 
Share-Based Compensation amounts included in net income $783 $493 $604 
              
Page 88     Chesapeake Utilities Corporation 2008 Form 10-K

Stock Options
The CompanyWe did not have any stock options outstanding at December 31, 2009, 2008 or December 31, 2007, nor were any stock options issued during 2009, 2008 and 2007.
Directors Stock Compensation Plan
Under the DSCP, each of our non-employee director of the Companydirectors received in 20082009 an annual retainer of 650 shares of common stock and additional shares of common stock to servefor serving as a committee chairperson. For 2008,2009, 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 advance of the directors’ service period; therefore, these shares are fully vested as of the date of the grant. The Company recordsgrant date. We record a prepaid expense as of the date of the grant equal to the fair value of the shares issued and amortizesamortize the expense equally over a service period of one year.
Chesapeake Utilities Corporation 2009 Form 10-K     Page 97

A summary of stock activity under the DSCP is presented below:
                
 Weighted    Weighted Average 
 Number of Average Grant  Number of Grant Date 
 Shares Date Fair Value  Shares Fair Value 
Outstanding — December 31, 2006 — — 
Outstanding — December 31, 2007 — — 
          
Granted 5,850 $31.38  6,161 $29.43 
Vested 5,850 $31.38  6,161 $29.43 
Forfeited — —  — — 
          
Outstanding — December 31, 2007 — — 
Outstanding — December 31, 2008 — — 
          
Granted(a)(1)
 6,161 $29.43  7,174 $29.83 
Vested 6,161 $29.43  7,174 $29.83 
Forfeited — —  — — 
          
Outstanding — December 31, 2008 — — 
Outstanding — December 31, 2009 — — 
          
   
(a)(1) On September 15, 2008,October 28, 2009, the Company added atwo new membermembers to its Board of Directors. The numberDirectors; each new board member was awarded 337 shares of shares issued to this Director for her annual retainer was prorated.common stock.
CompensationWe recorded compensation expense of $191,000, $180,000 and $181,000 related to DSCP awards recorded by the Company for the years ended December 31, 2009, 2008 and 2007, and 2006 is presented in the following table:
             
For the year ended December 31, 2008  2007  2006 
 
Compensation expense for DSCP $180,037  $180,920  $165,340 
respectively.
The weighted-average grant-date fair value of DSCP awards granted during fiscal2009 and 2008 was $29.83 and 2007 was $29.43, and $31.38, respectively, per share.share, respectively. The intrinsic values of the DSCP awards are equal to the fair market value of these awards on the date of grant. At December 31, 2008,2009, there was $62,470$64,000 of unrecognized compensation expense related to DSCP awards that is expected to be recognized over the first four months of 2009.2010.
As of December 31, 2008,2009, there were 51,28944,115 shares reserved for issuance under the terms of the Company’s DSCP.
Performance Incentive Plan (“PIP”)
The Company’sOur Compensation Committee of the Board of Directors is authorized to grant key employees of the Company the right to receive awards of shares of the Company’sour common stock, contingent upon the achievement of established performance goals. These awards granted under the PIP are subject to certain post-vesting transfer restrictions.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 89

Notes to the Consolidated Financial Statements
In 2006 and 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 were achieved by the Company at the end of a one-year performance period. ForIn 2008, the Companywe adopted multi-year performance plans to be used in lieu of the one-year awards. Similar to the one-year plans, the multi-year plans will provide incentives based upon the achievement of long-term goals, development and the success of the Company. The long-term goals have both market-based and performance-based conditions or targets.
The shares granted under the PIP in 2006 and 2007 are fully vested, and the fair value of each share is equal to the market price of the Company’sour common stock on the date of the grant. The shares granted under the 2008 and 2009 long-term plans are unvested athave not vested as of December 31, 2008,2009, and the fair value of each performance-based condition or target is equal to the market price of the Company’sour 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:
                
 Weighted  Number of Weighted Average 
 Number of Average Fair 
 Shares Value 
Outstanding — December 31, 2006 31,140 $31.00 
     
Granted 33,760 $29.90 
Vested 12,544 $31.00 
Fortfeited 6,820 $31.00 
Expired 11,776 $31.00 
      Shares Fair Value 
Outstanding — December 31, 2007 33,760 $29.90  33,760 $29.90 
          
Granted 94,200 $27.71  94,200 $27.84 
Vested 31,094 $29.90  31,094 $29.90 
Fortfeited — —  — — 
Expired 2,666 $29.90  2,666 $29.90 
          
Outstanding — December 31, 2008 94,200 $27.71  94,200 $27.84 
          
Granted 28,875 $29.19 
Vested — — 
Fortfeited — — 
Expired — — 
     
Outstanding — December 31, 2009 123,075 $28.15 
     
ForIn 2009, no shares under the yearsPIP vested. In 2008, and 2007, the Companywe 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, as determined by the average of the high and low of the Company’sour stock price. The total number ofNo payments for the employee’s tax obligations were made to taxing authorities in 2009 as no shares withheld (2,420) for 2007 was based on the value of the PIP shares on their vesting date as determined by the closing price of the Company’s stock.vested during this period. Total payments for the employees’ tax obligations to the taxing authorities were approximately $382,650$383,000 in 2008.
We recorded compensation expense of $1.1 million, $640,000 and $69,200 in$809,000 related to the PIP for the years ended December 31, 2009, 2008, and 2007, respectively.
Compensation expense related to the PIP recorded by the Company during 2008, 2007, and 2006 is presented in the following table:
             
For the year ended December 31, 2008  2007  2006 
 
Compensation expense for PIP $640,138  $809,030  $544,450 
The weighted-average grant-date fair value of PIP awards granted during fiscal2009, 2008 and 2007 was $29.19, $27.84 and 2006 was $27.71, $29.90, and $31.00, respectively, per share.share respectively. The intrinsic value of the PIP awards was $1,080,161$2.1 million and $1.1 million for 2008.2009 and 2008, respectively. The intrinsic valuesvalue of the 2007 and 2006 PIP awards arewas equal to the fair market value of these awards on the date of grant.
As of December 31, 2008,2009, there were 371,293 shares reserved for issuance under the terms of the Company’sour PIP.
Page 90     Chesapeake Utilities Corporation 2008 Form 10-K

N.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.
Chesapeake hasWe have participated in the investigation, assessment or remediation and has accrued liabilities,have certain exposures at threesix former manufactured gas plantMGP sites. Those sites are located in Delaware,Salisbury, Maryland, and Florida, referred to, respectively, as the Dover Gas Light Site, the Salisbury Town Gas Light Site and the Winter Haven, Coal Gas Site. The Company hasKey West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of Environmental (“MDE”)MDE regarding a fourthseventh former manufactured gas plantMGP site located in Cambridge, Maryland. The Key West, Pensacola, Sanford and West Palm Beach sites are related to FPU, for which we assumed in the merger any existing and future contingencies.

Chesapeake Utilities 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 recovery of environmental costs from Chesapeake’s customers through its 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 from the West Palm Beach site, which represents our estimate of the future 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 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 following discussion provides details on each site.
Dover Gas Light SiteSalisbury, Maryland
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 EPA regarding this site. This concluded Chesapeake’s remedial action obligation related to this site and relieves Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered there, or information previously unknown to the EPA is received which indicates that the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the EPA in all liability settlements.
The Company has reviewed its remediation costs incurred to date for the Dover Gas Light site and has concluded that all costs incurredWe have been paid and recovered through rates or other parties. The Company does not expect any future environmental expenditure for this site. On February 5, 2008, the Delaware PSC granted final approval to cease the recovery of environmental costs through the Company’s Environmental Rider recovery mechanism, effective November 30, 2008. Any residual balance shall be included in the Company’s Gas Sales Service Rate application.
Salisbury Town Gas Light Site
In cooperation with the MDE, the Company has 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 of an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake hasWe 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 the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well which is being maintained for continued product monitoring and recovery. Chesapeake hasWe have requested and isare awaiting a No Further Action determination from the MDE.
Through December 31, 2008, 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 $2.03$2.1 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland PSC to recover, through its rates charged to customers, $1.16 million of environmental remediation costs incurred as of that date. As of December 31, 2008, a regulatory asset of approximately $899,000 has been recorded to represent the portionand have $783,000 of the 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 filedPursuant to a Consent Order entered into with the FDEP, an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a 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 insite. We are currently completing additional soil and groundwater sampling at this location for the fourth quarterpurpose of 2002, and the system remains fully operational.
Chesapeake Utilities Corporation 2008 Form 10-K     Page 91

Notes to the Consolidated Financial Statements
Through December 31, 2008, the Company has incurred approximately $1.8 million of environmental costs associated withdesigning a remedy for this site. At December 31, 2008, the Company had recorded a liability associated with this site of $511,000, which partially offsetting (a) approximately $268,000 collected through rates in excess of costs incurred and (b) a regulatory asset of $779,000, representing the uncollected portion of the estimated clean-up costs relatedsite. Following the completion of this field work, we will submit a soil excavation plan to this site.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 Coal Gas 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 intendsintend to oppose any requirement 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 manufactured gas 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.
O.P. Other Commitments and Contingencies
Rates and Other Regulatory Activities
The Company’sOur natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs;PSC; ESNG, the Company’sour natural gas transmission operation, is subject to regulation by the FERC.
Delaware. On July 6, 2007, the Company filed with the Delaware PSC an application seeking approval of the following: (i) participation Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Company’s Delaware commercial and industrial customers in gas supply buying pools served by third-party natural gas marketers; (ii) an annual base rate adjustment of $1,896,000 that represented approximately a 3.25 percent rate increase on average for the division’s firm customers; (iii) an alternative rate design for residential customers in a defined expansion area in eastern Sussex County, Delaware; and (iv) a revenue normalization mechanism that would have mitigated the price and revenue impacts of seasonal natural gas consumption patterns on both customers and the Company. As part of that filing, the Company also proposed that the Delaware division be permitted to earn a return on equity of up to fifteen percent (15%)Florida PSC as an incentive to make significant capital investments to serve the growing areas of eastern Sussex County, in support of Delaware’s Energy Policy, and to ensure that the Company’s investors are adequately compensated for the increased risk associated with the higher levels of capital investment necessary to provide natural gas in those areas. On August 21, 2007, the Delaware PSC authorized the Company to implement charges reflecting the proposed $1,896,000 increase, effective September 4, 2007, on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The PSC Staff filed testimony recommending a rate decrease of $693,245. The Delaware Public Advocate recommended a rate decrease of $588,670. Neither party recommended approval of the Delaware division’s other proposals mentioned above. The Delaware division disagreed with these positions in its rebuttal, which was filed on February 7, 2008. At an evidentiary hearing on July 9, 2008, the parties presented a joint proposed settlement agreement to resolve all issues in this docket, and the Delaware PSC approved this settlement agreement on September 2, 2008. The major components of the settlement include the following: (i) a rate increase for the division of $325,000, including miscellaneous fees; (ii) an overall rate of return of 8.91% and a return on equity of 10.25%; (iii) a change in depreciation rates that will reduce depreciation expense by approximately $897,000; (iv) the division will retain one hundred percent (100%) of margins on interruptible service over 10,000 Mcf per year; interruptible customers will receive transportation service only; (v) the division will continue to share with firm service customers, through its Gas Sales Service Rates (“GSR”) mechanism, eighty percent (80%) of any margins received from its Asset Manager and any off-system sales; and (vi) the residential service rate schedule will be divided into two separate schedules based on annual volumetric levels.entities.

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Delaware.On September 10, 2007, the Company2, 2008, our Delaware division filed with the Delaware PSCPublic Service Commission (“Delaware PSC”) its annual GSRGas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, rates, effective November 1, 2007.2008. On October 2, 2007,September 16, 2008, the Delaware PSC authorized the CompanyDelaware 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 CompanyDelaware division was required by its natural gas tariff to file a revised application if its projected under-collectionover-collection of gas costs for the determination period of November 2007 through October 2008 exceeded sixfour and one-half percent (6%)(4.5 percent) of total firm gas costs. As a result of continued increasesa significant decrease in the cost of natural gas, the CompanyDelaware division, on January 8, 2009, filed with the Delaware PSC on July 1, 2008, a supplemental GSR Application, seeking approval to change its GSR, rates, effective AugustFebruary 1, 2008.2009. On July 8, 2008,January 29, 2009, the Delaware PSC authorized the CompanyDelaware division to implement the supplementalrevised GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted final approval of both ofOn July 7, 2009, the Delaware Division’s GSR rate filings on October 7, 2008.
On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application, to become effective December 1, 2007. The Delaware PSC granted approval of a settlement agreement presented by the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision. On February 5, 2008,parties in this docket, the Delaware PSC, granted final approvalour Delaware division and the Division of the ER rates, as filed. Since allPublic 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 division’s environmental expenses subjectsettlement, the parties also agreed to recovery pursuant todevelop a record in a later proceeding on the ER recovery mechanism will have been collectedprice charged by the end of the determination period, no additional ER rate applications will be filed, and ER charges ceased to appear on customers’ bills as of November 30, 2008.
On September 1, 2008, the Delaware division filed withfor 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 its annual GSR Application, seeking approval to change its GSR rates, effective November 1, 2008. On September 16, 2008,require the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis, subjectdivision to refund pendingto its firm service customers the completiondifference 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 full evidentiary hearings and a final decision. The Company anticipates a final decisionany interest, the amount that would have to be refunded if the Hearing Examiner’s recommendation is approved without modification by the Delaware PSC duringis approximately $700,000 as of December 31, 2009. The Hearing Examiner has also recommended that the first half of 2009.
On September 29, 2008,Delaware PSC require us to adhere to asymmetrical pricing principles regarding all future capacity releases by the Delaware division filed an application withto PESCO, if any. Accordingly, if the Hearing Examiner’s recommendation is approved without modification by the Delaware PSC requesting approvaland 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 issuance of $10,000,000 of debt securities.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 granted approval ofon February 18, 2010, but no ruling was made by the issuance at its regularly scheduled meetingDelaware 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 October 23, 2008.a previous settlement approved by the Delaware PSC and therefore, we have not recorded a liability for this contingency.
On December 2, 2008, theour 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 will allow the division to charge allrecover from natural gas customers located within the respective town and city limitsTown of Milford or the City of Seaford a proportionate share of the franchise feefees paid by the division to the Town of Milton and City of Seaford as a condition to providing natural gas service.division. The Delaware PSC granted approval of both Franchise Fee Riders on January 29, 2009.
Maryland. On September 26, 2006,4, 2009, our Delaware division filed with the MarylandDelaware 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 a base rate increase forby the MarylandDelaware PSC. The Delaware division based on an annual cost of service increase of approximately $780,000. As part of a settlement agreement in that proceeding, however, the division was required to file a depreciation study, and it did so on April 9, 2007. The division then filed formal testimony on July 10, 2007, initiating a Phase II of this proceeding and proposing a rate decrease of approximately $80,000 annually, based on lower depreciation expense. On November 29, 2007, the PSC approved a settlement agreement for a rate decrease of $132,155 based on the Company’s revised approved depreciation rates, effective December 1, 2007. Under the settlement, the division reduced its depreciation expense by approximately $119,000 and its asset removal costs by approximately $167,000. The difference between the decrease in depreciation expense and the decreasepotential 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 delivery service rates is due to an increase in rate case expense amortization and an increase in rates to offset the lossfirst quarter of margin from a large customer in Maryland.2010.

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Notes to the Consolidated Financial Statements
Maryland.On December 17, 2007,16, 2008, the Maryland PSCPublic Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings submitted by our Maryland division during the twelve months ended September 30, 2007. No issues were raised at the hearing, and on February 7, 2008, the Maryland PSC approved, without exception, the division’s four quarterly gas cost recovery filings.
On December 16, 2008, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve12 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 gas cost recovery filings, which became a final Order of the Maryland PSC on January 21, 2009.
Florida. In complianceOn 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 state law,this Order.
On December 1, 2009, the FloridaMaryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Company’s Maryland division filed its 2007 Depreciation Study (“Study”) withduring the Florida12 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 on May 17, 2007. This Study, which supersededissued an Order affirming the last study performedHearing Examiner’s decisions in 2002, provided the PSCmatter, but made certain clarifications and corrections to the opportunity to review and address changes in plant and equipment lives, salvage values, reserves and resulting life depreciation rates. The division responded to interrogatories regardingtext of the Study on October 15, 2007, December 24, 2007, and February 7, 2008. Based on the recommendationproposed Order issued by the PSC Staff, the Commission, at its May 20, 2008 agenda conference, approved certain revisions to the division’s utility plant remaining lives, net salvage values, depreciation reserves, and depreciation rates, effective January 1, 2008. TheHearing Examiner.
Florida. On July 14, 2009, Chesapeake’s Florida PSC issued an order on June 27, 2008, which closed this docket.
On August 15, 2008, the Companydivision filed with the Florida PSC its petition for a petition seekingrate 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 waiverrate 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 aspectssurcharge mechanisms; (d) restructuring of meter-reading rules that could preventcertain rate classifications; and (e) deferral of certain costs and the Company and its customers from realizing fullypurchase premium associated with the accuracy and efficiency benefits of automatic meter-reading equipment, which enables the Company to take daily meter readings remotely for every customer. Existing Commission rules, established well before automatic meter-reading technology existed, can be read to require a monthly visit to each customer to take a reading from a meter located on the customer’s premises. The Commission, at its October 14, 2008 Agenda Conference, approved the Company’s petition,pending merger with a minor modification requiring the Company to read all meters physically once each year. The Florida PSC issued an order on November 3, 2008 confirming its approval and a consummating order on December 2, 2008, which closed this docket.
FPU. On August 18, 2008,2009, the Company filed with the Florida PSC a petition seeking recovery of costs incurred to implement Phase 2 of its experimental Transitional Transportation Service program. The Company incurred certain incremental, non-recurring costs from May 2007 through June 2008 ($77,980) and is projecting that it will incur additional non-recurring expenses through May 2009 ($100,000) for a total of approximately $177,980. The Company is seeking recovery of these expenses, plus applicable Regulatory Assessment Fees and interest, through a fixed monthly surcharge from the two approved Transitional Transportation Service Shippers on the Company’s system. The Florida PSC approved the Company’s petition at its Octoberfull 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, 2008 Agenda Conference.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 issuedhad 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 November 3, 2008, and a consummating order on November 26, 2008, which closed this docket.
ESNG. ESNG had the following regulatory activityMay 5, 2009, with the FERC regardingnew rates to be effective beginning on June 4, 2009. On June 17, 2009, however, the expansionOffice 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 — 20082008.. On November 15, 2007, ESNG requested FERC authorization to commence construction of facilities (approximately nine miles) included In accordance with the requirements in the third phase ofFERC’s Order Issuing Certificate for the 2006-082006 — 2008 System Expansion. The FERC granted this authorization on January 7, 2008. Construction began in January 2008, and the facilities were completed and have been placed in service. The 2008 facilities provide 5,650 Dts of additional firm service capacity per day and an annualized gross margin contribution of approximately $988,000.Expansion, ESNG hashad until June 13, 2009, to construct the remaining facilities that were includedauthorized in the 2006-08 System Expansion filing withproject filing. On February 3, 2009, ESNG requested authorization to modify the FERC, that willpreviously required completion date and to commence construction of the facilities, which provide for the remaining 7,200 Dts6,957 Mcfs of additional firm service capacity previously approved by the FERC. On March 13, 2009, the FERC andgranted 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 earnrealize an additional annualized gross margin of approximately $1.$1.0 million.
Page 94     Chesapeake Utilities Corporation 2008 Form 10-K

Energylink Expansion Project (“E3 Project.Project”).In 2006, ESNG proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas from the existing Cove Point Liquefied Natural Gas terminal located 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.
On May 31, 2006,In April 2009, ESNG entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Co. and Chesapeake, through its Delaware and Maryland divisions, to provide additional firm transportation services upon completion of the E3 Project. Both Chesapeake and Delmarva Power & Light Co. are parties to existing firm natural gas transportation service agreements with ESNG, and each desired additional firm transportation service underterminated the E3 Project as evidenced by the Precedent Agreements. Pursuantand initiated billing to the Precedent Agreements, the parties agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations necessary for ESNG to provide, and for Chesapeake and Delmarva Power & Light Co. to utilize, additional firm transportation service under the E3 Project.
As part of the Precedent Agreements, ESNG, Chesapeake and Delmarva Power & Light Co. also entered into Letter Agreements, which provide that, if the E3 Project is not certificated and placed in service, Chesapeake and Delmarva Power & Light Co. will each pay its proportionate share of certain pre-certificationrecover specified project costs by means of a negotiated surcharge over a period of not less than 20 years.
In furtherance of the E3 Project, ESNG submitted a petition to the FERC on June 27, 2006, seeking approval of the pre-construction cost agreements as part of a rate-related Settlement Agreement (the “Settlement Agreement”), which would provide benefits to ESNG and its customers, including but not limited to: (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 E3 Project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC approved the Settlement Agreement. On September 6, 2006, ESNG submitted to the FERC proposed tariff sheets to implement the provisions of the Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets, effective September 7, 2006.
On April 23, 2007, ESNG submitted to the FERC its request to commence a pre-filing process, and on May 15, 2007, the FERC notified ESNG that its request had been approved. The pre-filing process was intended to engage all interested and affected stakeholders early in the process with the intention of resolving all environmental issues prior to the formal certificate application being filed. As part of this process, ESNG performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. ESNG also held meetings with federal, state and local permitting/regulatory agencies, non-governmental organizations, landowners, and other interested stakeholders.
As part of an updated engineering study, ESNG received additional construction cost estimates for the E3 Project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the overall project development plan, ESNG explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. ESNG also held discussions and meetings with several potential new customers, who expressed interest in the E3 Project, but elected not to participate.
On December 20, 2007, ESNG withdrew from the pre-filing process as a result of insufficient customer commitments for capacity to make the project economical. ESNG will continue to explore potential construction methods, construction cost mitigation strategies, additional market requests, and potential design changes in its efforts to improve the overall economics of the E3 project.
If ESNG decides to abandon the E3 Project, it will initiate billing of a pre-certification costs surcharge in accordance with the terms of the above described Precedent Agreements and Letter Agreementsprecedent agreements executed with the two participating customers, one of which is Chesapeake, through its customers, which provide for these customers toDelaware and Maryland divisions. These billings will reimburse ESNG for pre-certificationthe $3.17 million of costs incurred in connection with the E3 Project, up to a maximum amountincluding the cost of $2.0 million each, with interest,capital, over a period of 20 years. As of December 31, 2008, ESNG had incurred $3.17 million of pre-certification costs relating to the E3 Project.

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NotesPrior 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 Consolidated Financial Statements60-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 rate and certificate matters:
Natural Gas Act Section 4 General Rate Proceeding. On June 6, 2007, ESNG and interested parties reached a settlement agreement in principle on its base rate proceeding filed with the FERC on October 31, 2006. The negotiated settlement provided for an annual cost of service of $21,536,000, which reflected a pretax rate of return of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, ESNG submitted its Settlement Offer to the Presiding Administrative Law Judge (“ALJ”) for review and certification to the full Commission.
ESNG filed concurrently with its Settlement Agreement a Motion to place the settlement rates into effect on September 1, 2007, in order to expedite the implementation of the reduced settlement rates pending final approval of the settlement. The FERC issued an order on September 25, 2007, authorizing ESNG to commence billing its settlement rates, effective September 1, 2007.
On October 1, 2007, the Presiding ALJ forwarded to the full Commission an order certifying the uncontested Settlement Agreement as fair, reasonable, and in the public interest. A final FERC Order approving the settlement was issued on January 31, 2008. In compliance with the Settlement Agreement, refunds, inclusive of interest, totaling $1.26 million, based on the higher interim rates that were effective for the period from May 15, 2007 through August 31, 2007, were distributed to ESNG’s customers on February 1, 2008.
Interruptible Revenue Sharing. On May 15, 2008,April 30, 2009, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC. InESNG reported in this filing ESNG reported that since its interruptible service revenue exceeded its annual threshold amount, it refunded to its eligible firm customers a total of $63,675$245,500, inclusive of interest, in the second quarter of 2008 to its eligible firm service customers in accordance with the terms of its tariff and the rate case Settlement Agreement described above.2009.
Fuel Retention Percentage and Cash Out. On June 24, 2008,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 retain its current Fuel Retention Percentageimplement an FRP rate of zero0.12 percent and also a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund a total of $412,013, including$294,540, inclusive of interest, to its eligible customers in the thirdsecond quarter of 2008 as a result of2009 by netting its over-recovered Gas Required for Operationsfuel cost against its under-recovered Cash-Out Cost.cash-out cost. The FERC approved these proposals, onand ESNG refunded $294,540 to customers in July 11, 2008, and customer refunds were distributed that same month.2009.
Prior Notice Activity — Blanket Certificate Authority. On July 2, 2008,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, a Prior Notice filing under its Blanket Certificate Authoritywhich will have no financial impact on ESNG.
On August 21, 2009, ESNG filed revised tariff sheets to add a new delivery pointreflect an increase in the Annual Charge Adjustment (“ACA”) surcharge from $0.0017 per Dt to serve an industrial customer located in Seaford, Delaware. In accordance with FERC regulations, a Prior Notice filing requires a 60-day window for protests. No protests were received, and ESNG was authorized$0.0019 per Dt. The ACA surcharge is designed to construct and operate the new delivery point. In mid-October and prior to the commencement of any construction, the customer notified ESNG that, based on adverse developments affecting the market for its products, it did not require the new delivery point. Pursuant to a pre-construction contract between the parties, the customer reimbursed ESNG a total of $500,000 for pre-constructionrecover 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 it pursuedproposed and were made effective January 15, 2010. As this project.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 to purchase gas and electricity from various suppliers. The contracts have various expiration dates. In March 2008, the Company2009, 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. This contract expires on March 31, 2009. 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.
Page 96     Chesapeake Utilities Corporation 2008 Form 10-K

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 natural gas supply managementmarketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiariesNeither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 20082009 was $22.2$22.7 million, with the guarantees expiring on various dates in 2009.2010.
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, 2009.2010. The letter of credit is provided as security to satisfy the deductibles under the Company’sour various insurance policies. There have been no draws on this letter of credit as of December 31, 2008.2009. We do not anticipate that this letter of credit will be drawn upon by the counterparty and we expect that it will be renewed to the extent necessary in the future.
Internal Revenue Service ExaminationOther
In November 2007, the Internal Revenue Service (“IRS”) initiated an examination of our consolidated federal tax return for the year ended December 31, 2005. During the review, the IRS expanded its examination to include our 2006 consolidated federal tax return as well.
In September 2008, the IRS completed its examination of our 2005 and 2006 consolidated federal tax returns and issued its Examination Report. As a result of the examination, the Company reduced its income tax receivable by $27,000 for the tax liability associated with disallowed expense deductions included on the tax returns. The Company has amended its 2005 and 2006 federal and state corporate income tax returns to reflect the disallowed expense deductions.
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 20082009 Form 10-K     Page 97

107

 

Notes to the Consolidated Financial Statements
P.Q. Quarterly Financial Data (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 and to disclose OnSight as a discontinued operation. The quarterly information shown has been adjusted to reflect the reclassification of OnSight’s operations for all periods presented.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  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 $100,273,502 $69,056,959 $49,698,013 $72,415,004  $100,274 $69,057 $49,698 $72,415 
Operating Income $14,040,715 $4,329,439 $1,170,393 $8,938,386  $14,041 $4,329 $1,170 $8,938 
Net Income (Loss) $7,574,343 $1,818,924 $(198,298) $4,412,291  $7,574 $1,819 $(198) $4,412 
Earnings per share: 
Earnings (Loss) per share: 
Basic $1.11 $0.27 $(0.03) $0.65  $1.11 $0.27 $(0.03) $0.65 
Diluted $1.10 $0.27 $(0.03) $0.64  $1.10 $0.27 $(0.03) $0.64 
 
2007
 
Operating Revenue $93,526,891 $52,501,920 $41,418,718 $70,838,968 
Operating Income $14,613,572 $3,698,066 $985,634 $8,816,310 
Net Income (Loss) $7,991,088 $1,481,791 $(355,898) $4,080,730 
Earnings per share: 
Basic $1.19 $0.22 $(0.05) $0.60 
Diluted $1.18 $0.22 $(0.05) $0.60 
Page 98      Chesapeake Utilities Corporation 2008 Form 10-K

(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.
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
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, 2008.2009. 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, 2008.2009.
Changes in Internal Controls
ThereOther 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, 2008,2009, that materially affected, or is reasonably likely to materially affect, 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 Item 8 under the heading “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.

Page 108     Chesapeake Utilities Corporation 2009 Form 10-K

CEO and CFO Certifications
The Company’s Chief Executive Officer and Chief Financial Officer have filed with the SEC 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, 2008.2009. In addition, on May 20, 2008,June 1, 2009 the Company’s Chief Executive Officer certified to the NYSE 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, Beard Miller Company LLP,ParenteBeard LLC, have audited and issued their report on effectiveness of the Company’sour internal control over financial reporting. That report appears below.in the following page.

Chesapeake Utilities Corporation 20082009 Form 10-K     Page 99

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, 2008,2009, 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, 2008,2009, 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, 20082009 and 2007,2008, and the related consolidated statements of income, stockholders’ equity and cash flows and income taxes for the years then ended,of Chesapeake Utilities Corporation, and our report dated March 9, 20098, 2010 expressed an unqualified opinion.
/s/ Beard Miller Company LLP     
Beard Miller Company LLP
Reading, Pennsylvania
March 9, 2009
/s/ ParenteBeard LLC
ParenteBeard LLC
Malvern, Pennsylvania
March 8, 2010

Page 100110     Chesapeake Utilities Corporation 20082009 Form 10-K

 

Item 9B. Other Information.
None
Part III
Item 10. Directors, Executive Officers of the Registrant and Corporate 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,” to be filed not later than March 31, 2009,2010, in connection with the Company’s Annual Meeting to be held on or about May 6, 2009.5, 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 this report following Item 4, as Item 4A, under the caption “Executive Officers of the 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, 2009,2010, in connection with the Company’s Annual Meeting to be held on or about May 6, 2009.5, 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, 2009,2010, in connection with the Company’s Annual Meeting to be held on or about May 6, 2009.5, 2010.

Chesapeake Utilities Corporation 20082009 Form 10-K     Page 101

111

 

The following table sets forth information, as of December 31, 2008,2009, 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 to  Weighted-average  issuance under equity 
  be issued upon exercise  exercise price  compensation plans 
  of outstanding options,  of outstanding options,  (excluding securities 
  warrants and rights  warrants and rights  reflected in column (a)) 
Equity compensation plans approved by security holders  —   —   446,632(1)
          
             
Equity compensation plans not approved by security holders  —(2)  —   — 
          
             
Total  —   —   446,632 
          
(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, 51,28944,115 shares available under the 2005 Directors Stock Compensation Plan, and 24,05023,850 shares available under the 2005 Employee Stock Awards Plan.
(2)All warrants were exercised in 2006.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
NoneThe 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.
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 the Independent Registered Public Accounting Firm,” to be filed not later than March 31, 2009,2010, in connection with the Company’s Annual Meeting to be held on or about May 6, 2009.5, 2010.

Page 102112     Chesapeake Utilities Corporation 20082009 Form 10-K

 

Part IV
Item 15. Exhibits, Financial Statement Schedules.
(a) 
The following documents are filed as part of this report:
 1. 
Financial Statements:
•Report of Independent Registered Public Accounting Firm;
•Consolidated Statements of Income for each of the three years ended December 31, 2008, 2007, and 2006;
•Consolidated Balance Sheets at December 31, 2008 and December 31, 2007;
•Consolidated Statements of Cash Flows for each of the three years ended December 31, 2008, 2007, and 2006;
•Consolidated Statements of Stockholders’ Equity for each of the three years ended December 31, 2008, 2007, and 2006;
•Consolidated Statements of Income Taxes for each of the three years ended December 31,2008, 2007, and 2006;
•Notes to the Consolidated 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.
 2. 
Financial Statement Schedule:Schedules:
•Report of Independent Registered Public Accounting Firm; and
•Schedule II — Valuation and Qualifying Accounts.
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.
Report of Independent Registered Public Accounting Firm;
Schedule I — Parent Company Condensed Financial Statements; and
Schedule II — Valuation and Qualifying Accounts.
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
     
•
 Exhibit 1.1 Underwriting 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 3.1 Restated 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 3.2 Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective December 11, 2008, are incorporated herein by reference to Exhibit 3 of the Company’s Current Report on Form 8-K, filed herewith.December 16, 2008, File No. 001-11590.
     
•
 Exhibit 4.1 Form 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 4.2 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 4.3 Note 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.
Chesapeake Utilities Corporation 2008 Form 10-K      Page 103

     
•
 Exhibit 4.4 Note 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 4.5 Note 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 4.6 Note 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 4.7 Note Agreement entered into by the CompanyChesapeake on October 31, 2008, pursuant to which the Company,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. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request.
     
•
 Exhibit 4.8 Form 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 4.9 Form 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 4.10 Form 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 4.11Form of Indenture 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 7-A of Florida Public Utilities Company’s Registration No. 2-6087.
•Exhibit 4.12Fourteenth Supplemental Indenture entered into by Florida Public Utilities Company on September 1, 2001, pursuant to which Florida Public Utilities Company, on September 1, 2001, privately placed $15,000,000 of its 6.85% First Mortgage Bonds, is incorporated herein by reference to Exhibit 4(b) of Florida Public Utilities Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 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 January 1, 2005, is incorporated herein by reference to Exhibit 10.3 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.
     
•
 Exhibit 10.2* Chesapeake Utilities Corporation Directors Stock Compensation Plan, adopted in 2005, is incorporated herein by reference to the Company’sour Proxy Statement dated March 28, 2005, in connection with the Company’sour 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 the Company’sour Proxy Statement dated March 28, 2005, in connection with the Company’sour 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 the Company’sour Proxy Statement dated March 28, 2005, in connection with the Company’sour Annual Meeting held on May 5, 2005, File No. 001-11590.
     
•
 Exhibit 10.5* Chesapeake Utilities Corporation Deferred Compensation Plan, asProgram, amended and restated effectiveas of January 1, 2009, is filed herewith.incorporated herein by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
Page 104      Chesapeake Utilities Corporation 2008 Form 10-K

     
•
 Exhibit 10.6* Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and S. Robert Zola, is incorporated herein by reference to Exhibit 10.7 of the Company’sour 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 filed herewith.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 10.810.3 of the Company’s AnnualCurrent Report on Form 10-K for the year ended December 31, 2006,8-K, filed January 7, 2010, File No. 001-11590.
     
•
 Exhibit 10.9*Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.
•
Exhibit 10.10*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 10.910.4 of the Company’s AnnualCurrent Report on Form 10-K for the year ended8-K, filed January 7, 2010, File No. 001-11590.

Chesapeake Utilities Corporation 2009 Form 10-K     Page 115

•Exhibit 10.12*Executive Employment Agreement dated December 31, 2006,2009, 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 10.11*Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.
•
Exhibit 10.12*Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is incorporated herein by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.
•
 Exhibit 10.13*Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.
•
Exhibit 10.14*Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.
•
Exhibit 10.15*Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is filed herewith.
•
Exhibit 10.16* 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 the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.17*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 the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.18*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 incorporated herein by reference to Exhibit 10.13 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.19*10.16* 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 Michael P. McMasters, is incorporated herein by reference to Exhibit 10.14 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
Chesapeake Utilities Corporation 2008 Form 10-K      Page 105

     
•
 Exhibit 10.20*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 the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.21*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 the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.22*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 the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.23*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 the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.24*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 incorporated herein by reference to Exhibit 10.19 of the Company’sour 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 10.25*10.22* 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 S. Robert Zola, is incorporated herein by reference to Exhibit 10.20 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.
     
•
 Exhibit 10.26*10.23* Form of Performance Share Agreement 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 incorporated herein by reference to Exhibit 10.26 on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
•Exhibit 10.24*Form of Performance Share Agreement 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 10.27*10.25*Performance Share Agreement dated January 20, 2010 for the period 2010 to 2011, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Joseph Cummiskey is filed herewith.
•Exhibit 10.26* Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is filed herewith.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 10.28*10.27* Chesapeake Utilities Corporation Supplemental Executive Retirement Savings Plan, as amended and restated effective January 1, 2009, is filed herewith.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 12 Computation of Ratio of Earning to Fixed Charges is filed herewith.
Page 106      Chesapeake Utilities Corporation 2008 Form 10-K

     
•
 Exhibit 14.1 Code of Ethics for Financial Officers is incorporated herein by reference to Exhibit 14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.filed herewith.
     
•
 Exhibit 14.2 Business Code of Ethics and Conduct is filed herewith.
     
•
 Exhibit 21 Subsidiaries of the Registrant is filed herewith.
     
•
 Exhibit 23.1 Consent of Independent Registered Public Accounting Firm is filed herewith.
     
•
 Exhibit 23.231.1 ConsentCertificate of Preceding Independent Registered Public Accounting Firm for the year 2006Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d-14(a), dated March 8, 2010, is filed herewith.
     
•
Exhibit 31.1Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 9, 2009, is filed herewith.
•
 Exhibit 31.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d-14(a), dated March 9, 2009,8, 2010, is filed herewith.
     
•
 Exhibit 32.1 Certificate of Chief Executive OfficeOfficer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 9, 2009,8, 2010, is filed herewith.
     
•
 Exhibit 32.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 9, 2009,8, 2010, is filed herewith.
   
* Management contract or compensatory plan or agreement.

Page 118     Chesapeake Utilities Corporation 20082009 Form 10-K      Page 107

 

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  
  By:/s/ John R. Schimkaitis
John R. Schimkaitis
PresidentVice Chairman and Chief Executive Officer 
Date: March 8, 2010  
Date:March 9, 2009
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
 
Ralph J. Adkins,
Chairman of the Board and Director
 /s/ John R. Schimkaitis
 
John R. Schimkaitis, President,
and Director
Vice Chairman, Chief Executive Officer and Director		  
Date: March 9, 2009February 24, 2010 Date: March 9, 20098, 2010  
     
/s/ Beth W. Cooper
Beth W. Cooper, Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
Date: March 8, 2010
 /s/ Eugene H. Bayard
Eugene H. Bayard, Director
Date: February 24, 2010		  
     
Beth W. Cooper, Senior Vice President
/s/ Richard Bernstein
Richard Bernstein, Director
 Eugene H. Bayard,/s/ Thomas J. Bresnan
Thomas J. Bresnan, Director		  
and Chief Financial OfficerDate: February 24, 2010 Date: February 24, 2009
(Principal Financial and Accounting Officer)
Date: March 9, 20098, 2010  
     
/s/ Thomas P. Hill, Jr.
Thomas P. Hill, Jr., Director
/s/ Dennis S. Hudson, III
Dennis S. Hudson, III, Director		  
/s/ Richard BernsteinDate: February 24, 2010 /s/ Thomas J. BresnanDate: February 24, 2010  
     
Richard Bernstein,
/s/ Paul L. Maddock, Jr.
Paul L. Maddock, Jr., Director
 Thomas/s/ J. Bresnan,Peter Martin
J. Peter Martin, Director		  
Date: February 24, 20092010 Date: March 9, 2009February 24, 2010  
     
/s/ ThomasMichael p. Mcmasters
Michael P. Hill, Jr.McMasters, President, Chief Operating Officer and Director
Date: March 8, 2010
 /s/ J. Peter MartinJoseph E. Moore, Esq
Joseph E. Moore, Esq., Director
Date: February 24, 2010		  
     
Thomas P. Hill, Jr., DirectorJ. Peter Martin, Director
Date: February 24, 2009Date: February 24, 2009
/s/ Joseph E. Moore, Esq
/s/ Calvert A. Morgan, Jr.
Joseph E. Moore, Esq., DirectorJr
Calvert A. Morgan, Jr., Director		 
Date: February 24, 2009Date: February 24, 2009
/s/ Dianna F. Morgan
 
Dianna F. Morgan, Director
  
Date: February 24, 20092010 Date: February 24, 2010  
Page 108      

Chesapeake Utilities Corporation 20082009 Form 10-K

     Page 119

 

Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
The audit referred to in our report dated March 9, 20098, 2010 relating to the consolidated financial statements of Chesapeake Utilities Corporation as of December 31, 2009 and 2008 and 2007 and for each of the years thenin the three-year period ended December 31, 2009, which is contained in Item 8 of this Form 10-K also included the audits of the financial statement scheduleschedules listed in Item 15. This15(a) 2. These financial statement schedule isschedules are the responsibility of the Chesapeake Utilities Corporation’s management. Our responsibility is to express an opinion on thisthese financial statement scheduleschedules based on our audits.
In our opinion such financial statement schedule,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/ Beard Miller
/s/ ParenteBeard LLC
ParenteBeard LLC
Malvern, Pennsylvania
March 8, 2010

Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company LLP     Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Beard MillerCondensed 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 LLPCondensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Reading, Pennsylvania
March 9, 2009Condensed 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    Balance at Additions   
 Beginning of Charged to Other Balance at End  Beginning of Charged to Other Balance at End 
For the Year Ended December 31, Year Income Accounts(1) Deductions(2) of Year  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
 $952,075 $1,185,906 $241,153 $(1,220,120) $1,159,014  $952 $1,186 $241 $(1,220) $1,159 
           
 
2007 $661,597 $818,561 $26,190 $(554,273) $952,075  $662 $818 $26 $(554) $952 
           
 
2006 $861,378 $381,424 $65,519 $(646,724) $661,597 
           
   
(1) Recoveries.
 
(2) Uncollectible accounts charged off.

 

Upon written request,
Chesapeake will provide, free of
charge, a copy of any exhibit to
the 2008 Annual Report on
Form 10-K not included
in this document.