dqk.htm

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, 2007       Commission File Number: 001-11590

Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)

State of Delaware                                                           51-0064146
        (State or other jurisdiction of                                        (I.R.S. Employer
                                                                                                     incorporation or organization)                                      Identification No.)

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

302-734-6799
(Registrant’s telephone number, including area code)

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

Title of each class                                                    Name of each exchange on which registered
                                                                  Common Stock - par value per share $.4867                                         New York Stock Exchange, Inc.



Securities registered pursuant to Section 12(g) of the Act:
8.25% Convertible Debentures Due 2014
(Title of class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [  ]. No [X].

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]. No [  ].

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [  ]                                                      Accelerated filer  [X]                                           Non-accelerated filer  [  ]                                                      Smaller Reporting Company  [  ]

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

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2007, 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 $230.9 million.

As of February 29, 2008, 6,806,487 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the Proxy Statement for the 2008 Annual Meeting of Stockholders are incorporated by reference in Part III.


 
 

 

Chesapeake Utilities Corporation
 
Form 10-K

YEAR ENDED DECEMBER 31, 2007

TABLE OF CONTENTS
 
 




 
Page
Part I
1
Item 1. Business.
5
Item 1A. Risk Factors.
7
Item 1B. Unresolved Staff Comments.
7
Item 2. Properties
7
Item 3. Legal Proceedings
7
Item 4. Submission of Matters to a Vote of Security Holders.
7
Item 4A. Executive Officers of the Registrant.
8
Part II
8
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
8
Item 6. Selected Financial Data
11
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
15
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
32
Item 8. Financial Statements and Supplementary Data.
32
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
54
Item 9A. Controls and Procedures.
54
Item 9B. Other Information.
57
Part III
57
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance.
57
Item 11. Executive Compensation.
57
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
57
Item 13. Certain Relationships and Related Transactions, and Director Independence.
57
Item 14. Principal Accounting Fees and Services.
58
Part IV
58
Item 15. Exhibits, Financial Statement Schedules.
58
Signatures
60


 

 
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.

Safe Harbor for Forward-Looking Statements
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 and other matters. It is important to understand that these forward-looking statements are not guarantees but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to those discussed in Item 1A, “Risk Factors.”

Item 1. Business.
 
(a)  
General
Chesapeake is a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses. Chesapeake is a Delaware corporation that was formed in 1947.

Chesapeake is composed of four operating segments:

·  
Natural Gas.  The natural gas segment includes regulated natural gas distribution and transmission operations and also a non-regulated natural gas marketing operation.

·  
Propane.  The propane segment includes non-regulated propane distribution and wholesale marketing operations.

·  
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.

·  
Other.  The other segment consists primarily of non-regulated operations that own real estate leased to other Company subsidiaries.


(b)  
Financial Information About Business Segments
Our natural gas segment accounts for approximately 80 percent of Chesapeake’s consolidated operating income  and approximately 86 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.
 
 
             
Net Property, Plant
 
(Thousands)
 
Operating Income
   
& Equipment
 
Natural Gas
  $ 22,485       80 %   $ 224,661       86 %
Propane
    4,498       16 %     29,363       11 %
Advanced information systems
    836       3 %     419       < 1 %
Other & eliminations
    295       1 %     5,980       2 %
Total
  $ 28,114       100 %   $ 260,423       100 %

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


(c)  
Narrative Description of the Business
(i)(a) Natural Gas
Chesapeake’s natural gas segment performs natural gas distribution, transmission and marketing services for its customers. Chesapeake operates its natural gas distribution services as three divisions: Delaware, Maryland, and Florida, which are based in their respective service territories.  These three divisions serve approximately 62,900 residential, commercial and industrial customers in central and southern Delaware, Maryland’s Eastern Shore and parts of Florida. The Company’s natural gas transmission subsidiary, Eastern Shore Natural Gas Company (“Eastern Shore” or “ESNG”), operates a 370-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, Peninsula Energy Services Company, Inc. (“PESCO”), also provides natural gas supply and supply management services in the State of Florida.

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 48,490 customers, of which approximately 48,290 are residential and commercial customers purchasing gas primarily for heating and cooking use. The remaining 200 customers are industrial. For the year 2007, operating revenues and deliveries by customer class were as follow:

   
Operating Revenues
   
Deliveries
 
   
(Thousands)
   
(MMcf's)
 
Residential
  $ 49,858       47 %     2,586,517       35 %
Commercial
    29,430       28 %     2,047,112       28 %
Industrial
    1,597       2 %     612,631       8 %
Subtotal
  $ 80,885       77 %     5,246,260       71 %
Interruptible
    7,989       7 %     1,023,866       14 %
Off-system
    16,819       16 %     1,129,137       15 %
Total
  $ 105,693       100 %     7,399,263       100 %
 
 
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Florida. The Florida division distributes natural gas to approximately 14,250 residential and commercial and 100 industrial customers in the 13 Counties of Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee, Liberty, Washington and Citrus.  For the year 2007, operating revenues and deliveries by firm transportation customer class were as follow:
 
   
Operating Revenues
   
Deliveries
 
   
(Thousands)
   
(MMcf's)
 
Residential
  $ 3,612       32 %     307,779       5 %
Commercial
    2,929       26 %     1,067,539       18 %
Industrial
    4,744       42 %     4,478,921       77 %
Total
  $ 11,285       100 %     5,854,239       100 %

Natural Gas Transmission
The Company’s wholly-owned transmission subsidiary, Eastern Shore, owns and operates an interstate natural gas pipeline and provides open-access transportation services for affiliated and non-affiliated local distribution companies through an integrated gas pipeline system extending from southeastern Pennsylvania through Delaware to its terminus on the Eastern Shore of Maryland. Eastern Shore also provides swing transportation service and contract storage services.  For the year 2007, operating revenues and deliveries by customer class were as follow:
 
   
Operating Revenues
   
Deliveries
 
   
(Thousands)
   
(MMcf's)
 
Local Distribution Companies
  $ 19,354       83 %     10,011,290       52 %
Industrial
    3,076       13 %     7,793,128       40 %
Commercial
    856       4 %     1,542,061       8 %
Total
  $ 23,286       100 %     19,346,479       100 %
 
During 2005, Chesapeake formed a wholly-owned subsidiary, Peninsula Pipeline Company, Inc. (“PIPECO”), to provide industrial customers in the State of Florida natural gas transportation service as an intrastate pipeline. PIPECO did not have any activity in 2005 and 2006.  On August 27, 2007, PIPECO filed with the Florida PSC its petition for approval of a natural gas transmission pipeline tariff in order to establish its operating rules and regulations.  The Florida PSC approved the petition at its December 4, 2007 agenda conference. PIPECO will begin marketing its services to potential industrial customers in 2008.
 
Natural Gas Marketing
 PESCO, a wholly-owned subsidiary, competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers in the State of Florida with the  objective of earning a profit 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 assets owned by the Company’s regulated Florida distribution system and intrastate pipeline and four other regulated utilities’ local distribution systems.  PESCO bills its customers through the billing services of the regulated utilities that deliver the gas, or directly, through its own billing capabilities.
 
At December 31, 2007, PESCO served approximately 1,500 commercial and industrial natural gas customers, and as of January 2008, PESCO began offering similar services to customers in the State of Delaware.

Gas Supplies, Firm Transportation and Storage Capacity
The Company believes that the availability of gas supply and transportation to its Delaware, Maryland and Florida divisions 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.

The Delaware and Maryland divisions have both firm and interruptible transportation service contracts with four interstate “open access” pipelines, including Eastern Shore, a wholly-owned subsidiary. The divisions are directly interconnected with Eastern Shore, and are contracted with interstate pipelines upstream of Eastern Shore.  These interstate pipelines include Transcontinental Gas Pipe Line Corporation (“Transco”), Columbia Gas Transmission Corporation (“Columbia”) and Columbia Gulf Transmission Company (“Gulf”). None of the upstream service providers is an affiliate of the Company. The 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 supply and firm demand, the divisions purchase natural gas supplies on the spot market from various suppliers. This gas is transported by the upstream pipelines and delivered to the divisions’ interconnections with Eastern Shore. The divisions also have the capability to use propane-air peak-shaving to supplement or displace the spot market purchases.

Delaware.
 
Pipeline
Firm transportation capacity maximum peak-day daily deliverability (Dts)
Firm storage capacity maximum peak-day daily withdrawal (Dts)
Expiration
Transco
11,356
6,407
Various dates between 2008 and 2013
Columbia
3,460
8,224
Various dates between 2010 and 2020
Gulf
880
-
Expries in 2009
Eastern Shore
57,639
4,146
Various dates between 2008 and 2022
 

The Delaware 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 Delaware division also has contracts for firm peaking gas supplies to be delivered to its system in order to meet the differential between the Delaware division’s capacity on Eastern Shore and capacity on pipelines upstream of Eastern Shore.  These supply contracts provide a maximum firm daily entitlement of 44,566 Dts, delivered on the Transco, Columbia, and/or Gulf systems to Eastern Shore 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.
 

 
- Page 2 -

Maryland.
 
Pipeline
Firm transportation capacity maximum peak-day daily deliverability (Dts)
Firm storage capacity maximum peak-day 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
19,428 2,306
Various dates between 2008 and 2022
 

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 Eastern Shore and capacity on pipelines upstream of Eastern Shore.  These supply contracts provide a maximum firm daily entitlement of 12,816 Dts, delivered on the Transco, Columbia, and/or Gulf systems to Eastern Shore 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 Division

The Florida division has firm transportation service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System (“Gulfstream”). Pursuant to a program approved by the Florida Public Service Commission (“Florida PSC”), all of the capacity under these agreements has been released to various third parties, including PESCO. Under terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay for the service.

Chesapeake’s contracts with FGT include: (a) a contract, which expires in 2010, for daily firm transportation capacity of 23,519 Dts for the months of November through April, capacity of 20,123 Dts for the months of May through September, and capacity of 22,105 Dts for October; and (b) a contract for daily firm transportation capacity of 1,000 Dts daily, which expires in 2015. Chesapeake’s contract with Gulfstream is for daily firm transportation capacity of 10,000 Dts and expires in 2022.

Eastern Shore

Eastern Shore has three contracts with Transco for a total of 7,292 Dts of firm peak day storage entitlements and total storage capacity of 288,003 Dts, which expire in 2013.  Eastern Shore 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.

PESCO

PESCO currently has contracts with ConocoPhillips and British Petroleum (“BP”) for the purchase of firm natural gas supplies. The ConocoPhillips contract, which provides a maximum firm daily entitlement of 15,000 MMBtus, and the BP contract, which provides a maximum firm daily entitlement of 10,000 MMBtus, expires in May 2008.  PESCO is currently in the process of obtaining and reviewing supply proposals from suppliers and anticipates executing agreements prior to the expiration of the existing contracts.

The Company believes that the availability of gas supply and transportation to its operations is adequate under existing arrangements to meet the anticipated needs of its customers.

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

Rates and Regulation
Chesapeake’s natural gas distribution divisions are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions (“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’s firm distribution sales rates are subject to gas cost recovery mechanisms, which match revenues with gas 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.

Eastern Shore is subject to regulation by the Federal Energy Regulatory Commission (“FERC”) as an interstate pipeline. The FERC regulates the terms and conditions of service and the rates Eastern Shore can charge for its transportation and storage services.

Management monitors the achieved rate of return of its distribution divisions and Eastern Shore 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 — Regulatory Activities.”

Seasonality of Natural Gas Revenues
Revenues from the Company’s residential and commercial natural gas distribution activities are affected by seasonal variations in weather conditions.  Weather conditions 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 reduced use of natural gas, while sustained colder-than-normal temperatures will tend to result in greater use. The Company measures 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.

In efforts to stabilize the level of net revenues collected from customers, the Company has begun to request Weather Normalization Adjustments (“WNA”) in its rate filings with the Maryland and Delaware PSCs. A WNA mechanism is a billing adjustment mechanism that is designed to eliminate the effect of deviations from average seasonal temperatures on utility net revenues. On September 26, 2006, the Maryland PSC approved the Company’s proposal to implement a revenue normalization mechanism for its residential heating and smaller commercial heating customers.  The Company also has a pending rate case application filed with the Delaware PSC, requesting among other things, to implement a WNA billing mechanism. For further discussion of these matters, refer to the discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis — Regulatory Activities.”


(i)(b) Propane
Chesapeake’s retail propane distribution group consists of: (1) Sharp Energy, Inc. (“Sharp Energy”), a wholly-owned subsidiary of Chesapeake, (2) Sharpgas, Inc. (“Sharpgas”), a wholly-owned subsidiary of Sharp Energy, and (3) Tri-County Gas Co., Inc. (“Tri-County”), a wholly-owned subsidiary of Sharp Energy. The propane wholesale marketing group consists of Xeron, Inc. (“Xeron”), a wholly-owned subsidiary of Chesapeake.

- Page 3 -

 
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.
 
 
Propane Distribution
During 2007, our propane distribution operations served approximately 34,100 propane customers in central and southern Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania and parts of Florida and delivered approximately 29.8 million retail and wholesale gallons of propane.  The propane distribution business is affected by many factors, such as seasonality, the absence of price regulation, and competition among local providers.

For the year 2007, operating revenues and number of customers for our Delmarva and Florida propane distribution operations were as follow:
 

 
Operating Revenues
Total Gallons Sold
Average No. of
 
(Thousands)
(Thousands)
Customers
Delmarva
       57,622
95%
       28,665
96%
       32,153
94%
Florida
         2,826
5%
         1,120
4%
         1,990
6%
Total
       60,448
100%
       29,785
100%
       34,143
100%

Propane Wholesale Marketing
In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeron markets propane to large, independent petrochemical companies, resellers and retail propane companies in the southeastern United States. The propane wholesale marketing business is affected by wholesale price volatility and supply levels.  Additional information on Xeron’s trading and wholesale marketing activities, market risks and the controls that limit and monitor Xeron’s risks is included in Item 7 under the heading “Management’s Discussion and Analysis — Market Risk.”

The Company’s 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 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-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 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 66,000 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.

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.

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

Rates and Regulation
The propane distribution and 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 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.

Seasonality of Propane Revenues
Revenues from the Company’s 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 reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater use.


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

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


(i)(d)Other Subsidiaries
Skipjack, Inc. (“Skipjack”), Eastern Shore Real Estate, Inc. and Chesapeake Investment Company are wholly-owned subsidiaries of Chesapeake Service Company, which is a wholly-owned subsidiary of Chesapeake. Skipjack 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 the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services subsidiary, Chesapeake OnSight Services, LLC.


(ii) 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 — Liquidity and Capital Resources.”


(iii) Employees
As of December 31, 2007, Chesapeake had 445 employees, including 185 in natural gas, 134 in propane and 85 in advanced information services. The remaining 41 employees are considered general and administrative and include officers of the Company, treasury, accounting, internal audit, information technology, human resources and other administrative personnel.


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

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

The SEC also maintains an Internet site that contains reports, proxy and information statements and other information regarding the Company. The address of the SEC’s Internet website is www.sec.gov. Chesapeake makes available, free of charge, on the Company’s Internet website, its 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’s Internet website is www.chpk.com. The content of this website is not part of this report.

Chesapeake has a Business Code of Ethics and Conduct applicable to all employees, officers and directors and a Code of Ethics for Financial Officers. Copies of the Business Code of Ethics and Conduct and the Financial Officer Code of Ethics are available on its internet website. Chesapeake also adopted Corporate Governance Guidelines and Charters for the Audit Committee, Compensation Committee, and 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’s Internet website or may be obtained by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation; 909 Silver Lake Blvd.; Dover, DE 19904.

If Chesapeake makes any amendment to, or grants a waiver of, any provision of the Business Code of Ethics and Conduct or the Financial Officer Code of Ethics applicable to its principal executive officer, principal financial officer, principal accounting officer or controller, the amendment or waiver will be disclosed within five business days on the Company’s Internet website.
 
Item 1A. Risk Factors.
 
The following is a discussion of the primary factors that may affect the operations and/or financial performance of the regulated and unregulated businesses of Chesapeake. Refer to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 of this report for an additional discussion of these and other related factors that affect the Company’s operations and/or financial performance. The financial, operational, regulatory and legal, and environmental factors that affect the operations and/or financial performance of the Company include:

Financial Risks

Inability to access capital markets may impair our future growth.
We rely on access to both short-term and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from our operations. Currently, $65 million of the total $90 million of short-term lines of credit utilized to satisfy our short-term financing requirements are discretionary, uncommitted lines of credit. We utilize discretionary lines of credit to reduce the cost associated with these short-term financing requirements. We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. However, if we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.

A downgrade in our credit rating could adversely affect our access to capital markets.
Our ability to obtain adequate and cost effective capital depends on our credit ratings, which are greatly affected by our subsidiaries’ 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 covenants may impact financial condition if triggered.
Our long-term debt obligations 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’s financial condition.

A change in economic conditions and interest rates may adversely affect our results of operations and cash flows.
A downturn in the economies of the regions in which we operate, which we cannot accurately predict, might adversely affect our ability to increase our customer bases and cash flows at the same rates by which they have grown in the recent past. 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 borrowing 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. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. To help cope with the effects of inflation on our capital investments and returns, we seek rate relief from regulatory commissions for regulated operations 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 relief to offset the effects of inflation. To compensate for fluctuations in propane gas prices, we adjust our propane selling prices to the extent allowed by the market. However, there can be no assurance that we will be able to increase propane sales prices sufficiently to compensate fully for such fluctuations in the cost of propane gas to us.


Operational Risks

Fluctuations in weather may adversely affect our results of operations, cash flows and financial condition.
Our utility and propane distribution operations are sensitive to fluctuations in weather, and weather conditions directly influence the volume of natural gas and propane sold and delivered by our utility and propane distribution operations. A significant portion of our utility and propane distribution operation revenues is derived from the sale and delivery 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 and propane, increased supply costs and higher prices for customers.

The amount and availability of natural gas and propane supplies are difficult to predict; a substantial reduction in available supplies could reduce our earnings in those segments.
Natural gas and propane production can be affected by factors outside of our control, such as weather and refinery closings. If we are unable to obtain sufficient natural gas and propane supplies to meet demand, results in those segments may be adversely affected.

We rely on having access to interstate natural gas pipelines’ transportation and storage 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, we must acquire both sufficient natural gas supplies and interstate pipeline and storage 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, our own on-system resources, as well as the characteristics of our markets. Chesapeake, along with other local natural gas distribution companies and other participants in the industry, have raised concerns regarding the future availability of additional upstream interstate pipeline and storage capacity. This is a business issue which we must continue to manage as our customer base grows.

- Page 5 -

Natural gas and propane commodity price changes may affect the operating costs and competitive positions of our natural gas and propane distribution operations, which may adversely affect our results of operations, cash flows and financial condition.
Natural Gas. Over the last four years, natural gas costs have increased significantly, due to increased demand, and have become more volatile, due to events such as the hurricane activity in 2005, which reduced the natural gas available from the Gulf Coast region and caused a spike in natural gas prices. Higher natural gas prices can result in significant increases in the cost of gas billed to customers. Under our regulated gas cost recovery mechanisms, an increase in the cost of gas due to an increase in the price of the natural gas commodity generally has no immediate effect on our revenues and net income. Our net income, however, may be reduced by higher expenses that we may incur for uncollectable customer accounts and by lower volumes of natural gas deliveries as a result of customers reducing their consumption. Therefore, increases in the price of natural gas can affect our operating cash flows and the competitiveness of natural gas as an energy source.
 
Propane. Propane costs are subject to volatile changes as a result of product supply or other market conditions, including economic and political factors affecting crude oil and natural gas supply or pricing. Such cost changes can occur rapidly and can affect profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate in response to propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, declines in retail sales volumes, because of reduced consumption and increased amounts of uncollectible accounts may adversely affect net income.

Operating events affecting public safety and the reliability of Chesapeake’s natural gas distribution system could adversely affect the results of operations, financial condition and cash flows.
 
Chesapeake’s business is exposed to operational events, such as major leaks, mechanical problems and accidents, that could affect the public safety and reliability of its natural gas distribution 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 is unable to recover from customers, through the regulatory process, all or some of these costs and its authorized rate of return on these costs, this also could adversely affect the results of operations, financial condition and cash flows.

Because we operate in a competitive environment, we may lose customers to competitors.
In our natural gas marketing business, we compete with third-party suppliers to sell gas to commercial and industrial customers. In our gas transportation and distribution operations, our competitors include interstate pipelines, when distribution customers are located close enough to the transmission company’s pipeline to make direct connections economically feasible.

Our propane distribution operations compete with several other propane distributors, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Some of our competitors have significantly greater resources. The retail propane industry is mature, and we foresee modest growth in total demand. Given this limited growth, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow the propane distribution business is contingent upon execution of our community gas systems strategy to capture additional market share and to employ service pricing programs that retain and grow our customer base. Any failure to retain and grow our customer base would have an adverse effect on our results.
 
The propane wholesale marketing operation competes against various 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 to compete on the basis of technological expertise, reputation and price.

Changes in technology may adversely affect our advanced information services segment’s results of operations, cash flows and financial condition.
Our advanced information services segment participates in a market that is characterized by rapidly changing technology and accelerating product introduction cycles. The success of our advanced information services segment depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services, on a timely basis, and by keeping pace with technological developments and emerging industry standards. There is no assurance that we will be able to keep up with technological advancements 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, our propane wholesale and marketing subsidiary, and PESCO, our natural gas marketing subsidiary, 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.

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. Our propane distribution and wholesale marketing segments use derivative instruments, including forwards, 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 divisions, as well as PESCO. While we have a risk management policy and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial conditions may be adversely affected.

Changes in customer growth may affect earnings and cash flows.
Chesapeake’s ability to increase its gross margins in its regulated and propane businesses is dependent upon the new construction housing market, adding new industrial customers and conversion of customers to natural gas or propane from other fuel sources. Slowdowns in these markets could adversely affect the Company’s gross margin in its regulated or propane businesses, its earnings and cash flows.

Chesapeake’s businesses are capital intensive, and the costs of capital projects may be significant.
Chesapeake’s 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 are unable to manage such capital projects effectively or if we do not receive full recovery of such capital costs in future regulatory proceedings.
- Page 6 -


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 distribution operations; Eastern Shore, our natural gas transmission subsidiary, 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 divisions and Eastern Shore 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 distribution and interstate pipeline 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 by 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 supply; and (e) insufficient customer throughput commitments.

We are subject to operating and litigation risks that may not be fully covered by insurance.
Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting and delivering natural gas 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 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.

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

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

Further, existing environmental laws and regulations may be revised, or new laws and regulations seeking to protect the environment may be adopted 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.
 
Item 1B. Unresolved Staff Comments.
 
None.

Item 2. Properties
 
(a)  
General
The Company owns offices and operates facilities in the following locations: Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; and Winter Haven, Florida. Chesapeake rents office space in Dover and Ocean View, Delaware; Jupiter and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton and Salisbury, Maryland; Honey Brook and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In general, the Company believes that its properties are adequate for the uses for which they are employed.
 
(b)  
Natural Gas Distribution
Chesapeake owns over 1,033 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas and 741 miles of natural gas distribution mains (and related equipment) in its central Florida service areas. Chesapeake also owns facilities in Delaware and Maryland, which it uses for propane-air injection during periods of peak demand.

(c)  
Natural Gas Transmission
Eastern Shore owns and operates approximately 370 miles of transmission pipelines, extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania; and Hockessin, Delaware, to approximately 78 delivery points in southeastern Pennsylvania, Delaware and the eastern shore of Maryland.

(d)  
Propane Distribution and Wholesale Marketing
The company’s 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 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 66,000 gallons. Xeron does not own physical storage facilities or equipment to transport propane; however, it leases propane storage capacity and pipeline capacity.

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 agencies concerning rates. In the opinion of management, the ultimate disposition of these current proceedings will not have a material effect on our consolidated financial position.

(b)  
Environmental
See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to Consolidated Financial Statements — Note M.”

Item 4. Submission of Matters to a Vote of Security Holders.
 
None

 
- Page 7 -

 
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, 2007, with their recent business experience.  The age of each officer is as of the date of filing this report.

John R. Schimkaitis (age 60) Mr. Schimkaitis is President and Chief Executive Officer of Chesapeake and its subsidiaries. Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. He has served as President since 1997. Mr. Schimkaitis previously served as President and Chief Operating Officer, Executive Vice President, Senior Vice President, Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer and Assistant Secretary of Chesapeake.

Michael P. McMasters (age 49) Mr. McMasters is Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation. He was appointed Senior Vice President in 2004 and has served as Chief Financial Officer since December 1996. He has previously held the positions of Vice President, Treasurer, Director of Accounting and Rates, and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company.

Stephen C. Thompson (age 47) Mr. Thompson is President of Eastern Shore Natural Gas Company and Senior Vice President of Chesapeake Utilities Corporation. Prior to becoming Senior Vice President in 2004, he served as Vice President of Chesapeake. He has also served as Vice President, Director of Gas Supply and Marketing, Superintendent of Eastern Shore and Regional Manager for the Florida distribution operations.

Beth W. Cooper (age 41) Ms. Cooper is Vice President, Treasurer and Corporate Secretary of Chesapeake Utilities Corporation. Ms. Cooper has served as Corporate Secretary since July 2005. She previously served as Assistant Treasurer and Assistant Secretary, Director of Internal Audit, Director of Strategic Planning, Planning Consultant, Accounting Manager for Non-regulated Operations and Treasury Analyst. Prior to joining Chesapeake, she was employed as an auditor with Ernst & Young’s Entrepreneurial Services Group.

S. Robert Zola (age 55) Mr. Zola joined Sharp Energy in August 2002 as President. Prior to joining Sharp Energy, Mr. Zola most recently served as Northeast Regional Manager of Synergy Gas, now Cornerstone MLP, in Philadelphia, PA. During his 27-year career in the propane industry, Mr. Zola also started and successfully developed Bluestreak Propane, in Phoenix, AZ, which was ultimately sold to Ferrell Gas.
 
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 New York Stock Exchange (“NYSE”) under the symbol “CPK.” The high, low and closing prices of Chesapeake’s Common Stock and dividends declared per share for each calendar quarter during the years 2007 and 2006 were as follows:
 
 
                       
Dividends
 
                       
Declared
 
 
Quarter Ended
 
High
   
Low
   
Close
   
Per Share
 
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  
                           
2006
                         
 
March 31
  $32.47     $29.97     $31.24     $0.285  
 
June 30
  31.20     27.90     30.08     0.290  
 
September 30
  35.65     29.51     30.05     0.290  
 
December 31
  31.31     29.10     30.65     0.290  
                           

Dividends are payable at the discretion of our Board of Directors. Future payment of dividends, and the amount of these dividends, will depend on our financial condition, results of operations, capital requirements, and other factors. We sold no securities during the year 2007 that were not registered under the Securities Act of 1933, as amended.

Indentures to the long-term debt of the Company contain various restrictions. The most stringent restrictions state that the Company must maintain equity of at least 40 percent of total capitalization and the pro-forma fixed charge coverage ratio must be at least 1.5 times. The Company was in compliance with these restrictions and other debt covenants during 2007.

At December 31, 2007, there were 1,920 shareholders of record of the Common Stock.
 
- Page 8 -

 
(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, 2007.

 
                         
Period
 
Total Number of Shares Purchased
   
Average Price Paid per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
   
Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
 
October 1, 2007
                       
  through October 31, 2007 (1)
    490     $34.10      
0
      0  
November 1, 2007
                             
  through November 30, 2007
    0     $0.00       0       0  
December 1, 2007
                             
  through December 31, 2007
    0    $0.00       0       0  
Total
    490     $34.10       0       0  
                               
(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 Senior Executives under the Deferred Compensation Plan.
 
The Deferred Compensation Plan is discussed further in Note K to the Consolidated Financial Statements. During the
 
quarter, 490 shares were purchased through the reinvestment of dividends on deferred stock units.
 
                               
(2) Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to
 
     repurchase its shares.
                             

 
Discussion of compensation plans of Chesapeake and its subsidiaries, for which shares of Chesapeake common stock are authorized for issuance, included in the portion of the Proxy Statement captioned “Equity Compensation Plan Information” to be filed not later than March 31, 2008, in connection with the Company’s Annual Meeting to be held on May 1, 2008, is incorporated herein by reference.

The chief executive officer’s annual certification regarding the Company’s compliance with the NYSE’s corporate governance listing standards was submitted to the NYSE on May 29, 2007.

(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’s common stock during the five fiscal years ended December 31, 2007, with the cumulative total shareholder return on a hypothetical investment in both (i) the S&P 500 Index and (ii) an industry index consisting of 14 companies in the 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 in addition to seventeen other companies.  The Company chose to use the Edward Jones Natural Gas Distribution Group as its peer group this year for performance metrics comparison to coincide with the Compensation Committee’s decision to use this index of companies to evaluate the Company’s results in connection with issuing long-term awards to executive officers under the new long-term performance plan.

The fourteen 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., EnergySouth. Inc., The Laclede Group, Inc., New Jersey Resources Corporation, Northwest Natural Gas Company, Piedmont Natural Gas Co., Inc., RGC Resources, Inc., South Jersey Industries, Inc, and WGL Holdings, Inc.  The Company excluded SEMCO Energy, Inc. from its comparison due to its recent acquisition by Cap Rock Holding Corporation.

The comparison assumes $100 was invested on December 31, 2002 in the Company’s 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’s Common Stock.
 
- Page 9 -


 


               
 
2002
2003
2004
2005
2006
2007
 
Chesapeake
 $100 $148  $158 $189 $196 $211  
Industry Index
 $100 $120 $141 $152 $180 $202  
S&P 500
 $100  $128 $142 $149 $172  $182  


- Page 10 -



Item 6. Selected Financial Data
 


For the Years Ended December 31,
2007
2006 (3)
2005
2004
2003
Operating (in thousands of dollars) (1)
         
 
Revenues
         
   
Natural gas
$181,202
$170,374
$166,582
$124,246
$110,247
   
Propane
                62,838
                48,576
                48,976
                41,500
                41,029
   
Advanced informations systems
                15,099
                12,568
                14,140
                12,427
                12,578
   
Other and eliminations
                   (853)
                   (318)
                   (213)
                   (218)
                   (286)
 
Total revenues
$258,286
$231,200
$229,485
$177,955
$163,568
                 
 
Operating income
         
   
Natural gas
$22,485
$19,733
$17,236
$17,091
$16,653
   
Propane
                  4,498
                  2,534
                  3,209
                  2,364
                  3,875
   
Advanced informations systems
                     836
                     767
                  1,197
                     387
                     692
   
Other and eliminations
                     295
                     298
                     279
                     335
                     359
 
Total operating income
$28,114
$23,332
$21,921
$20,177
$21,579
                 
 
Net income from continuing operations
$13,218
$10,748
$10,699
$9,686
$10,079
                 
                 
Assets (in thousands of dollars)
         
 
Gross property, plant and equipment
$352,838
$325,836
$280,345
$250,267
$234,919
 
Net property, plant and equipment (2)
$260,423
$240,825
$201,504
$177,053
$167,872
 
Total assets (2)
$381,557
$325,585
$295,980
$241,938
$222,058
 
Capital expenditures (1)
$30,142
$49,154
$33,423
$17,830
$11,822
                 
                 
Capitalization (in thousands of dollars)
         
 
Stockholders' equity
$119,576
$111,152
$84,757
$77,962
$72,939
 
Long-term debt, net of current maturities
                63,256
                71,050
                58,991
                66,190
                69,416
 
Total capitalization
$182,832
$182,202
$143,748
$144,152
$142,355
                 
 
Current portion of long-term debt
$7,656
$7,656
$4,929
$2,909
$3,665
 
Short-term debt
                45,664
                27,554
                35,482
                  5,002
                  3,515
 
Total capitalization and short-term financing
$236,152
$217,412
$184,159
$152,063
$149,535
                 
                 
                 
 
(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) Statement of Financial Accounting Standard ("SFAS") 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001.
 
(3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.



   
 


- Page 11 -




For the Years Ended December 31,
2002
2001
2000
1999
1998
Operating (in thousands of dollars) (1)
         
 
Revenues
         
   
Natural gas
$93,588
$107,418
$101,138
$75,637
$68,770
   
Propane
                29,238
                35,742
                31,780
                25,199
                23,377
   
Advanced informations systems
                12,764
                14,104
                12,390
                13,531
                10,331
   
Other and eliminations
                   (334)
                   (113)
                   (131)
                     (14)
                     (15)
 
Total revenues
$135,256
$157,151
$145,177
$114,353
$102,463
                 
 
Operating income
         
   
Natural gas
$14,973
$14,405
$12,798
$10,388
$8,820
   
Propane
                  1,052
                     913
                  2,135
                  2,622
                     965
   
Advanced informations systems
                     343
                     517
                     336
                  1,470
                  1,316
   
Other and eliminations
                     237
                     386
                     816
                     495
                     485
 
Total operating income
$16,605
$16,221
$16,085
$14,975
$11,586
                 
 
Net income from continuing operations
$7,535
$7,341
$7,665
$8,372
$5,329
                 
                 
Assets (in thousands of dollars)
         
 
Gross property, plant and equipment
$229,128
$216,903
$192,925
$172,068
$152,991
 
Net property, plant and equipment (2)
$166,846
$161,014
$131,466
$117,663
$104,266
 
Total assets (2)
$223,721
$222,229
$211,764
$166,958
$145,029
 
Capital expenditures (1)
$13,836
$26,293
$22,057
$21,365
$12,516
                 
                 
Capitalization (in thousands of dollars)
         
 
Stockholders' equity
$67,350
$67,517
$64,669
$60,714
$56,356
 
Long-term debt, net of current maturities
                73,408
                48,409
                50,921
                33,777
                37,597
 
Total capitalization
$140,758
$115,926
$115,590
$94,491
$93,953
                 
 
Current portion of long-term debt
$3,938
$2,686
$2,665
$2,665
$520
 
Short-term debt
                10,900
                42,100
                25,400
                23,000
                11,600
 
Total capitalization and short-term financing
$155,596
$160,712
$143,655
$120,156
$106,073
                 
                 
                 
 
(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) Statement of Financial Accounting Standard ("SFAS") 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001.
 
(3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.


 


- Page 12 -




For the Years Ended December 31,
2007
2006 (3)
2005
2004
2003
Common Stock Data and Ratios
         
 
Basic earnings per share from continuing operations (1)
$1.96
$1.78
$1.83
$1.68
$1.80
 
Diluted earnings per share from continuing operations (1)
$1.94
$1.76
$1.81
$1.64
$1.76
                 
 
Return on average equity from continuing operations (1)
11.5%
11.0%
13.2%
12.8%
14.4%
                 
 
Common equity / total capitalization
65.4%
61.0%
59.0%
54.1%
51.2%
 
Common equity / total capitalization and short-term financing
50.6%
51.1%
46.0%
51.3%
48.8%
                 
 
Book value per share
$17.64
$16.62
$14.41
$13.49
$12.89
                 
                 
 
Market price:
         
   
High
$37.250
$35.650
$35.780
$27.550
$26.700
   
Low
$28.000
$27.900
$23.600
$20.420
$18.400
   
Close
$31.850
$30.650
$30.800
$26.700
$26.050
                 
                 
 
Average number of shares outstanding
           6,743,041
           6,032,462
           5,836,463
           5,735,405
           5,610,592
 
Shares outstanding at year-end
           6,777,410
           6,688,084
           5,883,099
           5,778,976
           5,660,594
 
Registered common shareholders
                  1,920
                  1,978
                  2,026
                  2,026
                  2,069
                 
 
Cash dividends declared per share
$1.18
$1.16
$1.14
$1.12
$1.10
 
Dividend yield (annualized) (2)
3.7%
3.8%
3.7%
4.2%
4.2%
 
Payout ratio from continuing operations (1) (4)
60.2%
65.2%
62.3%
66.7%
61.1%
                 
                 
Additional Data
         
 
Customers
         
   
Natural gas distribution and transmission
                62,884
                59,132
                54,786
                50,878
                47,649
   
Propane distribution
                34,143
                33,282
                32,117
                34,888
                34,894
                 
                 
 
Volumes
         
   
Natural gas deliveries (in MMCF)
                34,820
                34,321
                34,981
                31,430
                29,375
   
Propane distribution (in thousands of gallons)
                29,785
                24,243
                26,178
                24,979
                25,147
                 
                 
 
Heating degree-days (Delmarva Peninsula)
         
   
Actual HDD
                  4,504
                  3,931
                  4,792
                  4,553
                  4,715
   
10 -year average HDD (normal)
                  4,376
                  4,372
                  4,436
                  4,389
                  4,409
                 
 
Propane bulk storage capacity (in thousands of gallons)
                  2,441
                  2,315
                  2,315
                  2,045
                  2,195
                 
 
Total employees (1)
445
437
423
426
439
                 
                 
 
(1) These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company
 
closed its distributed energy operation in 2007.  All assets of all of the water businesses were sold in 2004 and 2003.
 
(2) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then
 
dividing that amount by the closing common stock price at December 31.
   
 
(3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
 
(4) The payout ratio from continuing operations is calculated by dividing cash dividends declared per share
 
(for the year) by basic earnings per share from continuing operations.
   

 
- Page 13 -



 
For the Years Ended December 31,
2002
2001
2000
1999
1998
Common Stock Data and Ratios
         
 
Basic earnings per share from continuing operations (1)
$1.37
$1.37
$1.46
$1.63
$1.05
 
Diluted earnings per share from continuing operations (1)
$1.37
$1.35
$1.43
$1.59
$1.04
                 
 
Return on average equity from continuing operations (1)
11.2%
11.1%
12.2%
14.3%
9.7%
                 
 
Common equity / total capitalization
47.8%
58.2%
55.9%
64.3%
60.0%
 
Common equity / total capitalization and short-term financing
43.3%
42.0%
45.0%
50.5%
53.1%
                 
 
Book value per share
$12.16
$12.45
$12.21
$11.71
$11.06
                 
                 
 
Market price:
         
   
High
$21.990
$19.900
$18.875
$19.813
$20.500
   
Low
$16.500
$17.375
$16.250
$14.875
$16.500
   
Close
$18.300
$19.800
$18.625
$18.375
$18.313
                 
                 
 
Average number of shares outstanding
           5,489,424
           5,367,433
           5,249,439
           5,144,449
           5,060,328
 
Shares outstanding at year-end
           5,537,710
           5,424,962
           5,297,443
           5,186,546
           5,093,788
 
Registered common shareholders
                  2,130
                  2,171
                  2,166
                  2,212
                  2,271
                 
 
Cash dividends declared per share
$1.10
$1.10
$1.07
$1.03
$1.00
 
Dividend yield (annualized) (2)
6.0%
5.6%
5.8%
5.7%
5.5%
 
Payout ratio from continuing operations (1) (4)
80.3%
80.3%
73.3%
63.2%
95.2%
                 
                 
Additional Data
         
 
Customers
         
   
Natural gas distribution and transmission
                45,133
                42,741
                40,854
                39,029
                37,128
   
Propane distribution
                34,566
                35,530
                35,563
                35,267
                34,113
                 
                 
 
Volumes
         
   
Natural gas deliveries (in MMCF)
                27,935
                27,264
                30,830
                27,383
                21,400
   
Propane distribution (in thousands of gallons)
                21,185
                23,080
                28,469
                27,788
                25,979
                 
                 
 
Heating degree-days (Delmarva Peninsula)
         
   
Actual HDD
                  4,161
                  4,368
                  4,730
                  4,082
                  3,704
   
10 -year average HDD (normal)
                  4,393
                  4,446
                  4,356
                  4,409
                  4,493
                 
 
Propane bulk storage capacity (in thousands of gallons)
                  2,151
                  1,958
                  1,928
                  1,926
                  1,890
                 
 
Total employees (1)
455
458
471
466
431
                 
                 
 
(1) These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company
 
closed its distributed energy operation in 2007.  All assets of all of the water businesses were sold in 2004 and 2003.
 
(2) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then
 
dividing that amount by the closing common stock price at December 31.
   
 
(3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
 
(4) The payout ratio from continuing operations is calculated by dividing cash dividends declared per share
 
(for the year) by basic earnings per share from continuing operations.
   



 
 

 
 


- Page 14 -

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

INTRODUCTION
 
 
This section provides management’s discussion of Chesapeake Utilities Corporation and its consolidated subsidiaries, with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, 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 OVERVIEW
 
Chesapeake is a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses.

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

·  
executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital;
·  
expanding the natural gas distribution and transmission business through expansion into new geographic areas in our current service territories;
·  
expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities;
·  
utilizing the Company’s expertise across our various businesses to improve overall performance;
·  
enhancing marketing channels to attract new customers;
·  
providing reliable and responsive customer service to retain existing customers;
·  
maintaining a capital structure that enables the Company to access capital as needed; and
·  
maintaining a consistent and competitive dividend for shareholders.

In 2007, net income increased 26 percent as the Company earned $13.2 million in net income, or $1.94 per share (diluted), when compared to the net income of $10.5 million, or $1.72 per share (diluted), earned in 2006.  Overall, operating income in 2007 increased $4.8 million, or 20 percent, from 2006. The increase in operating income was partially offset by an increase of $816,000, or 14 percent, in interest expense and higher income taxes of $1.6 million, or 23 percent.

The following discussions and those later in the document on operating income and segment results include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost for natural gas and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with Generally Accepted Accounting Principles (“GAAP”). Chesapeake believes 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 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.

Operating Income
A strong year-over-year increase in operating income for 2007 was attained from the Company’s natural gas, propane, and advanced information services business segments.
 

               
           
Percentage
 
(In thousands)
2007
2006
Change
   
Change
 
Natural gas
$22,485
 $19,733
 $2,752
   
 14%
Propane
4,498
2,534
1,964
   
 78%
Advanced information services
836
767
69
   
 9%
Other & eliminations
295
298
(3)
   
 -1%
Total operating income
 $28,114
 $23,332
 $4,782
   
  100%     
 

The natural gas segment benefited from the additional transportation capacity contracts implemented by Eastern Shore, continued customer growth from the distribution operations, rate increases, and the impact of colder temperatures on the Delmarva Peninsula that were 15 percent colder in 2007 than in 2006.  The propane segment benefited from the colder temperatures on the Delmarva Peninsula and also from the volatility in wholesale propane prices experienced in 2007.

Key financial and operational highlights for fiscal year 2007 include the following:

·  
New transportation capacity contracts implemented by Eastern Shore in November 2006 provided for 26,200 Dts of firm transportation capacity per day and contributed $3.1 million of additional gross margin in 2007.
 

·  
On August 11, 2007, Eastern Shore received authorization from the FERC to commence construction of a portion of the Phase II facilities (approximately 4 miles) of the 2006-2008 Expansion Project.  These additional facilities, which were completed and placed in service on November 1, 2007 provide for 8,300 Dts of additional firm capacity per day generating annualized gross margin of $1.2 million.
 

·  
The base rate increase that the Company received from the Maryland PSC on September 26, 2006, for our Maryland natural gas operations, contributed $693,000 of additional gross margin in 2007.
 
- Page 15 -


·  
Effective September 1, 2007, the FERC authorized Eastern Shore to commence the billing of increased rates agreed to in a settlement with its customers, which the FERC formally approved in January 2008.  These increased rates provided for an additional $563,000 of gross margin in 2007.
 

·  
On August 21, 2007, the Delaware PSC authorized the Company to implement temporary rates with its customers, subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC.
 
 
·  
Customer growth in the natural gas and propane businesses remained strong, with the Delmarva and Florida natural gas distribution operations registering seven and five percent increases in residential customers, respectively, and the Delmarva Community Gas Systems (“CGS”) generating a 22 percent increase in propane distribution customers.

 
·  
For the year ended December 31, 2007, the Company generated $25.7 million in operating cash attributed to net income of $13.2 million and $12.5 million in net cash from other operating activities, which includes $9.1 million in depreciation and amortization.
 

·  
The Company continued to invest in property, plant and equipment to support current and future growth opportunities and utilized $31.3 million of cash in 2007 for such expenditures.
 

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

Critical Accounting Policies
 
Chesapeake prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“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 its estimates on historical experience and on various other 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.  Most of Chesapeake’s businesses are regulated, accordingly, the accounting methods used by these businesses must comply with the requirements of the regulatory bodies; therefore, 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’s Audit Committee.

Regulatory Assets and Liabilities
As a result of the ratemaking process, Chesapeake records certain assets and liabilities in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71 “Accounting for the Effects of Certain Types of Regulation,” and consequently, the accounting principles applied by our regulated utilities 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 A to the Consolidated Financial Statements, Chesapeake had recorded regulatory assets of $4.1 million and regulatory liabilities of $27.7 million, at December 31, 2007. If the Company were required to terminate application of SFAS No. 71, it 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 adverse effect on the Company’s results of operations.

Valuation of Environmental Assets and Liabilities
As more fully described in Note M to the Financial Statements, Chesapeake has completed its responsibilities related to one environmental site and is currently participating in the investigation, assessment or remediation of three 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 Environmental Protection Agency (“EPA”) or applicable state environmental authority may not have selected the final remediation methods. In addition, there is uncertainty with regard to amounts that may be recovered from other potentially responsible parties.

Since the Company’s management believes that recovery of these expenditures, including any litigation costs, is probable through the regulatory process, the Company has recorded, in accordance with SFAS 71, a regulatory asset and corresponding regulatory liability.   At December 31, 2007, Chesapeake had recorded an environmental regulatory asset of $851,000 and a regulatory liability of $227,000 for over-collections and an additional liability of $835,000 for environmental costs.

Derivatives
Chesapeake may use derivative instruments to manage the price risk of its natural gas and propane purchasing activities. The use of these instruments is subject to the Company’s risk management policies, which are continually monitored for compliance. Derivative instruments utilized in connection with these activities and services are accounted in accordance with SFAS 133, Accounting for Derivative Instruments and Hedging Activities, under which Chesapeake either records the fair value of derivatives held as assets and liabilities.  If the derivative contracts meets the “normal purchase and normal sale” scope exception of SFAS 133, the related activities and services are accounted on an accrual basis of accounting.

The following is a review of Chesapeake’s derivative activity at December 31, 2007 and 2006:

·  
The natural gas distribution and marketing operations entered into physical contracts for the purchase and sale of natural gas. These physical contracts qualify for the “normal purchases and normal sales” scope exception under SFAS 133 at December 31, 2007 and 2006 in that they provide for the purchase or sale of natural gas that will 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, they are not subject to the accounting requirements of SFAS No. 133.

·  
During 2007 and 2006, Chesapeake’s propane distribution operations entered into physical contracts to buy propane supplies. These contracts qualify for the “normal purchases and normal sales” scope exception under SFAS 133 in that they provide for the purchase or sale of propane that will 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 are recorded when title to the underlying commodity passes.

During 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on our price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At the end of the period, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss in 2006 of $84,000.  The Company did not enter into a similar swap agreement in 2007.

·  
Chesapeake’s propane wholesale marketing operation enters into forward and futures contracts that are considered derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In accordance with that pronouncement, open positions are marked to market prices at the end of each reporting period and unrealized gains or losses are recorded in the Consolidated Statement of Income as revenue. The contracts all mature within one year and are almost exclusively for propane commodities, with delivery points of Mt. Belvieu, Texas; Conway, Kansas; and Hattiesburg, Mississippi. Management estimates the market valuation based on references to exchange-traded futures prices, historical differentials and actual trading activity at the end of the reporting period. At December 31, 2007, these contracts had net unrealized gains of $179,000 that were recorded in the financial statements. At December 31, 2006, these contracts had net unrealized gains of $8,500 that were recorded in the financial statements.  Commodity price volatility may have a significant impact on the gain or loss in any given period.

- Page 16 -

Operating Revenues
Revenues for the natural gas 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. However, the regulatory authorities have granted the Company’s 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 can negotiate rates above or below the FERC-approved tariff rates.

For regulated deliveries of natural gas, Chesapeake reads meters and bills customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accrues unbilled revenues for gas that has 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, Chesapeake must estimate the amount of gas that has not been accounted for on its delivery system 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.
 
The propane wholesale marketing operation records trading activity, on a net mark-to-market basis in the Company’s income statement, for open contracts. The propane distribution, advanced information services and other segments record revenue in the period the products are delivered and/or services are rendered.

Chesapeake’s natural gas distribution operations in Delaware and Maryland each have a purchased gas cost recovery mechanism.  This mechanism provides the Company with a method of adjusting the billing rates with its customers for changes in the cost of purchased gas included in base rates. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

The Company charges flexible rates to the natural gas distribution’s industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative fuels. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.
 
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 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 prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.


Results of Operations
 
 
Net Income & Diluted Earnings Per Share Summary
                   
               
Increase
               
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Net Income *
                                   
Continuing operations
  $ 13,218     $ 10,748     $ 2,470     $ 10,748     $ 10,699     $ 49  
Discontinued operations
    (20 )     (241 )     221       (241 )     (231 )     (10 )
Total Net Income
  $ 13,198     $ 10,507     $ 2,691     $ 10,507     $ 10,468     $ 39  
                                                 
Diluted Earnings (Loss) Per Share
                                         
Continuing operations
  $ 1.94     $ 1.76     $ 0.18     $ 1.76     $ 1.81     $ (0.05 )
Discontinued operations
    -       (0.04 )     0.04       (0.04 )     (0.04 )     -  
Total Earnings Per Share
  $ 1.94     $ 1.72     $ 0.22     $ 1.72     $ 1.77     $ (0.05 )
* Dollars in thousands.
                                               
 

The Company’s net income from continuing operations increased $2.5 million in 2007 when compared to 2006. Net income from continuing operations was $13.22 million, or $1.94 per share (diluted), for 2007, compared to a net income from continuing operations of $10.75 million, or $1.76 per share (diluted) in 2006.

The Company’s net income from continuing operations increased $49,000 in 2006 when compared to 2005. Net income from continuing operations was $10.75 million, or $1.76 per share (diluted), for 2006, compared to a net income from continuing operations of $10.70 million, or $1.81 per share (diluted) in 2005.
 
During 2007, Chesapeake decided to close its distributed energy services company, Chesapkeake OnSight Services, LLC (“OnSight”), which consistently experienced operating losses since 2004.  At December 31, 2007, the results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented.  For 2007, the discontinued operations experienced a net loss of $20,000 compared to a net loss of $241,000, or $0.04 per share (diluted), for 2006 and a net loss of $231,000, or $0.04 per share (diluted), for 2005.
 

Operating Income Summary (in thousands)
                         
               
Increase
               
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Business Segment:
                                   
Natural gas
  $ 22,485     $ 19,733     $ 2,752     $ 19,733     $ 17,236     $ 2,497  
Propane
    4,498       2,534       1,964       2,534       3,209       (675 )
Advanced information services
    836       767       69       767       1,197       (430 )
Other & eliminations
    295       298       (3 )     298       279       19  
Operating Income
  $ 28,114     $ 23,332     $ 4,782     $ 23,332     $ 21,921     $ 1,411  
                                                 
Other Income
    291       189       102       189       383       (194 )
Interest Charges
    6,590       5,774       816       5,774       5,132       642  
Income Taxes
    8,597       6,999       1,598       6,999       6,472       527  
Net Income from Continuing Operations
  $ 13,218     $ 10,748     $ 2,470     $ 10,748     $ 10,700     $ 48  
 
 
- Page 17 -

2007 Compared to 2006
Compared to 2006, operating income in 2007 increased by $4.8 million, or 20 percent.  Factors affecting this improvement included the following:

·  
New transportation capacity contracts implemented for the natural gas transmission operation in November 2006 and November 2007 provided for $3.3 million of additional gross margin in 2007.
·  
Weather on the Delmarva Peninsula was 15 percent colder in 2007 than 2006, which the Company estimates contributed approximately $2.0 million in additional 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.  The variance occurred as a result of the season 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, for the Delmarva and Florida natural gas distribution operations in 2007.
·  
The average gross margin per retail gallon sold to customers increased $0.05 in 2007 for the Delmarva propane distribution operations, which contributed $1.1 million to gross margins.
·  
The Delmarva Community Gas Systems continued to experience strong customer growth as the number of customers increased 22 percent in 2007 compared to 2006.
 
2006 Compared to 2005
Operating income in 2006 increased $1.4 million, or 6.5 percent, compared to 2005, despite significantly warmer weather in 2006. The improvement in 2006 results of operations compared to 2005 was affected by the following factors:

·  
Weather on the Delmarva Peninsula was 18 percent warmer in 2006 than in 2005; as a result, the Company estimates that 2006 gross margin for its Delmarva natural gas and propane distribution operations was approximately $3.4 million less than in 2005.
·  
Strong residential customer growth of nine percent and eight percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2006.
·  
The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent, due to additional capacity contracts that went into effect in November 2005 and November 2006.
·  
A 67 percent increase in the number of customers for the Company’s natural gas marketing operation.
·  
Gross margin for the Delmarva propane distribution operations decreased $834,000, primarily, as a result of the warmer weather in 2006.
·  
The Delmarva Community Gas Systems continued to experience strong customer growth increasing by 34 percent in 2006 compared to 2005.
·  
Operating income for the advanced information services segment decreased $430,000 in 2006. Although revenues from consulting increased $749,000 in 2006, the 2005 results contained $993,000 of operating income for the Lightweight Association Management Processing Systems (“LAMPSTM”) product, which was sold in the fourth quarter 2005.  The LAMPSTM product was an internally developed software that was developed and marketed specifically for REALTOR® Associations.
 
Natural Gas
The natural gas segment earned operating income of $22.5 million for 2007, $19.7 million for 2006, and $17.2 million for 2005, resulting in increases of $2.8 million, or 13.9 percent for 2007, and $2.5 million, or 14.5 percent, for 2006.
 

Natural Gas (in thousands)
                                   
               
Increase
               
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Revenue
  $ 181,202     $ 170,374     $ 10,828     $ 170,374     $ 166,582     $ 3,792  
Cost of gas
    121,550       117,948       3,602       117,948       116,178       1,770  
Gross margin
    59,652       52,426       7,226       52,426       50,404       2,022  
                                                 
Operations & maintenance
    26,024       22,673       3,351       22,673       23,874       (1,201 )
Depreciation & amortization
    6,918       6,312       606       6,312       5,682       630  
Other taxes
    4,225       3,708       517       3,708       3,612       96  
Other operating expenses
    37,167       32,693       4,474       32,693       33,168       (475 )
Total Operating Income
  $ 22,485     $ 19,733     $ 2,752     $ 19,733     $ 17,236     $ 2,497  
 
Heating Degree-Day (HDD) and Customer Analysis
                         
                   
Increase
                   
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Heating degree-day data — Delmarva
                                 
Actual HDD
    4,504       3,931       573       3,931       4,792       (861 )
10-year average HDD
    4,376       4,372       4       4,372       4,436       (64 )
                                                 
Estimated gross margin per HDD
  $ 1,937     $ 2,013     $ (76 )   $ 2,013     $ 2,234     $ (221 )
                                                 
Estimated dollars per residential customer added:
                         
Gross margin
  $ 372     $ 372     $ 0     $ 372     $ 372     $ 0  
Other operating expenses
  $ 106     $ 111     $ (5 )   $ 111     $ 106     $ 5  
                                                 
Average number of residential customers
                                 
Delmarva
    43,485       40,535       2,950       40,535       37,346       3,189  
Florida
    13,250       12,663       587       12,663       11,717       946  
Total
    56,735       53,198       3,537       53,198       49,063       4,135  
 
- Page 18 -


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 $4.5 million, or 14 percent, for 2007 compared to 2006. The gross margin increases of $3.9 million for the natural gas transmission operation, $3.4 million for the Delmarva natural gas distribution operations, and $88,000 for the Florida natural gas distribution operation 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 million, or 22 percent, in 2007 compared to 2006.  Of the $3.9 million increase, $3.3 million was attributable to new transportation capacity contracts implemented in November 2006 and 2007. In 2008, the new transportation capacity contracts implemented in November 2007 are expected to generate an additional annual gross margin of $1.2 million above 2007 gross margins.  In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $563,000 to gross margins in 2007.  A further discussion of the FERC rate proceeding is provided in detail within the “Regulatory Activities” listed later in this section.  The remaining $43,000 increase to gross margin in 2007 is attributable to other factors, such as higher interruptible sales.  An increase of $2.3 million in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

·  
Payroll and benefit costs increased by $282,000 and $90,000, respectively, as the operation increased its staffing levels to comply with new federal pipeline integrity regulations and to serve the additional growth.  The new pipeline integrity regulations require the Company to assess the integrity of each covered segment of its line pipe.  These regulations require the assessment of at least 50 percent of the covered segments by December 17, 2007 and completion of the baseline assessment of all covered segments by December 17, 2012.
·  
Eastern Shore also incurred an additional $385,000 of third-party costs in 2007 compared to 2006 to comply with the new federal pipeline integrity regulations previously discussed.
·  
The increased level of capital investment caused higher depreciation and asset removal costs of $371,000 and increased property taxes of $188,000.
·  
Corporate costs increased $568,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC.
·  
The increase in operating expenses for 2007 is magnified by the FERC’s authorization, in July 2006, to defer certain pre-service costs of Eastern Shore’s 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 “Regulatory Activities” discussion below for further information on the E3 Project.
·  
Other operating expenses relating to various items increased collectively by approximately $226,000.
 
Natural Gas Distribution
The Delmarva distribution operations experienced an increase in gross margin of $3.4 million, or 16 percent. The significant items contributing to the increase in gross margin include the following:

·  
Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 2,950, or seven percent, for 2007 compared to 2006, and the Company estimates that these additional residential customers contributed approximately $1.2 million to gross margin.  The Company does not expect to maintain the growth rate of residential customers, which it has experienced in the past few years.  The Company has seen a slow-down in the new housing market in 2007 as a result of unfavorable market conditions in the housing industry, which include: (a) increased new and resale home inventory levels, (b) decreased homebuyer demand due to lower consumer confidence in the overall housing market, (c) increased uncertainty in the overall mortgage market, and (d) increased underwriting standards.
·  
Rate increases for both the Delaware and Maryland divisions generated an additional $848,000 in gross margin in 2007 compared to 2006.  In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $693,000 period-over-period increase to gross margin in 2007.  The Delaware Division received approval from the Delaware PSC to implement temporary rates, subject to refund, which contributed an additional $155,000 to gross margin in 2007.
·  
The Company estimates that weather contributed $819,000 to gross margin in 2007 compared to 2006, as temperatures on the Delmarva Peninsula were 15 percent colder in 2007. This amount differs from the $1.1 million of additional gross margin that the Company had expected the colder weather to contribute.  This variance occurred as a result of the season or month that the heating degree day variance occurred.
·  
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 now includes a weather normalization adjustment (“WNA”) mechanism, which was implemented in October 2006 and is designed to protect a portion of the Company’s revenues against warmer-than-normal weather, as deviations from normal weather can affect our financial performance. The WNA also serves to offset the impact of colder-than-normal weather on our customers by reducing the amounts the Company can charge them during such periods.
·  
Growth in commercial and industrial customers contributed $224,000 and $102,000, respectively, to gross margin in 2007 compared to 2006.
·  
Increased sales volumes to interruptible customers contributed $224,000 to gross margin in 2007 compared to 2006.
·  
The remaining $31,000 increase in gross margin can be attributed to various 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 attributable to the same unfavorable housing market conditions previously discussed.
 
Other operating expense for the natural gas distribution operations increased by $2.0 million in 2007 compared 2006. Among the key components of the increase were the following:

·  
Payroll costs increased by $110,000 as vacant positions in 2006 were filled in 2007 and additional positions were added to serve the growth experienced by the operations.
·  
Health care costs increased by $177,000 as a result of the additional personnel and a higher cost of claims in 2007 compared to 2006.
·  
Incentive compensation increased $229,000 in 2007 as the Delmarva operations experienced improved earnings and increased staffing levels.
·  
Depreciation and amortization expense, asset removal cost and property taxes increased by $316,000, $121,000 and $156,000, respectively, as a result of the Company’s continued capital investments.
·  
The Florida distribution operation experienced an increased expense of $227,000 in 2007 compared with 2006 to maintain compliance with the new federal pipeline integrity regulations.
·  
Sales and advertising costs increased $129,000 in 2007 compared to 2006, primarily to promote energy conservation and customer awareness of the availability of natural gas service.
·  
Regulatory expenses increased $113,000 as the Delaware and Maryland operations began expensing costs associated with their respective rate cases.
·  
The allowance for uncollectible accounts increased $183,000 in 2007 compared to 2006 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 items increased by approximately $355,000.

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 of increases in natural gas supply costs that the Company was contractually unable to pass through to its customers.  In addition, a shift in the market prevented the Company 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 primarily due 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.
 
 
2006 Compared to 2005
Gross margin for the Company’s natural gas segment increased $2.0 million, or 4 percent, and other operating expenses decreased $475,000, or 1 percent, in 2006 compared to 2005. The gross margin increases of $1.8 million for the natural gas transmission operation, $395,000 for the Florida natural gas distribution operation and $75,000 for the natural gas marketing operation were partially offset by a lower gross margin of $210,000 for the Delmarva natural gas distribution operations.

Natural Gas Transmission
The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent. Of the $1.8 million increase, $1.1 million was attributable to new transportation capacity contracts implemented in November 2005 and $612,000 due to new transportation capacity contracts implemented in November 2006.  An increase of $416,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses are as follow:

- Page 19 -

·  
Payroll costs and incentive compensation increased $108,000 to serve the additional growth experienced by the operation.
·  
Depreciation and asset removal costs increased by $558,000 and property taxes by $109,000 due to an increase in the level of capital investment.
·  
As a result of the operation receiving approval from the FERC to recover certain pre-service costs associated with the E3 Project, the Company deferred $188,000 of costs previously incurred and expensed in 2005.  As a result of this deferral, the amounts recognized in the Company’s income statement declined from 2005 by $376,000. Please refer to the “Regulatory Activities” discussion for further information on this expansion project.
·  
Other operating expenses relating to various other items increased by approximately $17,000.
 
Natural Gas Distribution
Gross margin for the Florida distribution operation increased by $395,000 in 2006 compared to 2005. An eight percent growth in residential customers contributed $230,000 of this increase in gross margin. In addition to residential customer growth, new commercial and industrial customers contributed $91,000 to gross margin in 2006. The remaining $74,000 increase in gross margin is attributed to various factors, including turn-on revenue.

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

Other operating expense for the natural gas distribution operations decreased $814,000 in 2006 compared to 2005. Some of the significant components of the decrease in other operating expenses in 2006, compared to 2005, include the following:

·  
Health care costs decreased by $313,000 as a result of the Company changing health care service providers in November 2005 and experiencing lower costs related to claims.
·  
Allowance for uncollectible accounts decreased by $289,000 in 2006 compared to 2005 due to increased collection efforts and lower revenues resulting from lower prices and warmer temperatures.
·  
Incentive compensation decreased by $177,000 in 2006, reflecting lower than expected earnings.
·  
Corporate costs were reduced by $407,000 due to lower payroll and related expenses.
·  
Depreciation and amortization expense and asset removal cost increased by $132,000 and $186,000, respectively, as a result of the Company’s continued capital investments.
·  
Merchant payment fees increased by $136,000 in 2006 compared to 2005 as the Company experienced more customers making payments with the use of credit cards.
·  
In addition, other operating expenses relating to various minor items increased by approximately $55,000.

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

Propane
The propane segment experienced an increase of $2.0 million, or 78 percent, in operating income in 2007 compared to 2006.  Gross margin increased $4.0 million, which was partially offset by an increase in other operating expenses of $2.0 million.  During 2006, operating income for the propane segment decreased by $675,000, or 21 percent, compared to 2005, reflecting a gross margin decrease of $1.1 million, which was partially offset by a decrease in operating expenses of $464,000.

 
Propane (in thousands)
                                   
               
Increase
               
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Revenue
  $ 62,838     $ 48,576     $ 14,262     $ 48,576     $ 48,976     $ (400 )
Cost of sales
    41,038       30,780       10,258       30,780       30,041       739  
Gross margin
    21,800       17,796       4,004       17,796       18,935       (1,139 )
                                                 
Operations & maintenance
    14,594       12,823       1,771       12,823       13,355       (532 )
Depreciation & amortization
    1,842       1,659       183       1,659       1,574       85  
Other taxes
    866       780       86       780       797       (17 )
Other operating expenses
    17,302       15,262       2,040       15,262       15,726       (464 )
Total Operating Income
  $ 4,498     $ 2,534     $ 1,964     $ 2,534     $ 3,209     $ (675 )
 
Propane Heating Degree-Day (HDD) Analysis — Delmarva
                 
                   
Increase
                   
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Heating degree-days
                                               
Actual
    4,504       3,931       573       3,931       4,792       (861 )
10-year average
    4,376       4,372       4       4,372       4,436       (64 )
                                                 
Estimated gross margin per HDD
  $ 1,974     $ 1,743     $ 231     $ 1,743     $ 1,743     $ 0  
 

2007 Compared to 2006
Operating income for the propane segment increased 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, primarily due to increases in 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.

- Page 20 -

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 are greater than the Company’s average inventory price per gallon. This trend reverses when market prices decrease and move closer to the Company’s 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 margin for the Delmarva propane distribution operation 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. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide an additional 7,700 CGS customers, an increase of 145 percent.  With the slowdown in the housing market, however, the Company is unable to predict when construction of systems currently under contract will be completed and in service.
·  
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 compared to 2006.
·  
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.
·  
Incentive compensation increased by $361,000 as a result of the improved operating results in 2007 compared to 2006.
·  
Health care costs increased by $119,000 during 2007 compared to the same period in 2006 as the Company experienced a higher cost of claims during the year.
·  
The operation incurred an additional $233,000 expense in 2007 for propane tank recertifications and maintenance to maintain compliance with Department of Transportation (“DOT”) standards.  The DOT standards require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years after that.
·  
Mains fees increased by $100,000 in 2007 compared to 2006 as a result of added CGS customers.  This expenditure will continue to increase as more CGS customers are added.
·  
Depreciation and amortization expense increased by $107,000 over the prior year as a result of the Company’s increased capital investments.
·  
In addition, other operating expenses relating to various items increased collectively by approximately $193,000.

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, increased by $223,000, primarily due to increases in payroll costs, insurance and depreciation expense.
 
Propane Wholesale and Marketing
Gross margin for the Company’s propane wholesale marketing operation increased by $677,000, or 40 percent, in 2007 compared to 2006. This increase reflects the larger number of market opportunities that arose in 2007, due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in 2006. The increase in gross margin was partially offset by higher other operating expenses of $318,000, due primarily to higher incentive compensation based on the increased earnings in 2007.

2006 Compared to 2005
Operating income for the propane segment decreased $675,000, or 21 percent, to $2.5 million for 2006 compared to 2005. This decrease was due primarily to warmer weather on the Delmarva Peninsula in 2006, which resulted in reduced customer consumption. Gross margin in the Delmarva propane distribution operations was $834,000 lower than in 2005, primarily due to warmer weather in 2006. Gross margin also decreased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $146,000 and $159,000, respectively.

Delmarva Propane Distribution
The Delmarva propane distribution operation’s decrease in gross margin of $834,000 resulted from the following factors:

·  
Volumes sold in 2006 decreased 1.9 million gallons, or eight percent, due primarily to 18 percent warmer temperatures on the Delmarva Peninsula in 2006 than in 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.7 million when compared to 2005.
·  
Gross margin increased by $956,000 due to an increase of three cents in the average gross margin per retail gallon in 2006 compared to 2005.
·  
Gross margin for the Delmarva CGS activities increased by $155,000 compared to 2005 due primarily to an increase in the average number of customers, which grew by approximately 1,000 to a total count of approximately 3,900, or a 34 percent increase, compared to 2005.
·  
Gross margin was adversely affected by a $272,000 write-down of propane inventory, reflecting the lower of cost or market.
·  
The remaining gross margin decrease of $29,000 was attributable primarily to customer conservation and changes in the timing of deliveries to customers.
 
Other operating expenses decreased by $335,000 for the Delmarva operations in 2006 compared to 2005. The significant factors contributing to the decrease included:

·  
The Company recovered $387,000 in fixed costs from one of its propane suppliers in response to a propane contamination incident that occurred in a previous period when approximately 75,000 gallons of propane that the Company purchased from the supplier contained above-normal levels of petroleum byproducts.
·  
Health care costs decreased by $324,000. The Company changed health care service providers in November 2005 and subsequently experienced lower costs related to claims.
·  
In addition, there was a decrease of approximately $39,000 in other operating expenses relating to various minor items.
·  
These lower costs were partially offset by increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, increased payroll costs of $165,000 and higher costs of $74,000 associated with vehicle fuel.
 
Florida Propane Distribution
In 2006, the Florida propane distribution operation experienced a decrease in gross margin of $146,000, or 12 percent, when compared to 2005. The lower gross margin reflected a decrease of $208,000 for in-house piping sales as the operation exited the house piping service, which was partially offset by an increase in gross margin of $62,000 from propane sales due primarily to an increase in the average gross margin per retail gallon, partially offset by a one percent decrease in the volumes sold in 2006. The Florida propane operation experienced a decrease of $49,000 in other operating expenses in 2006 compared to 2005, attributable to lower payroll and benefits costs related to vacant positions during the year, partially offset by higher expenses related to leak testing and depreciation expense.
 

Propane Wholesale and Marketing
Gross margin for the Company’s propane wholesale marketing operation decreased by $159,000 in 2006 compared to 2005. This decrease from the 2005 results reflects the increased market opportunities that arose in 2005 due to the extreme price volatility in the propane wholesale market following the hurricanes in the Gulf of Mexico area, but did not extend into 2006. The decrease in gross margin was partially offset by lower other operating expenses of $79,000 attributed primarily to lower incentive compensation as a result of lower earnings in 2006.
 
- Page 21 -

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 $836,000 for 2007, $767,000 for 2006, and $1.2 million for 2005.

 
Advanced Information Services (in thousands)
                         
               
Increase
               
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Revenue
  $ 15,099     $ 12,568     $ 2,531     $ 12,568     $ 14,140     $ (1,572 )
Cost of sales
    8,260       7,082       1,178       7,082       7,181       (99 )
Gross margin
    6,839       5,486       1,353       5,486       6,959       (1,473 )
                                                 
Operations & maintenance
    5,225       4,119       1,106       4,119       5,129       (1,010 )
Depreciation & amortization
    144       113       31       113       123       (10 )
Other taxes
    634       487       147       487       510       (23 )
Other operating expenses
    6,003       4,719       1,284       4,719       5,762       (1,043 )
Total Operating Income
  $ 836     $ 767     $ 69     $ 767     $ 1,197     $ (430 )


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.

The period-over-period increase of gross margin resulted primarily from:

·  
A strong demand for the segment’s consulting services in 2007 generated an increase of $1.9 million in consulting revenues as the number of billable hours increased by 15 percent; and
·  
An increase of $276,000 from Managed Database Administration (“MDBA”) services, first offered in the first quarter of 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock.

Other operating expenses increased by $1.3 million to $6.0 million in 2007, compared to $4.7 million for 2006. This increase in operating expenses in 2007 is attributable to the following:
·  
Payroll, incentive compensation and commissions, payroll taxes, benefit claims, and consulting expense accounted for $937,000 of the period-over-period 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 allowance for uncollectible accounts of $223,000 associated with a customer in the mortgage lending business that had filed for bankruptcy in the third quarter of 2007.
·  
In addition, other operating expenses relating to various minor items increased by approximately $140,000.
 
2006 Compared to 2005
Operating income for the advanced information services segment decreased by $430,000 to $767,000 for 2006 compared to $1.2 million in 2005. The greater operating income in 2005 included $993,000 for the LAMPS™ product, which in turn included a $924,000 pre-tax gain on the sale of the product in October 2005 to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc.

Revenues for the period decreased $1.6 million compared to 2005, due primarily to elimination of $1.9 million of revenue generated by the LAMPSTM product in 2005. Consulting revenues increased $749,000 in 2006 compared to 2005, primarily from offering MDBA services to its customers in 2006, which accounted for $740,000 of the increase, and an increase of 7.6 percent in the average hourly billing rate, while the number of billable hours remained at the same level attained in 2005.  Partially offsetting the increase in consulting revenues were decreases of $128,000 in training and product sales and $244,000 in other revenues.

Cost of sales for 2006 decreased by $99,000 to $7.08 million, compared to the 2005 cost of sales of $7.18 million, which included $401,000 related to LAMPSTM. After deducting the 2005 cost of sales associated with the LAMPSTM product, cost of sales increased in 2006 compared to 2005 to support the higher 2006 revenues.
 
Other operating expenses decreased $1.0 million in 2006 to $4.7 million compared to 2005. The reduction in expenses primarily reflects expenses of $554,000 in 2005 associated with LAMPSTM and lower benefits costs, rent expense and consulting costs.


Other Operations and Eliminations
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 $295,000 for 2007, $298,000 for 2006, and $279,000 for 2005.
 

Other Operations & Eliminations (in thousands)
                   
               
Increase
               
Increase
 
For the Years Ended December 31,
 
2007
   
2006
   
(decrease)
   
2006
   
2005
   
(decrease)
 
Revenue
  $ 622     $ 618     $ 4     $ 618     $ 618     $ 0  
Cost of sales
    -       -       -       -       -       -  
Gross margin
    622       618       4       618       618       -  
                                                 
Operations & maintenance
    109       96       13       96       67       29  
Depreciation & amortization
    160       163       (3 )     163       220       (57 )
Other taxes
    62       65       (3 )     65       81       (16 )
Other operating expenses
    331       324       7       324       368       (44 )
                                                 
Operating Income — Other
  $ 291     $ 294     $ (3 )   $ 294     $ 250     $ 44  
Operating Income — Eliminations
  $ 4       4     $ 0     $ 4       29     $ (25 )
Total Operating Income
  $ 295       298     $ (3 )   $ 298       279     $ 19  

- Page 22 -

Other Income
Other income for the years 2007, 2006, and 2005, respectively, was $291,000, $189,000, and $383,000, which include interest income, late fees charged to customers and gains or losses from the sale of assets.

 
Interest Expense
Total interest expense for 2007 increased approximately $816,000, or 14 percent, compared to 2006. The higher interest expense was a result of the following developments:

·  
As the 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 the average long-term debt balance was the result of a debt placement of $20 million in Senior Notes (“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).
·  
The average short-term borrowing balance decreased by $6.3 million in 2007 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.

Total interest expense for 2006 increased approximately $642,000, or 12.5 percent, compared to 2005. The increase reflected the following:

·  
Average short-term debt balance and short-term interest rates both increased in 2006 compared to 2005. The average short-term borrowing balance increased by $21.2 million in 2006 to $26.9 million compared to $5.7 million in 2005 primarily to finance the $39.3 million of net property, plant, and equipment added in 2006.
·  
The weighted average interest rate for short-term borrowing increased from 4.47 percent for 2005 to 5.47 percent for 2006.
·  
The average long-term debt balance during 2006 was $67.2 million with a weighted average interest rate of 6.98 percent, compared to $67.4 million with a weighted average interest rate of 7.18 percent for 2005. The Company also capitalized $586,000 of interest as part of capital project costs during 2006.
 
Income Taxes
Income tax expense for 2007 was $8.6 million compared to $7.0 million for 2006. Income taxes increased in 2007 compared to 2006, due primarily to increased taxable income and income taxes increased in 2006 compared to 2005, again due to increased taxable income. The effective federal income tax rate for each of the three years 2007, 2006 and 2005 was 35 percent and the Company realized a benefit of $226,000, $220,000, and $223,000 in those years, respectively, resulting from a change in the tax law allowing tax deductions for dividends paid on Company stock held in Employee Stock Ownership Plans (“ESOP”).

Discontinued Operations
During the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services company, Chesapeake OnSight Services, LLC (“OnSight”), which experienced operating losses since its inception in 2004.  OnSight was previously reported as part of the Company’s Other Operations business segment.  At December 31, 2007, 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 net losses of $20,000 for 2007, $241,000 for 2006 and $231,000 for 2005.


Liquidity and Capital Resources
Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to investment in new plant and equipment and retirement of outstanding debt. The Company relies on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures. 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.

During 2006, net cash provided by operating activities was $30.1 million, cash used by investing activities was $48.9 million, and cash provided by financing activities was $20.7 million.
 
The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of December 31, 2007, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $90.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Three of the bank lines, totaling $25.0 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, 2007 and 2006 was $45.7 million and $27.6 million, respectively.  The level of short-term debt was reduced in 2006 with funds provided from the placement of $20 million of 5.5 percent Senior Notes in October 2006 and from the proceeds of the issuance of 600,300 shares of common stock in November 2006.

Chesapeake has budgeted $37.5 million for capital expenditures during 2008. This amount includes $17.0 million for natural gas distribution, $13.3 million for natural gas transmission, $5.9 million for propane distribution and wholesale marketing, $290,000 for advanced information services and $887,000 for other operations. The natural gas distribution and transmission expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth, to acquire land for a future bulk storage facility, and to replace equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other category includes general plant, computer software and hardware.  The Company expects to fund the 2008 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 opportunities, acquisition opportunities and availability of capital.
 
Capital Structure
The following presents our capitalization as of December 31, 2007 and 2006:


   
December 31,
 
   
2007
   
2006
 
   
(In thousands, except percentages)
 
                         
Long-term debt, net of current maturities
  $ 63,256       35 %   $ 71,050       39 %
Stockholders' equity
  $ 119,576       65 %   $ 111,152       61 %
Total capitalization, excluding short-term debt
  $ 182,832       100 %   $ 182,202       100 %

 
- Page 23 -

As of December 31, 2007, common equity represented 65 percent of total capitalization, compared to 61 percent at December 31, 2006.

The following presents our capitalization as of December 31, 2007 and 2006, if short-term borrowing and the current portion of long-term debt were included in capitalization:
 

   
December 31,
 
   
2007
   
2006
 
   
(In thousands, except percentages)
 
                         
Short-term debt
  $ 45,664       19 %   $ 27,554       13 %
Long-term debt, including current maturities
  $ 70,912       30 %   $ 78,706       36 %
Stockholders' equity
  $ 119,576       51 %   $ 111,152       51 %
Total capitalization, including short-term debt
  $ 236,152       100 %   $ 217,412       100 %
 
If short-term borrowing and the current portion of long-term debt were included in capitalization, total capitalization increased by $18.7 million in 2007 compared to 2006. The increased capitalization was primarily used to fund a portion of the $31.3 million of net property, plant, and equipment added in 2007 and for other general working capital. In addition, if short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 51 percent at both December 31, 2007 and 2006.

Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as 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 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. The net proceeds from the sale were used for general corporate purposes, including financing of capital expenditures, repayment of short-term debt, and funding working capital requirements. At December 31, 2007 and 2006, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided by Operating Activities
Our cash flows provided by (used in) operating activities were as follows:

 
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
Net income
  $ 13,197,710     $ 10,506,525     $ 10,467,614  
Non-cash adjustments to net income
    15,554,639       11,186,418       13,059,678  
Changes in working capital
    (3,070,465 )     8,424,055       (9,927,351 )
Net cash from operating activties
  $ 25,681,884     $ 30,116,998     $ 13,599,941  
 
 Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income and working capital. Changes in working capital are determined by a variety of factors, including weather, the price of natural gas and propane, the timing of customer collections, payments of natural gas and propane purchases, and deferred gas cost recoveries.

The Company generates a large portion of its annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered by our Delmarva natural gas and propane distribution operations to our customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

In 2007, our 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.

- Page 24 -

In 2006, our net cash flow provided by operating activities was $30.1 million, an increase of $16.5 million over 2005. This increase was primarily a result of the recovery during 2006 of working capital that was deployed in 2005 due to significantly higher commodity prices and the amount of working capital required for operations. Also, contributing to this increase was a reduction of $6.1 million in natural gas and propane purchased for inventory as a result of mild weather in the prior heating season and therefore higher inventory balances for the current heating season.
 
Cash Flows Used in Investing Activities
Net cash flows used in investing activities totaled $31.3 million, $48.9 million and $33.1 million during fiscal years 2007, 2006, and 2005, respectively.

·  
Cash utilized for capital expenditures was $31.3 million, $48.9 million and $33.3 million for 2007, 2006, and 2005, respectively. Additions to property, plant and equipment in 2007 were primarily for natural gas transmission ($9.2 million), natural gas distribution ($15.2 million), propane distribution ($5.2 million), and other operations ($1.7 million).  In both 2007 and 2006, 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.
·  
Sales of property, plant, and equipment generated $205,000 of cash in 2007.
·  
The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in 2007 and 2006 by $228,000 and $16,000, respectively; in 2005, the Company recovered from its customers $240,000 in excess of its environmental expenditures for the period.


Cash Flows Provided by Financing Activities
Cash flows provided by financing activities totaled $3.7 million during 2007, $20.7 million during 2006, and $20.4 million during 2005. Significant financing activities included the following:

·  
During 2007 and 2005, net borrowing of short-term debt increased by $18.7 million and $29.6 million, respectively, primarily to support our capital investments.  During 2006, the Company reduced it short-term debt by $8.0 million.
 
·  
The Company repaid $7.7 million of long-term debt during 2007 compared with $4.9 million during 2006 and $4.8 million during 2005.
 
·  
During 2007, the Company paid $7.0 million in cash dividends compared with dividend payments of $6.0 million and $5.8 million for 2006 and 2005, respectively. The increase in 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.
 
·  
In November 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, pursuant to a shelf registration statement declared effective in November 2006, generating net proceeds of $19.7 million.
 
·  
In October 2006, the Company placed $20.0 million of 5.5 percent Senior Notes (“Notes”) to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).
 
·  
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.
 

 
- Page 25 -

 


Contractual Obligations
 
We have the following contractual obligations and other commercial commitments as of December 31, 2007:
   
Payments Due by Period
Contractual Obligations
 
Less than 1 year
   
1 - 3 years
   
3 - 5 years
   
More than 5 years
   
Total
 
Long-term debt (1)
  $ 7,656,364     $ 13,312,727     $ 14,474,545     $ 35,468,364     $ 70,912,000  
Operating leases (2)
    790,801       1,211,720       1,166,800       2,252,714       5,422,035  
Purchase obligations (3)
                                       
Transmission capacity
    9,302,772       20,794,882       6,266,171       21,339,713       57,703,538  
Storage — Natural Gas
    1,553,175       4,210,670       3,015,217       1,838,948       10,618,010  
Commodities
    13,907,762       63,515       -       -       13,971,277  
Forward purchase contracts  — Propane (4)
    41,781,709       -       -       -       41,781,709  
Unfunded benefits (5)
    308,552       628,143       645,350       1,945,895       3,527,940  
Funded benefits (6)
    73,939       133,864       119,852       1,572,844       1,900,499  
Total Contractual Obligations
  $ 75,375,074     $ 40,355,521     $ 25,687,935     $ 64,418,478     $ 205,837,008  
                                         
(1) Principal payments on long-term debt, see Note H, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item. The expected interest payments on long-term debt are $5.2 million, $8.8 million, $6.9 million and $10.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $ 30.9 million.
 
(2) See Note J, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
 
(3) See Note N, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information.
 
(4) The Company has also entered into forward sale contracts. See "Market Risk" of the Management's Discussion and Analysis for further information.
 
(5) The Company has recorded long-term liabilities of $4.2 million at December 31, 2006 for unfunded post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 65 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations.
 
(6) The Company has recorded long-term liabilities of $2.0 million at December 31, 2006 for funded benefits. These liabilities have been funded using a Rabbi Trust and an asset in the same amount is recorded under Investments on the Balance Sheet. The defined benefit pension plan was closed to new participants on January 1, 1999 and participants in the plan on that date were given the option to leave the plan. See Note K, "Employee Benefit Plans," in the Notes to the Consolidated Financial Statements for further information on the plan. Since the plan modification, no additional funding has been required from the Company and none is expected for the next five years, based on factors in effect at December 31, 2006. However, this is subject to change based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets.
 
 
Off-Balance Sheet Arrangements
The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event either subsidiary’s default. Neither of these subsidiaries has ever defaulted in 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, 2007 was $24.2 million, with the guarantees expiring on various dates in 2008.
 
In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2008. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies.  There have been no draws on this letter of credit as of December 31, 2007.

Regulatory Activities
The Company’s natural gas distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs; Eastern Shore, the Company’s natural gas transmission operation, is subject to regulation by the FERC.

Delaware. On September 2, 2005, the Delaware division filed an application with the Delaware PSC requesting approval of an alternative rate design and rate structure in order to provide natural gas service to prospective customers in eastern Sussex County (“2005 Proceeding”). While Chesapeake provides natural gas service to residents and businesses in portions of Sussex County under the Company’s current tariff, natural gas distribution lines have not been extended to a large portion of eastern Sussex County targeted for growth by the State of Delaware. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy to enhance the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broader number of prospective customers within eastern Sussex County supports the Task Force recommendation. As the Delaware division included these proposals in its base rate filing made on July 6, 2007, the Delaware division closed the 2005 Proceeding with the intent to continue discussions in the context of the 2007 base rate proceeding.

On September 1, 2006, the Company filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR rates effective for service rendered on and after November 1, 2006. On October 3, 2006, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Division of the Public Advocate (“DPA”) recommended a cost disallowance of approximately $4.4 million related to the Delaware division’s commodity procurement purchases and a disallowance of approximately $275,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Delaware PSC Staff recommended a cost disallowance of approximately $2.2 million related to the Delaware division’s commodity procurement purchases and the deferral of approximately $535,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Company disagreed with these recommendations and opposed the proposed cost disallowances and deferrals in its rebuttal position submitted on April 19, 2007. Under established Delaware law, gas procurement costs, like other normally accepted operating expenses, cannot be disallowed unless it is shown that the costs were the result of an abuse of discretion, bad faith, or waste. Management believes that the Company’s gas procurement practices and pipeline capacity costs were reasonable and that, in no event were the costs at issue incurred as a result of any abuse of discretion, bad faith, or waste on the part of the Company. On July 24, 2007, the Delaware PSC approved a settlement agreement among the parties resulting in a complete recovery of the Delaware division’s costs.  As a result of the settlement agreement, the Delaware division has agreed to contribute an amount equal to $37,500 per year for the next three years to a program designed to benefit elderly, disabled, and low-income customers of the Delaware division.  In addition, with respect to the allowances for recovery of costs associated with pipeline capacity in eastern Sussex County, the settlement provides for the Delaware division to reduce the total amount of GSR charges to be collected from its customers by $275,000, effective beginning with the billing period from November 1, 2007 through October 31, 2008.  The settlement also provides for the Delaware division to add $275,000 to the total GSR charges to be collected from customers effective for billings from November 1, 2008 through October 31, 2009.

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

- Page 26 -

On November 9, 2006, the Delaware division filed two applications with the Delaware PSC requesting approval for a Town of Millsboro Franchise Fee Rider and a Town of Georgetown Franchise Fee Rider. These Riders will allow the Delaware division to charge all respective natural gas customers within town limits the franchise fee paid by the Delaware division to the Towns of Millsboro and Georgetown as a condition to providing natural gas service. The Delaware PSC granted approval of both Riders on January 23, 2007.
 
On July 6, 2007, the Company filed with the Delaware PSC an application seeking approval of the following: (i) participation by the Company’s Delaware commercial and industrial customers in transportation buying pools served by third-party natural gas marketers; (ii) a base rate adjustment of $1,896,000 annually that represents approximately a 3.25 percent rate increase on average for the Delaware 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 reduces the impact of natural gas consumption on both customers and the Company. As an incentive for the Delaware division to make the significant capital investments to serve the growing areas of eastern Sussex County and in supporting Delaware’s Energy Policy, the Company has proposed as part of the filing that the Delaware division be permitted to earn a return on equity up to 15 percent. This level of return would 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 growing 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 Delaware PSC Staff filed testimony recommending a rate decrease of $693,245.  The DPA recommended a rate decrease of $588,670.  Neither party recommended approval of the Delaware division’s other proposals mentioned above.  The Delaware division strongly disagrees with these positions and is currently in the process of drafting its rebuttal position which was filed on February 7, 2008.  The Delaware division anticipates a final decision by the Delaware PSC during the second quarter of 2008.

On September 10, 2007, the Company filed with the Delaware PSC its annual GSR Application, seeking the approval of the Delaware PSC to change its GSR rates effective for service rendered on and after November 1, 2007.  On October 2, 2007, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC.  The Delaware division anticipates a final decision by the Delaware PSC during the second or third quarter of 2008.

On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2007. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision.  The Delaware division anticipates a final decision by the Delaware PSC during the first quarter of 2008.

Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division of approximately $780,000 annually. In a settlement agreement entered into in that proceeding, the Maryland division was required to file a depreciation study, which was filed on April 9, 2007. The Maryland division filed formal testimony on July 10, 2007, initiating a phase II of this proceeding. In this filing, the Maryland division proposed a rate decrease of approximately $80,000 annually, resulting from a change in depreciation expense. On November 29, 2007 the Maryland PSC approved a settlement agreement for a rate decrease of $132,155, effective December 1, 2007 based on the change in the Company’s depreciation rates.

On December 17, 2007, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2007.  No issues were raised at the hearing.  The Maryland division anticipates a final decision by the Maryland PSC during the first quarter of 2008.
 
Florida. On October 10, 2006, the Florida division filed with the Florida PSC a petition for authority to implement phase two of its experimental transitional transportation service (“TTS”) pilot program, and for approval of a new tariff to reflect the division’s transportation service environment. Phase two of the TTS program for residential and certain small commercial consumers will expand the number of pool managers from one to two and increase the gas supply pricing options available to these consumers. Approved on April 24, 2007 by the Florida PSC, phase two of the TTS program went into effect on July 1, 2007.
 
On November 29, 2006, the Florida division filed with the Florida PSC a petition for authority to modify its energy conservation programs. In this petition, the Florida division sought approval to increase the cash allowances paid within its Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of its Residential Water Heater Retention Program to add natural gas heating systems, cooking and clothes drying appliances. The Florida PSC granted approval of the petition in an order dated March 5, 2007. The modifications and new cash allowances became effective on March 30, 2007.

On May 2, 2007, the Florida division filed its summary of activity and true-up calculation for its 2006 Energy Conservation Cost Recovery Program with the Florida PSC. On September 5, 2007, the Florida PSC issued its audit report in which less than $8,000, or one percent, of the 2006 expenditures were disallowed as non-conservation-related.  The results of the audit were incorporated into the calculation of the 2008 Energy Conservation Cost Recovery Factors, which were filed with the Florida PSC on September 13, 2007, approved on November 6, 2007, and became effective on January 1, 2008.
 
In compliance with the Florida Administrative Code, the Florida division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This study provides the Florida PSC with the opportunity to review and address changes in plant and equipment lives, salvage values, reserves and resulting life depreciation rates since the last study performed in 2002. In its filing, the Florida division has requested that any changes to the depreciation rates be made effective January 1, 2008.  The Florida division responded to interrogatories concerning the Study on October 15 and December 24, 2007.  While the Company cannot predict the outcome of the Florida PSC’s review at this time, the Company anticipates a final decision regarding the depreciation rates in the second quarter of 2008.

On July 6, 2007, the Company and Peoples Gas Service (“PGS”), another local gas distribution company in Florida, filed a joint petition for Commission action on a territorial agreement for portions of Pasco County, a Master Territorial Agreement and a Gas Transportation Agreement filed as a special contract.  PGS operates a natural gas distribution system in Pasco County but is unable to serve economically certain areas of the county.  The Company entered into negotiations with PGS that would allow the Company to serve these areas by connecting to PGS’ existing distribution system and to extend its facilities into these specific territories to serve primarily residential and commercial consumers.  The negotiations concluded with the execution of a Pasco County Territorial Agreement that provides the Company with two distinct areas as its territory and a Gas Transportation Agreement that specifies the terms, conditions and rates for transportation service across the PGS distribution system.  The Company and PGS have also entered into a Master Territorial Agreement that contains terms and conditions which will govern all existing and potential territorial agreements.  The Florida PSC approved these agreements at its October 9, 2007 agenda conference.

On August 27, 2007, PIPECO, filed with the Florida PSC its petition for approval of a natural gas transmission pipeline tariff in order to establish its operating rules and regulations.  The Florida PSC approved the petition at its December 4, 2007 agenda conference.
 
Eastern Shore. During 2007, FERC regulatory activity regarding the expansion of Eastern Shore’s transmission system included the following:

System Expansion 2006 – 2008   On January 20, 2006, Eastern Shore filed with the FERC an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (“the 2006 – 2008 Project”). The application requested authority to construct and operate approximately 55 miles of new pipeline facilities and two new metering and regulating station facilities to provide an additional 47,350 dekatherms per day (“Dt/d”) of firm transportation service in accordance with customer requests of 26,200 Dt/d in 2006, 10,300 Dt/d in 2007, and 10,850 Dt/d in 2008, at a total estimated cost of approximately $33.6 million. On June 13, 2006, the FERC issued a certificate authorizing Eastern Shore to construct and operate the 2006 – 2008 Project as proposed. On November 1, 2006, Eastern Shore completed and placed in service the authorized Phase I facilities.

On July 24, 2007, Eastern Shore requested FERC authorization to commence construction of a portion (approximately 4 miles) of the Phase II facilities. Eastern Shore received the requested FERC authorization on August 11, 2007.  Facilities have been completed and were placed in service on November 1, 2007. These additional facilities provide for 8,300 Dts of additional firm capacity per day and annualized gross margin contribution of $1.2 million, instead of the amounts included in the original filing of 10,300 Dts of additional firm capacity per day and $1.5 million annualized gross margin contribution.
 
- Page 27 -

On November 15, 2007 Eastern Shore requested FERC authorization to commence construction of Phase III facilities (approximately 9.2 miles). The FERC granted this authorization on January 7, 2008.  Construction activities are to begin in the first quarter of 2008 and are to be completed and placed in service on November 1, 2008. These Phase III facilities provide for 5,650 Dts of additional firm capacity per day and annualized gross margin contribution of approximately $1.0 million instead of the amounts included in the original filing of 10,850 Dts of additional firm capacity per day and $1.6 million annualized gross margin contribution.

Eastern Shore Energylink Expansion Project (“E3 Project”). In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas from Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware.

On May 31, 2006, Eastern Shore entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Company (“Delmarva”) and Chesapeake, through its Delaware and Maryland divisions, to provide additional firm transportation services upon completion of the E3 Project.  Both Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desires additional firm transportation service under the E3 Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, additional firm transportation service under the E3 Project.

As part of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements which provide that, if the event that the E3 Project is not certificated and placed in service, Chesapeake and Delmarva will each pay their proportionate share of certain pre-certification costs by means of a negotiated surcharge of up to $2 million, over a period of not less than 20 years.

In furtherance of the E3 Project, Eastern Shore submitted a petition to the FERC on June 27, 2006 seeking approval of an uncontested rate-related Settlement Agreement by and between Eastern Shore, Chesapeake and Delmarva (the “Settlement Agreement”). The Settlement Agreement provides Eastern Shore and all customers utilizing Eastern Shore’s system with benefits, including but not limited to the following: (1) advancement of a necessary infrastructure project to meet the growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project development costs by the participating customers in the project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC approved the Settlement Agreement, which was uncontested. On September 6, 2006, Eastern Shore submitted to 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, Eastern Shore submitted to the FERC its request to commence a pre-filing process and on May 15, 2007, the FERC notified Eastern Shore that its request had been approved. The pre-filing process is 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, Eastern Shore has performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. Eastern Shore has 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, Eastern Shore 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, Eastern Shore explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes.  Eastern Shore also held discussions and meetings with several potential new customers, who have expressed an interest in the project that would expand its size and likely have significant impact on the cost, timeline and in-service date.

On December 20, 2007, Eastern Shore withdrew from the pre-filing process as a result of insufficient customer commitments for capacity to make the project economical. Eastern Shore 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 project.

If Eastern Shore decides to abandon the E3 Project, it will initiate billing of pre-certification costs surcharge in accordance with the terms of the Precedent Agreements executed with two of its customers, which provide for these customers to reimburse Eastern Shore for pre-certification costs incurred in connection with the E3 Project, up to a maximum amount of $2.0 million each over a period of 20 years.  As of December 31, 2007, the Company had incurred $2.97 million of pre-certification costs relating to the E3 Project.
 
During 2007, Eastern Shore also had developments in the following FERC rate matters:

On October 31, 2006, Eastern Shore filed a base rate proceeding with the FERC in compliance with the settlement approved in its prior base rate proceeding. Eastern Shore’s filed rates, proposed to be effective November 1, 2006, reflected an annual increase of $5,589,000 in its annual operating revenues based on increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on existing gas plant facilities and new facilities placed into service by March 31, 2007.

On November 30, 2006 the FERC issued an order suspending the effectiveness of Eastern Shore’s proposed rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order. On December 19, 2006, the Presiding Administrative Law Judge (“ALJ”) approved a procedural schedule to govern further proceedings in this case.

Settlement conferences were held on April 17, May 30, and June 6, 2007 at the FERC’s offices in Washington, D.C. On May 14, 2007, Eastern Shore filed a motion, which the FERC granted, to make its suspended rate increase effective on May 15, 2007, subject to refund, pending the ultimate resolution of the rate case. At the June 6, 2007 conference, the parties reached a settlement agreement in principle, and on June 8, 2007, the Chief ALJ suspended the procedural schedule to allow time for the parties to draft a formal Stipulation and Agreement. The negotiated settlement provides for an annual cost of service of $21,536,000, which reflects a pretax return on equity of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, Eastern Shore submitted its Settlement Offer to the Commission for the ALJ’s review and certification to the full Commission. There were no comments filed objecting to, or in protest of, the Settlement Offer.

Eastern Shore 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 Commission issued an order on September 25, 2007, authorizing Eastern Shore 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 Commission Order approving the settlement was issued on January 31, 2008.

- Page 28 -

Environmental Matters
The Company continues to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at three environmental sites (see Note M to the Consolidated Financial Statements). The Company believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

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’s long-term debt consists of first mortgage bonds, fixed-rate senior notes and convertible debentures (see Note H to the Consolidated Financial Statements for annual maturities of consolidated long-term debt). All of the Company’s 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 $70.9 million at December 31, 2007, as compared to a fair value of $75.0 million, based mainly on current market prices or discounted cash flows, using current rates for similar issues with similar terms and remaining maturities. The Company evaluates whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.
 
The Company’s propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its 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 has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. Management reviewed the Company’s storage position as of December 31, 2007, and elected not to hedge any of its inventories.  At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the 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 described in SFAS 133. At the end of 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.  The Company did not enter into a similar agreement in 2007.
 
The Company’s propane wholesale marketing operation is a party to natural gas liquids (“NGL”) forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL to the Company or the counter-party or “booking out” the transaction.  Booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy. The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane.

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for NGL 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’s 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 by the Company’s oversight officials daily. In addition, the Risk Management Committee reviews periodic reports on market 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, 2007 and 2006 is presented in the following tables.

 
 At December 31, 2007
 
Quantity in gallons
   
Estimated Market Prices
   
Weighted Average Contract Prices
 
 Forward Contracts
                 
 Sale
 
 30,941,400
   
$0.8925 — $1.6025
   
$1.3555
 
 Purchase
 
 30,954,000
   
$0.8700 — $1.6000
   
$1.3498
 
                         
Estimated market prices and weighted average contract prices are in dollars per gallon.
 
All contracts expire in 2008.
                 


 
   
Quantity
   
Estimated
   
Weighted Average
 
 At December 31, 2006
 
in gallons
   
Market Prices
   
Contract Prices
 
 Forward Contracts
                 
 Sale
 
 13,797,000
   
$0.9250 — $1.2100
   
$1.0107
 
 Purchase
   13,733,800     $0.9250 — $1.2200     $1.0098  
                         
Estimated market prices and weighted average contract prices are in dollars per gallon.
 
All contracts expired in 2007.
                 
 

The Company’s natural gas distribution and marketing operations have entered into agreements with natural gas suppliers to purchase natural gas 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.
 
- Page 29 -

Competition
The Company’s natural gas operations compete with other forms of energy including electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. The Company’s natural gas distribution operations have several large volume industrial customers that can use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements. Lower levels of interruptible sales may occur when oil prices are lower than the price of natural gas. Oil prices, as well as the prices of electricity and other fuels, are subject to fluctuation for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales sides of this business to compete with the fluctuations in its customers’ alternative fuel prices. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, their businesses have shifted from providing bundled transportation and sales service to providing only transportation and contract storage services.
 
The Company’s natural gas distribution operations in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended such service to residential customers. With such transportation service available on the Company’s distribution systems, the Company is competing with third-party suppliers to sell gas to industrial customers. With respect to unbundled transportation services, the Company’s 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’s distribution operations in this manner. In certain situations, the Company’s distribution operations may adjust services and rates for these customers to retain their business. The Company expects to continue to expand the availability of transportation service to additional classes of distribution customers in the future. The Company established a natural gas sales and supply operation in Florida to compete for customers eligible for transportation services. The Company also provides such sales service in Delaware.

The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally from local outlets of national distribution companies and local businesses because distributors located in close proximity to customers incur lower costs of providing 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, which 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.

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 distribution operations, fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanism in the Company’s tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for its regulated operations and closely monitors the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts its propane selling prices to the extent allowed by the market.
 
- Page 30 -

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, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations 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;
 
·  
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;
 
·  
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 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;
 
·  
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.
 
 
- Page 31 -

 
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 Exchange Act Rules 13a-15(f). A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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. Chesapeake’s management has evaluated and concluded that Chesapeake’s internal control over financial reporting was effective as of December 31, 2007.
 
 
- Page 32 -

 
 
 
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 sheet of Chesapeake Utilities Corporation as of December 31, 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, cash flows and income taxes for the year then ended. 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 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 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 audit provides 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, 2007 and the results of their operations and their cash flows for the year ended in conformity with accounting principles generally accepted in the United States of America.
 
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2008 expressed an unqualified opinion.
 
 

 

/s/ Beard Miller Company LLP
————————————————
Beard Miller Company LLP
Reading, Pennsylvania
March 10, 2008

 
- Page 33 -

 

Report of Independent Registered Public Accounting Firm
________


To the Board of Directors and Stockholders
of Chesapeake Utilities Corporation

In our opinion, the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, comprehensive income, cash flows, stockholders’ equity and income taxes for each of the two years in the period 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 financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period 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 each of the two years in the period 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 audits.  We conducted our audits, 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 audits provide a reasonable basis for our opinion.

As discussed in Note K 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 properly applied.  Those adjustments were audited by other auditors.
 
 

/s/ PricewaterhouseCoopers LLP
————————————————
PricewaterhouseCoopers LLP
Boston, MA
March 10, 2007

- Page 34 -

 
Consolidated Statements of Income
  
 For the Twelve Months Ended December 31,
 
2007
   
2006
   
2005
 
 Operating Revenues
  $ 258,286,495     $ 231,199,565     $ 229,485,352  
 Operating Expenses
                       
 Cost of sales, excluding costs below
    170,848,211       155,809,747     $ 153,398,723  
 Operations
    42,274,023       36,670,302       39,778,597  
 Maintenance
    2,203,800       2,103,558       1,818,981  
 Depreciation and amortization
    9,060,185       8,243,715     $ 7,568,209  
 Other taxes
    5,786,694       5,040,306     $ 4,999,963  
 Total operating expenses
    230,172,913       207,867,628       207,564,473  
 Operating Income
    28,113,582       23,331,937       21,920,879  
 Other income, net of other expenses
    291,305       189,093     $ 382,610  
 Interest charges
    6,589,639       5,773,993     $ 5,132,458  
 Income Before Income Taxes
    21,815,248       17,747,037       17,171,031  
 Income taxes
    8,597,461       6,999,072       6,472,220  
 Income from Continuing Operations
    13,217,787       10,747,965       10,698,811  
 Loss from discontinued operations, net of
                       
 tax benefit of $10,898, $162,510 and $160,204
    (20,077 )     (241,440 )     (231,197 )
 Net Income
  $ 13,197,710     $ 10,506,525     $ 10,467,614  
                         
Weighted Average Common Shares Outstanding:
                 
Basic
    6,743,041       6,032,462       5,836,463  
Diluted
    6,854,716       6,155,131       5,992,552  
                   
Earnings (Loss) Per Share of Common Stock:
                 
 Basic
                       
 From continuing operations
  $ 1.96     $ 1.78     $ 1.83  
 From discontinued operations
    -     $ (0.04 )     (0.04 )
 Net Income
  $ 1.96     $ 1.74     $ 1.79  
                         
 Diluted
                       
 From continuing operations
  $ 1.94     $ 1.76     $ 1.81  
 From discontinued operations
    -     $ (0.04 )     (0.04 )
 Net Income
  $ 1.94     $ 1.72     $ 1.77  

The accompanying notes are an integral part of the financial statements.
- Page 35 -


Consolidated Statements of Cash Flows
 
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
Operating Activities
                 
  Net Income   $ 13,197,710     $ 10,506,525     $ 10,467,614  
  Adjustments to reconcile net income to net operating cash:
                       
  Depreciation and amortization
    9,060,185       8,243,715       7,568,209  
  Depreciation and accretion included in other costs
    3,336,506       3,102,066       2,705,620  
  Deferred income taxes, net
    1,831,030       (408,533 )     1,510,777  
  Gain on sale of assets
 
  (204,882 )     -       -  
  Unrealized gain (loss) on commodity contracts
    (170,465 )     37,110       (227,193 )
  Unrealized loss on investments
    (122,819 )     (151,952 )     (56,650 )
  Employee benefits and compensation
    1,825,028       382,608       1,621,607  
  Other, net
    56       (18,596 )     (62,692 )
  Changes in assets and liabilities:                        
  Sale (purchase) of investments
    229,125       (177,990 )     (1,242,563 )
  Accounts receivable and accrued revenue
 
  (28,189,132 )     9,705,860       (16,831,751 )
  Propane inventory, storage gas and other inventory
    1,193,336       354,764       (5,704,040 )
  Regulatory assets
    (344,680 )     2,498,954       (1,719,184 )
  Prepaid expenses and other current assets
    (1,188,481 )     (271,438 )     36,704  
  Other deferred charges
    (2,477,879 )     (231,822 )     (102,561 )
  Long-term receivables
    83,653       137,101       247,600  
  Accounts payable and other accrued liabilities
    22,130,049       (11,434,370 )     15,569,924  
  Income taxes receivable (payable)
    (158,556 )     1,800,913       (2,006,762 )
  Accrued interest
    33,112       273,672       (42,376 )
  Customer deposits and refunds
    2,534,655       2,361,265       462,781  
  Accrued compensation
    1,117,941       (542,512 )     875,342  
  Regulatory liabilities
    2,124,091       2,824,068       144,501  
  Other liabilities
    (157,699 )     1,125,590       385,034  
Net cash provided by operating activities
    25,681,884       30,116,998       13,599,941  
                         
Investing Activities
                       
  Property, plant and equipment expenditures
    (31,277,390 )     (48,845,828 )     (33,319,613 )
  Proceeds from sale of assets
    204,882       -       -  
  Environmental recoveries (expenditures)
    (227,979 )     (15,549 )     240,336  
Net cash used by investing activities
    (31,300,487 )     (48,861,377 )     (33,079,277 )
                         
Financing Activities
                       
  Common stock dividends
    (7,029,821 )     (5,982,531 )     (5,789,180 )
  Issuance of stock for Dividend Reinvestment Plan
    299,436       321,865       458,757  
  Stock issuance
    -       19,698,509       -  
  Cash settlement of warrants
    -       (434,782 )     -  
  Change in cash overdrafts due to outstanding checks
    (541,052 )     49,047       874,083  
  Net borrowing (repayment) under line of credit agreements
    18,651,055       (7,977,347 )     29,606,400  
  Proceeds from issuance of long-term debt
    -       20,000,000       -  
  Repayment of long-term debt
    (7,656,580 )     (4,929,674 )     (4,794,827 )
Net cash provided by financing activities
    3,723,038       20,745,087       20,355,233  
                         
Net Increase (Decrease) in Cash and Cash Equivalents
    (1,895,565 )     2,000,708       875,897  
Cash and Cash Equivalents — Beginning of Period
    4,488,366       2,487,658       1,611,761  
Cash and Cash Equivalents — End of Period
  $ 2,592,801     $ 4,488,366     $ 2,487,658  
                         
Supplemental Disclosures of Non-Cash Investing Activities:
                       
  Capital property and equipment acquired on account,                        
  but not paid as of December 31   $ 365,890     $ 1,490,890     $ 1,367,348  
                         
Supplemental Disclosure of Cash Flow information
                       
  Cash paid for interest   $ 5,592,279     $ 5,334,477     $ 5,052,013  
  Cash paid for income taxes   $ 7,009,206     $ 6,285,272     $ 6,342,476  

 
The accompanying notes are an integral part of the financial statements.
- Page 36 -

 
Consolidated Balance Sheets
  
 Assets
 
December 31,
2007
   
December 31, 2006
 
             
Property, Plant and Equipment
       
 Natural gas
  $ 289,706,066     $ 269,012,516  
 Propane
    48,506,231       44,791,552  
 Advanced information services
    1,157,808       1,054,368  
 Other plant
    8,567,833       9,147,500  
 Total property, plant and equipment
    347,937,938       324,005,936  
 Less:  Accumulated depreciation and amortization
    (92,414,289 )     (85,010,472 )
 Plus:  Construction work in progress
    4,899,608       1,829,948  
 Net property, plant and equipment
    260,423,257       240,825,412  
                 
 Investments
    1,909,271       2,015,577  
                 
 Current Assets
               
 Cash and cash equivalents
    2,592,801       4,488,366  
 Accounts receivable (less allowance for uncollectible
 
    accounts of $952,075 and $661,597, respectively)
    72,218,191       44,969,182  
 Accrued revenue
    5,265,474       4,325,351  
 Propane inventory, at average cost
    7,629,295       7,187,035  
 Other inventory, at average cost
    1,280,506       1,564,937  
 Regulatory assets
    1,575,072       1,275,653  
 Storage gas prepayments
    6,042,169       7,393,335  
 Income taxes receivable
    1,237,438       1,078,882  
 Deferred income taxes
    2,155,393       1,365,316  
 Prepaid expenses
    3,496,517       2,280,900  
 Mark-to-market energy assets
    7,812,456       1,379,896  
 Other current assets
    146,253       173,388  
 Total current assets
    111,451,565       77,482,241  
                 
Deferred Charges and Other Assets
         
 Goodwill
    674,451       674,451  
 Other intangible assets, net
    178,073       191,878  
 Long-term receivables
    740,680       824,333  
 Regulatory assets
    2,539,235       1,765,088  
 Other deferred charges
    3,640,480       1,215,004  
 Total deferred charges and other assets
    7,772,919       4,670,754  
                 
                 
                 
                 
                 
                 
                 
 Total Assets
  $ 381,557,012     $ 324,993,984  


 
The accompanying notes are an integral part of the financial statements.
- Page 37 -

 
Consolidated Balance Sheets

 
 Capitalization and Liabilities
 
December 31,
2007
   
December 31, 2006
 
             
 Capitalization
           
 Stockholders' equity
           
Common Stock, par value $0.4867 per share
 
(authorized 12,000,000 shares)
  $ 3,298,473     $ 3,254,998  
 Additional paid-in capital
    65,591,552       61,960,220  
 Retained earnings
    51,538,194       46,270,884  
 Accumulated other comprehensive loss
    (851,674 )     (334,550 )
 Deferred compensation obligation
    1,403,922       1,118,509  
 Treasury stock
    (1,403,922 )     (1,118,509 )
 Total stockholders' equity
    119,576,545       111,151,552  
                 
 Long-term debt, net of current maturities
    63,255,636       71,050,000  
 Total capitalization
    182,832,181       182,201,552  
                 
 Current Liabilities
               
 Current portion of long-term debt
    7,656,364       7,656,364  
 Short-term borrowing
    45,663,944       27,553,941  
 Accounts payable
    54,893,071       33,870,552  
 Customer deposits and refunds
    10,036,920       7,502,265  
 Accrued interest
    865,504       832,392  
 Dividends payable
    1,999,343       1,939,482  
 Accrued compensation
    3,400,112       2,901,053  
 Regulatory liabilities
    6,300,766       4,199,147  
 Mark-to-market energy liabilities
    7,739,261       1,371,379  
 Other accrued liabilities
    2,500,542       2,634,416  
 Total current liabilities
    141,055,827       90,460,991  
                 
Deferred Credits and Other Liabilities
         
 Deferred income taxes
    28,795,885       26,517,098  
 Deferred investment tax credits
    277,698       328,277  
 Regulatory liabilities
    1,136,071       1,236,254  
 Environmental liabilities
    835,143       211,581  
 Other pension and benefit costs
    2,513,030       1,608,311  
 Accrued asset removal cost
    20,249,948       18,410,992  
 Other liabilities
    3,861,229       4,018,928  
 Total deferred credits and other liabilities
    57,669,004       52,331,441  
                 
Other Commitments and Contingencies (Note N)
 
                 
                 
 Total Capitalization and Liabilities
  $ 381,557,012     $ 324,993,984  

 
The accompanying notes are an integral part of the financial statements.
- Page 38 -

 
Consolidated Statements of Stockholders’ Equity
   
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
                     
Common Stock
                 
  Balance — beginning of year
  $ 3,254,998     $ 2,863,212     $ 2,812,538  
  Dividend Reinvestment Plan
    17,197       18,685       20,038  
  Retirement Savings Plan
    14,388       14,457       10,255  
  Conversion of debentures
    3,945       8,117       11,004  
  Performance shares and options exercised (1)
    7,945       14,536       9,377  
  Stock issuance
    -       335,991       -  
  Balance — end of year     3,298,473       3,254,998       2,863,212  
                           
Additional Paid-in Capital
                       
  Balance — beginning of year
    61,960,220       39,619,849       36,854,717  
  Dividend Reinvestment Plan
    1,121,190       1,148,100       1,224,874  
  Retirement Savings Plan
    934,295       900,354       682,829  
  Conversion of debentures
    133,839       275,300       373,259  
  Performance shares and options exercised (1)
    498,674       887,426       484,170  
  Stock-based compensation
    943,334       -       -  
  Stock issuance
    -       19,362,518       -  
  Exercise warrants, net of tax
    -       (233,327 )     -  
  Balance — end of year     65,591,552       61,960,220       39,619,849  
                           
Retained Earnings
                       
  Balance — beginning of year
    46,270,884       42,854,894       39,015,087  
  Net income
    13,197,710       10,506,525       10,467,614  
  Cash dividends (2)
    (7,930,400 )     (7,090,535 )     (6,627,807 )
  Balance — end of year     51,538,194       46,270,884       42,854,894  
                           
Accumulated Other Comprehensive Income (Loss)
                       
  Balance — beginning of year
    (334,550 )     (578,151 )     (527,246 )
  Minimum pension liability adjustment, net of tax
    28,106       74,036       (50,905 )
  Gain (Loss) on funded status of Employee Benefit Plans, net of tax
    (545,230 )     169,565       -  
  Balance — end of year     (851,674 )     (334,550 )     (578,151 )
                           
Deferred Compensation Obligation
                       
  Balance — beginning of year
    1,118,509       794,535       816,044  
  New deferrals
    285,413       323,974       130,426  
  Payout of deferred compensation
    -       -       (151,935 )
  Balance — end of year     1,403,922       1,118,509       794,535  
                           
Treasury Stock
                       
  Balance — beginning of year
    (1,118,509 )     (797,156 )     (1,008,696 )
  New deferrals related to compensation obligation
    (285,413 )     (323,974 )     (130,426 )
  Purchase of treasury stock
    (29,771 )     (51,572 )     (182,292 )
  Sale and distribution of treasury stock
    29,771       54,193       524,258  
  Balance — end of year     (1,403,922 )     (1,118,509 )     (797,156 )
                           
                           
Total Stockholders’ Equity
  $ 119,576,545     $ 111,151,552     $ 84,757,183  
                           
(1) Includes amounts for shares issued for Directors' compensation.          
(2) Cash dividends declared per share for 2007, 2006 and 2005 were $1.18, $1.16 and $1.14, respectively.  
                           
 Consolidated Statements of Comprehensive Income
                       
  Net income   $ 13,197,710     $ 10,506,525     $ 10,467,614  
  Pension adjustments, net of tax of                        
    $342,320, ($48,889) and $33,615, respectively     (517,124 )     74,036       (50,905 )
Comprehensive Income
  $ 12,680,586     $ 10,580,561     $ 10,416,709  

 
The accompanying notes are an integral part of the financial statements.
- Page 39 -

 
Consolidated Statements of Income Taxes
      
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
                   
Current Income Tax Expense
                 
Federal
  $ 5,512,071     $ 5,994,296     $ 3,687,800  
State
    1,223,145       1,424,485       789,233  
Investment tax credit adjustments, net
    (50,579 )     (54,816 )     (54,816 )
Total current income tax expense
    6,684,637       7,363,965       4,422,217  
                         
Deferred Income Tax Expense (1)
                       
Property, plant and equipment
    2,958,758       1,697,024       1,380,628  
Deferred gas costs
    (629,228 )     (2,085,066 )     1,064,310  
Pensions and other employee benefits
    (9,154 )     (97,436 )     (340,987 )
Environmental expenditures
    45,872       (5,580 )     (98,229 )
Other
    (464,322 )     (36,345 )     (115,923 )
Total deferred income tax expense (benefit)
    1,901,926       (527,403 )     1,889,799  
Total Income Tax Expense
  $ 8,586,563     $ 6,836,562     $ 6,312,016  
                         
Reconciliation of Effective Income Tax Rates
                       
  Continuing Operations
                       
Federal income tax expense (2)
  $ 7,635,336     $ 6,212,237     $ 6,009,861  
State income taxes, net of federal benefit
    1,086,680     $ 829,630     $ 732,046  
Other
    (124,555 )   $ (42,795 )   $ (269,687 )
  Total continuing operations
  $ 8,597,461     $ 6,999,072     $ 6,472,220  
  Discontinued operations
  $ (10,898 )   $ (162,510 )   $ (160,204 )
Total income tax expense
  $ 8,586,563     $ 6,836,562     $ 6,312,016  
                         
Effective income tax rate
    39.4 %     39.4 %     37.6 %
                         
At December 31,
 
2007
   
2006
         
                         
Deferred Income Taxes
                       
Deferred income tax liabilities:
                       
Property, plant and equipment
  $ 31,058,050     $ 27,997,744          
Environmental costs
    250,021       204,149          
Other
    860,993       870,424          
Total deferred income tax liabilities
    32,169,064       29,072,317          
                         
Deferred income tax assets:
                       
Pension and other employee benefits
    2,581,853       2,225,944          
Self insurance
    384,009       468,922          
Deferred gas costs
    1,146,133       528,814          
Other
    1,416,577       696,855          
Total deferred income tax assets
    5,528,572       3,920,535          
Deferred Income Taxes Per Consolidated Balance Sheet
  $ 26,640,492     $ 25,151,782          
                         
(1) Includes $260,000, ($60,000), and $146,000 of deferred state income taxes for the years 2007, 2006, and 2005, 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 40 -


 
A. Summary of Accounting Policies
 
Nature of Business
Chesapeake is engaged in natural gas distribution to 62,852 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas transmission subsidiary operates an interstate pipeline from various points in Pennsylvania and northern Delaware to the Company’s Delaware and Maryland distribution divisions as well as other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s propane distribution and wholesale marketing segment provides distribution service to 34,143 customers in central and southern Delaware, the Eastern Shore of Maryland, southeastern Pennsylvania, central Florida and the Eastern Shore of Virginia and markets propane to wholesale customers including large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States. 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.

Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries. The Company does 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
The natural gas distribution divisions of the Company located in Delaware, Maryland and Florida are subject to regulation by their respective PSCs with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore is an open access pipeline and is subject to regulation 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 commissions. The propane, advanced information services and other business segments are not subject to regulation with respect to rates or maintenance of accounting records.
 
Property, Plant, Equipment and Depreciation
Utility and non-utility property is stated at original cost. 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, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of utility property, 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 are provided at an annual rate for each segment. The three-year average rates were three percent for natural gas distribution and transmission, five percent for propane, eleven percent for advanced information services and six percent for general plant.
 
 
At December 31,
2007
2006
Useful Life (1)
Plant in service
     
Mains
$166,202,413
$151,890,304
27-41 years
Services — utility
35,127,633
32,334,145
14-33 years
Compressor station equipment
24,959,330
24,921,976
28 years
Liquefied petroleum gas equipment
25,575,213
24,627,398
30-33 years
Meters and meter installations
18,111,466
16,093,737
Propane 10-33 years, Natural gas 26-44 years
Measuring and regulating station equipment
14,067,262
13,272,201
27-54 years
Office furniture and equipment
9,947,881
10,114,101
Non-regulated 3-10 years, Regulated 14-28 years
Transportation equipment
11,194,916
10,686,259
3-11 years
Structures and improvements
10,024,105
9,538,345
10-44 years (2)
Land and land rights
7,404,679
7,386,268
Not depreciable, except certain regulated assets
Propane bulk plants and tanks
5,313,061
5,301,457
15 - 40 years
Various
20,009,979
17,839,745
Various
Total plant in service
347,937,938
324,005,936
 
Plus construction work in progress
4,899,608
1,829,948
 
Less accumulated depreciation
(92,414,289)
(85,010,472)
 
Net property, plant and equipment
$260,423,257
$240,825,412
 
       
 (1) Certain immaterial account balances may fall outside this range.
       
  The regulated operations compute depreciation in accordance with rates approved by either the state Public Service Commission
  or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the
  appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the
  time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied
  to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage
  value.      
       
  The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.
       
 (2) Includes buildings, structures used in connection with natural gas and propane operations, improvements to those facilities
  and leasehold improvements.

 
- Page 41 -

 
 
Cash and Cash Equivalents
The Company’s policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.

Inventories
The Company uses the average cost method to value propane and materials and supplies 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 accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” This standard 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, the regulated utility defers the associated costs as 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 company for amounts previously collected from customers, and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

At December 31, 2007 and 2006, 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,
 
2007
   
2006
 
Regulatory Assets
           
Current
           
Underrecovered purchased gas costs
  $ 1,389,454     $ 1,076,921  
Conservation cost recovery
    -       51,408  
PSC Assessment
    22,290       22,290  
Flex rate asset
    107,394       81,926  
Other
    55,934       43,108  
Total current
    1,575,072       1,275,653  
                 
Non-Current
               
Income tax related amounts due from customers
    1,115,638       1,300,544  
Deferred regulatory and other expenses
    446,642       188,686  
Deferred gas supply
    15,201       15,201  
Deferred post retirement benefits
    111,159       138,949  
Environmental regulatory assets and expenditures
    850,594       121,708  
Total non-current
    2,539,234       1,765,088  
                 
Total Regulatory Assets
  $ 4,114,306     $ 3,040,741  
                 
Regulatory Liabilities
               
Current
               
Self insurance — current
  $ 191,004     $ 568,897  
Overrecovered purchased gas costs
    4,225,845       2,351,553  
Shared interruptible margins
    11,202       100,355  
Conservation cost recovery
    395,379       -  
Operational flow order penalties
    -       7,831  
Swing transportation imbalances
    1,477,336       1,170,511  
Total current
    6,300,766       4,199,147  
                 
Non-Current
               
Self insurance — long-term
    757,557       600,787  
Income tax related amounts due to customers
    151,521       285,819  
Environmental overcollections
    226,993       349,648  
Total non-current
    1,136,071       1,236,254  
                 
Accrued asset removal cost
    20,249,948       18,410,992  
                 
Total Regulatory Liabilities
  $ 27,686,785     $ 23,846,393  
 
- Page 42 -


Included in the regulatory assets listed above are $107,000 of which is accruing interest. Of the remaining regulatory assets, $2.6 million will be collected in approximately one to two years, $293,000 will be collected within approximately 3 to 10 years, and $721,000 will be collected within approximately 11 to 15 years.  In addition, there is approximately $466,000 for which the Company is awaiting regulatory approval for recovery, but once approved is expected to be collected within 12 months.

As required by SFAS No. 71, the Company monitors its regulatory and competitive environment to determine whether the recovery of its regulatory assets continues to be probable. If the Company were to determine that recovery of these assets is no longer probable, it would write off the assets against earnings. The Company believes that SFAS No. 71 continues to apply to its regulated operations, and that the recovery of its regulatory assets is probable.

Goodwill and Other Intangible Assets
The Company accounts for its goodwill and other intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS No. 142, goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note F “Goodwill and Other Intangible Assets” for additional discussions 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.

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’s deferred tax liabilities applicable to utility 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 “Accounting for Uncertainty in Income Taxes,” effective January 1, 2007.  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a Company’s financial statements in accordance with SFAS 109 “Accounting for Income Taxes.”  FIN 48 requires that an uncertain tax position should be recognized only if it is “more likely than not” that the position is sustainable based on technical merits.  Recognizable tax positions should 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, Inc. (“Xeron”), the Company’s 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’s 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 income statement in the period of change. The resulting unrealized gains and losses are recorded as assets or liabilities, respectively. There were unrealized gains of $179,000 and $8,500 at December 31, 2007 and 2006, respectively. Trading liabilities are recorded in mark-to-market energy liabilities. Trading assets are recorded in mark-to-market energy assets.
 
The Company’s natural gas and propane distribution operations have entered into agreements with natural gas and propane suppliers to purchase gas for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives of 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. At December 31, 2007, the Company decided not to hedge any of its propane inventories.  At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the 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 described in SFAS 133. At the end of the 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.
 
Earnings Per Share
Chesapeake calculates earnings per share in accordance with SFAS 128 “Earnings per Share.”  The calculations of both basic and diluted earnings per share are presented in the following chart.

   
 For the Periods Ended December 31,
 
2007
   
2006
   
2005
 
 Calculation of Basic Earnings Per Share:
                 
 Net Income
  $ 13,197,710     $ 10,506,525     $ 10,467,614  
 Weighted average shares outstanding
    6,743,041       6,032,462       5,836,463  
 Basic Earnings Per Share
  $ 1.96     $ 1.74     $ 1.79  
                         
 Calculation of Diluted Earnings  Per Share:
                       
 Reconciliation of Numerator:
                       
 Net Income
  $ 13,197,710     $ 10,506,525     $ 10,467,614  
 Effect of 8.25% Convertible debentures
    95,611       105,024       123,559  
 Adjusted numerator — Diluted
  $ 13,293,321     $ 10,611,549     $ 10,591,173  
                         
 Reconciliation of Denominator:
                       
 Weighted shares outstanding — Basic
    6,743,041       6,032,462       5,836,463  
 Effect of dilutive securities
                       
 Warrants
    -       -       11,711  
 8.25% Convertible debentures
    111,675       122,669       144,378  
 Adjusted denominator — Diluted
    6,854,716       6,155,131       5,992,552  
                         
 Diluted Earnings  Per Share
  $ 1.94     $ 1.72     $ 1.77  
 
 
- Page 43 -

Operating Revenues
Revenues for the natural gas 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. However, the regulatory authorities have granted the Company’s 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 can negotiate rates above or below the FERC-approved tariff rates.
 
For regulated deliveries of natural gas, Chesapeake reads meters and bills customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accrues unbilled revenues for gas that has 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, Chesapeake must estimate the amount of gas that has not been accounted for on its delivery system 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.

The propane wholesale marketing operation records trading activity, on a net mark-to-market basis in the Company’s income statement, for open contracts. The propane distribution, advanced information services and other segments record revenue in the period the products are delivered and/or services are rendered.

Chesapeake’s natural gas distribution operations in Delaware and Maryland each have a purchased gas cost recovery mechanism.  This mechanism provides the Company with a method of adjusting the billing rates with its customers for changes in the cost of purchased gas included in base rates. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

The Company charges flexible rates to the natural gas distribution’s industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative fuels. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

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 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 prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Certain Risks and Uncertainties
The Company’s financial statements are prepared in conformity with generally accepted accounting principles that require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes M and N 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 records certain assets and liabilities in accordance with SFAS No. 71. If the Company were required to terminate application of SFAS No. 71 for its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This could result in a charge to earnings, net of applicable income taxes, which could be material.
 
FASB Statements and Other Authoritative Pronouncements
In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes.” This interpretation: (i) clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes;” (ii) prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return; and (iii) provides guidance on derecognition and classification of uncertain tax positions, reporting of interest and penalties, accounting in interim periods, disclosure, and transition.  FIN No.48 is effective for fiscal years beginning after December 15, 2006, and Chesapeake’s adoption of it in the first quarter of 2007 did not have any impact on the Company’s Consolidated Financial Statements.
 
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. Since SFAS No. 157 is effective for financial statements issued within fiscal years beginning after November 15, 2007, Chesapeake will be required to adopt this statement in the first quarter of 2008. The Company does not expect SFAS No. 157 will have a material impact on its Consolidated Financial Statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115.SFAS No. 159 permits entities to measure at fair value many financial instruments and certain other items that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007.   The Company does not expect SFAS No. 159 will have a material impact on its Consolidated Financial Statements.

In April 2007, the FASB directed the FASB Staff to issue FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 modifies FIN No. 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. The Company does not expect FSP FIN 39-1 will have a material impact its Consolidated Financial Statements.

Reclassification of Prior Years’ Amounts
The Company reclassified some previously reported amounts to conform to current period classifications.
 
B. Business Dispositions and Discontinued Operations
 
During the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services subsidiary, Chesapeake OnSight Services, LLC (“OnSight”), which has experienced operating losses since its inception in 2004.  OnSight was previously reported as part of the Company’s Other business segment.  At December 31, 2007, the results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. For 2007, the discontinued operations experienced a net loss of $20,000, compared to a net loss of $241,000 for 2006 and a net loss of $231,000 for 2005.
 
- Page 44 -

C. Segment Information
 
The following table presents information about the Company’s reportable segments. The table excludes financial data related to our distributed energy company, which was reclassed to discontinued operations for each year presented.

  
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
Operating Revenues, Unaffiliated Customers
             
Natural gas distribution, transmission and marketing
  $ 180,842,699     $ 170,114,512     $ 166,388,562  
Propane
    62,837,696       48,575,976       48,975,349  
Advanced information services
    14,606,100       12,509,077       14,121,441  
Other
    -       -       -  
Total operating revenues, unaffiliated customers
  $ 258,286,495     $ 231,199,565     $ 229,485,352  
                         
Intersegment Revenues (1)
                       
Natural gas distribution, transmission and marketing
  $ 359,235     $ 259,970     $ 193,404  
Propane
    406       -       668  
Advanced information services
    492,840       58,532       18,123  
Other
    622,272       618,492       618,492  
Total intersegment revenues
  $ 1,474,753     $ 936,994     $ 830,687  
                         
Operating Income
                       
Natural gas distribution, transmission and marketing
  $ 22,485,266     $ 19,733,487     $ 17,235,810  
Propane
    4,497,843       2,534,035       3,209,388  
Advanced information services
    835,981       767,160       1,196,545  
Other and eliminations
    294,492       297,255       279,136  
Operating Income
    28,113,582       23,331,937       21,920,879  
Other income
    291,305       189,093       382,610  
Interest charges
    6,589,639       5,773,993       5,132,458  
Income taxes
    8,597,461       6,999,072       6,472,220  
Net income from continuing operations
  $ 13,217,787     $ 10,747,965     $ 10,698,811  
                         
Depreciation and Amortization
                       
Natural gas distribution, transmission and marketing
  $ 6,917,609     $ 6,312,277     $ 5,682,137  
Propane
    1,842,047       1,658,554       1,574,357  
Advanced information services
    143,706       112,729       122,569  
Other and eliminations
    156,823       160,155       189,146  
Total depreciation and amortization
  $ 9,060,185     $ 8,243,715     $ 7,568,209  
                         
Capital Expenditures
                       
Natural gas distribution, transmission and marketing
  $ 23,086,713     $ 43,894,614     $ 28,433,671  
Propane
    5,290,215       4,778,891       3,955,799  
Advanced information services
    174,184       159,402       294,792  
Other
    1,591,272       321,204       739,079  
Total capital expenditures
  $ 30,142,384     $ 49,154,111     $ 33,423,341  
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
 
                         
At December 31,
 
2007
   
2006
   
2005
 
Identifiable Assets
                       
Natural gas distribution, transmission and marketing
  $ 273,500,890     $ 252,292,600     $ 225,667,049  
Propane
    94,966,212       60,170,200       57,344,859  
Advanced information services
    2,507,910       2,573,810       2,062,902  
Other
    10,533,511       10,503,804       10,911,229  
Total identifiable assets
  $ 381,508,523     $ 325,540,414     $ 295,986,039  
 
 
- Page 45 -

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’s operations are primarily domestic. The advanced information services segment 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. Fair Value of Financial Instruments
 
Various items within the balance sheet are considered to be financial instruments, because they are cash or are to be settled in cash. The carrying values of these items generally approximate their fair value (see Note E to the Consolidated Financial Statements for disclosure of fair value of investments). The Company’s open forward and futures contracts at December 31, 2007 had a gain of $179,000 and at December 31, 2006 had a gain in fair value of $8,500, based on market rates at the respective dates. The fair value of the Company’s long-term debt is estimated using a discounted cash flow methodology. The Company’s long-term debt at December 31, 2007, including current maturities, had an estimated fair value of $75.0 million as compared to a carrying value of $70.9 million. At December 31, 2006, the estimated fair value was approximately $81.4 million as compared to a carrying value of $78.7 million. These estimates are based on published corporate borrowing rates for debt instruments with similar terms and average maturities.

 
E. Investments
 
The investment balances at December 31, 2007 and 2006 represent a Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifies these investments as trading securities. As a result of classifying them as trading securities, the Company is required to report the securities at their fair value, with any unrealized gains and losses included in other income. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust.  At December 31, 2007 and 2006, total investments had a fair value of $1.9 million and $2.0 million, respectively.

 
F. Goodwill and Other Intangible Assets
 
In accordance with SFAS No. 142, goodwill is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. The propane unit had $674,000 in goodwill for the two years ended December 31, 2007 and 2006. Testing for 2007 and 2006 has indicated that no impairment of the goodwill has occurred.
 
The carrying value and accumulated amortization of intangible assets subject to amortization for the years ended December 31, 2007 and 2006 are as follow:

 
   
December 31, 2007
   
December 31, 2006
 
   
Gross Carrying Amount
   
Accumulated Amortization
 
Gross Carrying Amount
   
Accumulated Amortization
 
 Customer lists
  $ 115,333     $ 82,269     $ 115,333     $ 75,057  
 Acquisition costs
    263,659       118,649       263,659       112,057  
 Total
  $ 378,992     $ 200,918     $ 378,992     $ 187,114  
 

Amortization of intangible assets was $14,000 for the years ended December 31, 2007 and 2006. The estimated annual amortization of intangibles is $14,000 per year for each of the years 2008 through 2012.
 
G. Stockholders’ Equity
 
Changes in common stock shares issued and outstanding are shown in the table below:

 
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
Common Stock shares issued and outstanding (1)
                 
Shares issued — beginning of period balance
    6,688,084       5,883,099       5,778,976  
Dividend Reinvestment Plan (2)
    35,333       38,392       41,175  
Retirement Savings Plan
    29,563       29,705       21,071  
Conversion of debentures
    8,106       16,677       22,609  
Employee award plan
    350       350       -  
Performance shares and options exercised (3)
    15,974       29,516       19,268  
Public offering
    -       690,345       -  
Shares issued — end of period balance (4)
    6,777,410       6,688,084       5,883,099  
                         
Treasury shares — beginning of period balance
    -       (97 )     (9,418 )
Purchases
    -       -       (4,852 )
Dividend Reinvestment Plan
    -       -       2,142  
Retirement Savings Plan
    -       -       12,031  
Other issuances
    -       97       -  
Treasury Shares — end of period balance
    -       -       (97 )
                         
Total Shares Outstanding
    6,777,410       6,688,084       5,883,002  
                         
(1) 12,000,000 shares are authorized at a par value of $0.4867 per share.
(2) Includes shares purchased with reinvested dividends and optional cash payments.
(3) Includes shares issued for Directors' compensation.
(4) Includes 57,309, 48,187, and 37,528 shares at December 31, 2007, 2006 and 2005, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.
 
 
- Page 46 -

In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 shares of Chesapeake stock in 2000, at an exercise price of $18.00 per share and 15,000 in 2001 at an exercise price of $18.25 per share. In August 2006, the investment banker exercised the 30,000 warrants pursuant to the terms of the agreement at $33.3657 per share. At the request of the investment banker, Chesapeake settled the warrants with a cash payment of $435,000, in lieu of issuing shares of the Company’s common stock. At December 31, 2007 and 2006, Chesapeake did not have any stock warrants outstanding.

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

  
At December 31,
2007
2006
Uncollateralized senior notes:
   
7.97% note, due February 1, 2008
$0
$1,000,000
6.91% note, due October 1, 2010
               1,818,182
             2,727,273
6.85% note, due January 1, 2012
               3,000,000
             4,000,000
7.83% note, due January 1, 2015
             12,000,000
           14,000,000
6.64% note, due October 31, 2017
             24,545,454
           27,272,727
5.50% note, due October 12, 2020
             20,000,000
           20,000,000
Convertible debentures:
   
8.25%  due March 1, 2014
               1,832,000
             1,970,000
Promissory note
                    60,000
                  80,000
Total Long-Term Debt
$63,255,636
$71,050,000
         
Annual maturities of consolidated long-term debt for the next five years are as follows: $7,656,364 for 2008;
$6,656,364 for 2009,$6,656,364 for 2010, $7,747,273 for 2011, $6,727,273 for 2012.
 
The convertible debentures may be converted, at the option of the holder, into shares of the Company’s common stock at a conversion price of $17.01 per share. During 2007 and 2006, debentures totaling $138,000 and $284,000, 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 2007 and 2006, no debentures were redeemed for cash. During 2005, debentures totaling $5,000 were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.

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

Indentures to the long-term debt of the Company and its subsidiaries contain various restrictions. The most stringent restrictions state that the Company must maintain equity of at least 40 percent of total capitalization, and the pro-forma fixed charge coverage ratio must be 1.5 times. The Company is in compliance with all of its debt covenants.
 
I. Short-term Borrowing
 
The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of December 31, 2007, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $90.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Three of the bank lines, totaling $25.0 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, 2007 and 2006 was $45.7 million and $27.6 million, respectively.  The annual weighted average interest rates on short-term debt were 5.46 percent and 5.47 percent for 2007 and 2006, respectively.

The Company also had a letter 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 lines of credit and is scheduled to expire on May 31, 2008.  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.
 
J. Lease Obligations
 
The Company has entered into several operating lease arrangements for office space at various locations, equipment and pipeline facilities. Rent expense related to these leases was $736,000, $680,000, and $837,000 for 2007, 2006, and 2005, respectively. Future minimum payments under the Company’s current lease agreements are $791,000, $668,000, $544,000, $531,000 and $636,000 for the years 2008 through 2012, respectively; and $2.3 million thereafter, with an aggregate total of $5.4 million.
 
K. Employee Benefit Plans
 
Retirement Plans
 
Before 1999, Company employees generally participated in both a defined benefit pension plan (“Defined 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 is 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 continues to provide appropriate levels of benefits to the Company’s employees, the Board amended the Defined Pension Plan and the Retirement Savings Plan, effective January 1, 2005, so that Defined Pension Plan participants who were actively employed by the Company on that date: (1) receive two additional years of benefit service credit to be used in calculating their Defined Pension Plan benefit (subject to the Defined Pension Plan’s limit of 35 years of benefit service credit), (2) have the option to receive their Defined Pension Plan benefit in the form of a lump sum at the time they retire, and (3) are eligible to receive the enhanced matching contribution in the Retirement Savings Plan. In addition, effective January 1, 2005, the Board amended the Defined Pension Plan so that participants will not accrue any additional benefits under that plan. These changes were communicated to the Company’s employees during the first week of November 2004.
 
- Page 47 -

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

SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. The Company is also required to recognize as a component of accumulated other comprehensive income (“AOCI”) the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit cost, as explained in SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

At December 31, 2007, the funded status of the Company’s Defined Pension Plan was a liability of $274,739; at December 31, 2006 it was an asset of $590,560.  In order to account for the liability and decrease in the funded status in accordance with FAS 158, the Company took a charge of $568,316, net of tax, to Comprehensive Income.  In addition, the funded status of the postretirement health and life insurance plan was a liability of $1.756 million at December 31, 2007 compared to $1.763 million at December 31, 2006.  To adjust for the reduced liability for the postretirement health and life insurance plan, as required by FAS 158, the Company recorded income of $23,086, net of tax, to Comprehensive Income.

The amounts in AOCI for the respective retirement plans that are expected to be recognized as a component of net benefit cost in 2008 are set forth in the following table.

  
         
 
Defined
Executive Excess
Other
 
 
Benefit
Defined Benefit
Postretirement
 
 
Pension
Pension
Benefit
 
Prior service cost (credit)
$(4,699)
-
-  
Loss (gain)
-  $46,444 $130,973  
 
 
Defined Benefit Pension Plan
As described above, effective January 1, 2005, the Defined Pension Plan was frozen with respect to additional years of service or additional compensation. Benefits under the plan were based on each participant’s years of service and highest average compensation, prior to the freeze. The Company’s funding policy provides that payments to the trustee shall be equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The Company does not expect to be required to make any funding payments to the Defined Pension Plan in 2008. The measurement dates for the Pension Plan were December 31, 2007 and 2006.

The following schedule summarizes the assets of the Defined Pension Plan, by investment type, at December 31, 2007, 2006 and 2005:
 

At December 31,
 
2007
   
2006
   
2005
 
Asset Category
                 
Equity securities
  49.03 %   77.34 %   76.12 %
Debt securities
  50.26 %   18.59 %   23.28 %
Other
  0.71 %   4.07 %   0.60 %
Total
  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 invests at least 80 percent of its total assets in:

·  
United States Government obligations; and
·  
Repurchase agreements that are fully collateralized by such obligations.

The investment policy of the Plan calls for an allocation of assets between equity and debt instruments with equity being 60 percent and debt at 40 percent, but allowing for a variance of 20 percent in either direction. 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. During 2004, Chesapeake modified its investment policy to allow the Employee Benefits Committee to reallocate investments to better match the expected life of the plan.

- Page 48 -

The following schedule sets forth the funded status of the Defined Pension Plan at December 31, 2007, 2006 and 2005:

  
At December 31,
 
2007
   
2006
   
2005
 
Change in benefit obligation:
                 
Benefit obligation — beginning of year
  $ 11,449,725     $ 12,399,621     $ 12,053,063  
Interest cost
    622,057       635,877       645,740  
Change in assumptions
    -       (301,851 )     388,979  
Actuarial loss
    282,684       607       28,895  
Benefits paid
    (1,280,946 )     (1,284,529 )     (717,056 )
Benefit obligation — end of year
    11,073,520       11,449,725       12,399,621  
                         
Change in plan assets:
                       
Fair value of plan assets — beginning of year
    12,040,287       11,780,866       12,097,248  
Actual return on plan assets
    39,440       1,543,950       400,674  
Benefits paid
    (1,280,946 )     (1,284,529 )     (717,056 )
Fair value of plan assets — end of year
    10,798,781       12,040,287       11,780,866  
                         
Reconciliation of funded status: (1)
                       
Plan assets in excess (less than) benefit obligation at year-end
    (274,739 )     590,560       (618,755 )
Unrecognized prior service cost
    -       -       (34,259 )
Unrecognized net actuarial gain
    -       -       (129,739 )
Net amount accrued
  $ (274,739 )   $ 590,560     $ (782,753 )
                         
Assumptions:
                       
Discount rate
    5.50 %     5.50 %     5.25 %
Expected return on plan assets
    6.00 %     6.00 %     6.00 %
                         
(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.
 
 
The Company reviewed the assumptions used for the discount rate to calculate the benefit obligation of the plan and has elected to maintain the rate at 5.50 percent, reflecting relatively no change in the interest rates of high quality bonds and reflecting the expected life of the plan, in light of the lump sum payment option. In addition, the average expected return on plan assets for the Defined Pension Plan remained constant at six percent due to the adoption of a change in the investment policy that allows for a higher level of investment in bonds and a lower level of equity investments. Since the Plan is frozen in regard additional years of service and compensation, the rate of assumed compensation rate increases is not applicable. The accumulated benefit obligation was $11.1 million and $11.4 million at December 31, 2007 and 2006, respectively.

Net periodic pension benefit for the Defined Pension Plan for 2007, 2006, and 2005 include the components as shown below:


For the Years Ended December 31,
2007
2006
2005
Components of net periodic pension cost:
     
Interest cost
$622,057
$635,877
$645,740
Expected return on assets
              (696,398)
              (690,533)
              (703,285)
Amortization of:
     
Prior service cost
                  (4,699)
                  (4,699)
                  (4,699)
Net periodic pension benefit
($79,040)
($59,355)
($62,244)
       
Assumptions:
     
Discount rate
5.50%
5.25%
5.50%
Expected return on plan assets
6.00%
6.00%
6.00%
 

Executive Excess Defined Benefit Pension Plan
The Company also provides an unfunded executive excess defined benefit pension plan (“Pension SERP”). As noted above, 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 was $2.32 million and $2.29 million at December 31, 2007 and 2006, respectively.

 
- Page 49 -

The following schedule sets forth the status of the Pension SERP:

  
At December 31,
 
2007
   
2006
   
2005
 
Change in benefit obligation:
                 
Benefit obligation — beginning of year
  $ 2,286,970     $ 2,322,471     $ 2,162,952  
Interest cost
    123,361       119,588       119,658  
Actuarial (gain) loss
    5,123       (65,886 )     133,839  
Benefits paid
    (89,204 )     (89,203 )     (93,978 )
Benefit obligation — end of year
    2,326,250       2,286,970       2,322,471  
                         
Change in plan assets:
                       
Fair value of plan assets — beginning of year
    -       -       -  
Employer contributions
    89,204       89,203       93,978  
Benefits paid
    (89,204 )     (89,203 )     (93,978 )
Fair value of plan assets — end of year
    -       -       -  
                         
Funded status
    (2,326,250 )     (2,286,970 )     (2,322,471 )
Unrecognized net actuarial loss
    -       -       959,492  
Net amount accrued (1)
  $ (2,326,250 )   $ (2,286,970 )   $ (1,362,979 )
                         
Assumptions:
                       
Discount rate
    5.50 %     5.50 %     5.25 %
                         
(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.
 
 

The Company reviewed the assumptions used for the discount rate of the plan to calculate the benefit obligation and has elected to maintain the rate at 5.50 percent, reflecting relatively no change in the interest rates of high quality bonds 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, 2007 and 2006.
 
Net periodic pension costs for the Pension SERP for 2007, 2006, and 2005 include the components as shown below:

     
For the Years Ended December 31,
2007
 
2006
 
2005
 
Components of net periodic pension cost:
           
Service cost
$ 0   $ 0   $ 0  
Interest cost
  123,361     119,588     119,658  
Amortization of:
                 
Actuarial loss
  51,734     57,039     49,319  
Net periodic pension cost
$ 175,095   $ 176,627   $ 168,977  
                   
Assumptions:
                 
Discount rate
  5.50 %   5.25 %   5.50 %


Other Postretirement Benefits
The Company sponsors a defined benefit 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,
 
2007
   
2006
   
2005
 
Change in benefit obligation:
                 
Benefit obligation — beginning of year
  $ 1,763,108     $ 1,534,684     $ 1,599,280  
Retirees
    56,123       264,470       (59,152 )
Fully-eligible active employees
    21,012       (114,082 )     (31,761 )
Other active
    (84,679 )     78,036       26,317  
Benefit obligation — end of year
  $ 1,755,564     $ 1,763,108     $ 1,534,684  
                         
Change in plan assets:
                       
Fair value of plan assets — beginning of year
    -       -       -  
Employer contributions
    243,660       300,360       89,238  
Plan participant's contributions
    100,863       94,914       72,866  
Benefits paid
    (344,523 )     (395,274 )     (162,104 )
Fair value of plan assets — end of year
    -       -       -  
                         
                         
Funded status
  $ (1,755,564 )   $ (1,763,108 )   $ (1,534,684 )
Unrecognized transition obligation
    -       -       22,282  
Unrecognized net actuarial loss
    -       -       751,450  
Net amount accrued (1)
  $ (1,755,564 )   $ (1,763,108 )   $ (760,952 )
                         
Assumptions:
                       
Discount rate
    5.50 %     5.50 %     5.25 %
                         
(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.
 
 
- Page 50 -

Net periodic postretirement costs for 2007, 2006 and 2005 include the following components:

 
For the Years Ended December 31,
 
2007
   
2006
   
2005
 
Components of net periodic postretirement cost:
             
Service cost
  $ 6,203     $ 9,194     $ 6,257  
Interest cost
    101,776       93,924       77,872  
Amortization of:
                       
Transition obligation
    -       22,282       27,859  
Actuarial loss
    166,423       144,694       88,291  
Net periodic postretirement cost
  $ 274,402     $ 270,094     $ 200,279  
 

The health care inflation rate for 2007 to calculate the benefit obligation is assumed to be 5.5 percent for medical and 7 percent for prescription drugs. These rates are projected to decrease to ultimate rates of five and six percent, respectively, by the year 2009. A one percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $242,000 as of January 1, 2008, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2008 by approximately $15,000. A one percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $200,000 as of January 1, 2008, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2008 by approximately $12,000. The measurement dates were December 31, 2007 and 2006.

Estimated Future Benefit Payments
The schedule below shows the estimated future benefit payments for each of the years 2008 through 2012 and the aggregate of the next five years for each of the plans previously described.
 

   
Defined Benefit Pension Plan (1)
   
Executive Excess Defined Benefit Pension Plan (2)
   
Other Post-Retirement Benefits (2)
 
2008
  $ 734,940     $ 87,959     $ 196,449  
2009
    1,363,074       86,586       199,250  
2010
    921,490       85,081       208,938  
2011
    437,213       83,444       195,679  
2012
    1,332,896       113,415       204,524  
Years 2013 through 2017
    3,755,455       835,415       1,081,460  
                         
(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
 
(2) Benefit payments are expected to be paid out of the general funds of the Company.
 
 
 
Retirement Savings Plan
The Company sponsors a 401(k) Retirement Savings Plan, which provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions of up to 15 percent of eligible base compensation, subject to Internal Revenue Service limitations. These participants were eligible for the enhanced matching described below, effective January 1, 2005.

Effective January 1, 1999, the Company began offering an enhanced 401(k) Plan to all new employees, as well as existing employees who elected to no longer participate in the Defined Pension Plan. The Company makes matching contributions of up to six percent of each employee's pre-tax compensation for the year, except for the employees of our Advanced Information Services segment. The match is between 100 percent and 200 percent of the employee’s contribution, 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’s 401(k) Plan according to each employee’s election options.

Effective July 1, 2006, the Company’s contribution made on behalf of Advanced Information Services segment employees, is a 50 percent matching contribution, up to six percent of the employee’s annual compensation. The matching contribution is funded in Chesapeake common stock. The Plan 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 segment has any dollars available for profit-sharing is dependent upon the extent to which actual earnings exceed budgeted earnings. Any profit-sharing dollars made available to employees can be deferred into the Plan and/or paid out in the form of a bonus.

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

Effective January 1, 1999, the Company began offering a non-qualified supplemental employee retirement savings plan (“401(k) SERP”) open to Company executives over a specific income threshold. Participants receive cash only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the twenty-one mutual funds available for investment. These same funds are available for investment of employee contributions within the Retirement Savings Plan.  All obligations arising under the 401(k) SERP are payable from the general assets of Chesapeake, although Chesapeake has established a Rabbi Trust to help pay benefits under the 401(k) SERP.  As discussed further in Note E – “Investments,” to the Consolidated Financial Statements, the assets held in the Rabbi Trust had a fair value of $1.9 million and $2.0 million at December 31, 2007 and 2006, respectively.  The assets of the Rabbi Trust are at all times subject to the claims of Chesapeake’s general creditors.

The Company’s contributions to the 401(k) plans totaled $1.48 million, $1.61 million, and $1.68 million for the years ended December 31, 2007, 2006, and 2005, respectively. As of December 31, 2007, there are 47,916 shares reserved to fund future contributions to the Retirement Savings 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 part or all of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors' fees.  At December 31, 2007, the Deferred Compensation Plan consists solely of shares of common stock related to the deferral of executive performance shares and directors’ stock retainers.
 
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 shall be paid in cash.  All deferrals of executive performance shares and directors’ stock retainers shall be paid in shares of the Company’s common stock, except that cash shall be paid in lieu of fractional shares.
 
- Page 51 -

The Company established a Rabbi Trust in connection with the Deferred Compensation Plan. The value of the Company’s 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 $1.4 million and $1.1 million at December 31, 2007 and 2006, respectively.
 
L. Share-Based Compensation Plans
 
The Company accounts for its share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments” (“SFAS 123R”), which requires companies to record compensation costs for all share-based awards over the respective service period for employee services 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, after tax, related to share-based compensation expense, for the restricted stock awards issued under the DSCP and the PIP.
 
 
For the year ended December 31,
 
2007
   
2006
   
2005
 
                   
Directors Stock Compensation Plan
  $ 110,360     $ 100,860     $ 83,980  
Performance Incentive Plan
    493,510       332,110       439,580  
                         
Amounts included in net income, after tax
  $ 603,870     $ 432,970     $ 523,560  


Stock Options
The Company did not have any stock options outstanding at December 31, 2007 or December 31, 2006, nor were any stock options issued during 2007 and 2006.

Directors Stock Compensation Plan
Under the DSCP, each non-employee director of the Company received in 2007 an annual retainer of 600 shares of common stock and an additional 150 shares of common stock for services as a committee chairman. Shares issued under the DSCP are fully vested as of the date of the grant.  The Company records a prepaid expense as of the date of the grant equal to the fair value of the shares issued and amortizes the expense equally over a service period of one year.
 
A summary of restricted stock activity under the DSCP for the three years of 2007, 2006, and 2005 is presented below:

 
             
   
Number of Restricted Shares
   
Weighted Average Grant Date Fair Value
 
Outstanding — December 31, 2004
    -        
Issued — May 5, 2005
    5,850     $ 24.68  
Vested
    5,850          
Outstanding — December 31, 2005
    -          
Issued — May 2, 2006
    5,850     $ 30.02  
Vested
    5,850          
Outstanding — December 31, 2006
    -          
Issued — May 2, 2007
    5,850     $ 31.38  
Vested
    5,850          
Outstanding — December 31, 2007
    -          
 

Compensation expense related to DSCP awards recorded by the Company for the years 2007, 2006, and 2005 is presented in the following table:
 
 
For the year ended December 31,
2007
 
2006
 
2005
           
Compensation expense for DSCP
 $        180,920
 
 $        165,340
 
 $        137,670
           
 

 
As of December 31, 2007, there were 57,450 shares reserved for issuance under the terms of the Company’s DSCP.
 
Performance Incentive Plan (“PIP”)
The Company’s 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’s common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions. The shares granted under the PIP are fully vested, and the fair value of each share is equal to the market price of the Company’s common stock on the date of grant.

- Page 52 -

A summary of restricted stock activity under the PIP for the three years of 2007, 2006, and 2005 is presented below:
 

   
Number of Restricted Shares
   
Weighted Average Grant Date Fair Value
 
Outstanding — December 31, 2004
    -        
Issued — February 24, 2005
    10,130     $ 27.00  
Vested
    10,130          
Outstanding — December 31, 2005
    -          
Issued — February 23, 2006
    23,666     $ 30.40  
Vested
    23,666          
Outstanding — December 31, 2006
    -          
Issued — March 1, 2007
    10,124     $ 30.89  
Vested
    10,124          
Outstanding — December 31, 2007
    -          
 
Compensation expense related to the PIP recorded by the Company during the three years of 2007, 2006, and 2005 is presented in the following table:

 
For the year ended December 31,
2007
 
2006
 
2005
           
Compensation expense for PIP
 $        809,030
 
 $        544,450
 
 $        720,630
           
 

As of December 31, 2007, there were 389,876 shares reserved for issuance under the terms of the Company’s PIP.
 
M. Environmental Commitments and Contingencies
 
Chesapeake is subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.
 
In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former manufactured gas plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former manufactured gas plant sites located in Maryland and Florida. The Company has accrued liabilities for the three sites referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites. The Company has been in discussions with the Maryland Department of the Environment (“MDE”) regarding a fourth former manufactured gas plant site located in Cambridge, Maryland. The following discussion provides details of each site.

Dover Gas Light Site
The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action obligation related to this site and relieves Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to the EPA is received that indicates the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the 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 incurred have been paid. The Company does not expect any future environmental expenditure for this site. Through December 31, 2007, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through December 2007 from other parties or through rates. As of December 31, 2007, a regulatory liability of approximately $294,500, representing the over-recovery portion of the clean-up costs, has been recorded. The over-recovery is temporary and will be refunded by the Company to customers in future rates.

Salisbury Town Gas Light Site
In cooperation with the MDE, the Company has completed remediation of the Salisbury Town Gas Light site, located in Salisbury, Maryland, where it was determined that a former manufactured gas plant had caused localized ground-water contamination. During 1996, the Company completed construction and began Air Sparging and Soil-Vapor Extraction (“AS/SVE”) remediation procedures. Chesapeake has been reporting 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 that is being maintained for continued product monitoring and recovery. Chesapeake has requested a No Further Action determination and is awaiting such a determination from the MDE.

Through December 31, 2007, the Company has incurred approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $1.88 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover, through its rates charged to customers, the remaining $1.02 million of the incurred environmental remediation costs.
 
Winter Haven Coal Gas Site
The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed 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 work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the 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 FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.

In the third quarter of 2007, the Company performed an updated environmental review of this site, including a review of any potential liabilities related to the investigation and remediation actions.  Based on this review, the Company increased its liability by approximately $700,000 for the updated estimate of costs to remediate this site.  Through December 31, 2007, the Company has incurred approximately $1.8 million of environmental costs associated with this site.  At December 31, 2007, the Company had accrued a liability of $835,000 related to this site, offsetting (a) $15,000 collected through rates in excess of costs incurred and (b) a regulatory asset of approximately $851,000, representing the uncollected portion of the estimated clean-up costs. The Company expects to recover the remaining clean-up costs through rates.

The FDEP has indicated that the Company 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 objects to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’s early estimates indicate that some of the corrective measures discussed by the FDEP may cost as much as $1 million. Given the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitude are unwarranted and plans to oppose any requirement that it 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 has not recorded a liability for sediment remediation. The outcome of this matter cannot be predicted at this time.
 
Other
The Company is in discussions with the MDE regarding a manufactured gas plant 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.
 
- Page 53 -

 
N. Other Commitments and Contingencies
 
Natural Gas and Propane Supply
The Company’s natural gas and propane distribution operations have entered into contractual commitments to purchase gas from various suppliers. The contracts have various expiration dates. In April 2007, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity.  This new contract expires on March 31, 2008.  PESCO is currently in the process of obtaining and reviewing supply proposals from suppliers and anticipates executing agreements prior to the existing contracts.

Corporate Guarantees
The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2007 totaled $24.2 million, with the guarantees expiring on various dates in 2008.  No guarantees were recorded by the Company in 2007.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2008. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies.  There have been no draws on this letter of credit as of December 31, 2007.

Internal Revenue Service Audit
In November 2007, the Company was notified by the Internal Revenue Service (“IRS”) that its consolidated federal income tax return for the year ended December 31, 2005 has been selected for examination. The IRS audit is ongoing and is expected to be completed in the second quarter of 2008.  The outcome of this audit cannot be determined at this time; therefore, the Company has not recorded any reserves for potential assessments that may result from the examination.

Other
The Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on the consolidated financial position, results of operations or cash flows of the Company.
 
O. 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. 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
 
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  
                                 
2006
                               
Operating Revenue
  $ 90,950,160     $ 44,303,239     $ 35,141,531     $ 60,804,636  
Operating Income
  $ 11,535,195     $ 3,303,448     $ 322,672     $ 8,170,621  
Net Income (Loss)
  $ 6,096,416     $ 1,132,509     $ (656,579 )   $ 3,934,179  
Earnings per share:
                               
Basic
  $ 1.03     $ 0.19     $ (0.11 )   $ 0.63  
Diluted
  $ 1.01     $ 0.19     $ (0.11 )   $ 0.62  
                                 
 

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
 
On March 20, 2007, the Audit Committee of the Board of Directors of Chesapeake Utilities Corporation (the “Company”) dismissed PricewaterhouseCoopers LLP (“PwC”) as the Company's independent registered public accounting firm.

The reports of PwC on the consolidated financial statements of the Company for the years ended December 31, 2006 and 2005 did not contain an adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principle.

During the years ended December 31, 2006 and 2005 and through March 20, 2007, there have been no (a) disagreements, as described under Item 304(a)(1)(iv) of Regulation S-K, with PwC on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of PwC, would have caused PwC to make reference thereto in their reports on the Company’s consolidated financial statements for such years, or (b) reportable events, as described under Item 304(a)(1)(v) of Regulation S-K.

The Company engaged Beard Miller Company LLP as its new independent registered public accounting firm. During the years ended December 31, 2006 and 2005 and through March 20, 2007, the Company had not consulted with Beard Miller Company LLP on any matters or events described in Item 304(a)(2) (i) and (ii) of Regulation S-K.
 
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) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2007. 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, 2007.

Changes in Internal Controls
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, 2007, that materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

- Page 54 -

CEO and CFO Certifications
The Company’s Chief Executive Officer as well as the Senior Vice President and Chief Financial Officer have filed with the Securities and Exchange Commission 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, 2007. In addition, on May 27, 2007, the Company’s CEO certified to the New York Stock Exchange 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, have audited and issued their report on effectiveness of the Company’s internal control over financial reporting. That report appears below. 
 
 
- Page 55 -

 
 
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, 2007, based on criteria established in Internal Control—Integrated Framework issued 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.
 
 
In our opinion, Chesapeake Utilities Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued 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 sheet of Chesapeake Utilities Corporation as of December 31, 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, cash flows and income taxes for the year then ended, and our report dated March 10, 2008 expressed an unqualified opinion.
 
 
/s/ Beard Miller Company LLP
————————————————
Beard Miller Company LLP
Reading, Pennsylvania
March 10, 2008

 
- Page 56 -



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 of Directors,” “Information Regarding the Board of 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, 2008 in connection with the Company’s Annual Meeting to be held on May 1, 2008.

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, 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.

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, 2008, in connection with the Company’s Annual Meeting to be held on May 1, 2008.
 
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 Ownership of Chesapeake’s Securities” to be filed not later than March 31, 2008 in connection with the Company’s Annual Meeting to be held on May 1, 2008.

The following table sets forth information, as of December 31, 2007, with respect to compensation plans of Chesapeake and its subsidiaries, under which shares of Chesapeake common stock are authorized for issuance:

 
                           
   
( a )
 
( b )
 
( c )
 
   
Number of securities to be issued upon exercise of outstanding options, warrants and rights
 
Weighted-average exercise price of outstanding options, warrants and rights
 
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)
 
Equity compensation plans approved by security holders
    0       (1)         471,626       (2)  
                                   
Equity compensation plans not approved by security holders
    0       (3)                    
                                   
Total
    0                            
                                   
(1) All options to purchase shares under the 1992 Performance Incentive Plan, as amended, were exercised as of 12/31/05.
 
                                   
(2) Includes 389,876 shares under the 2005 Performance Incentive Plan, 57,450 shares available under the 2005 Directors Stock Compensation Plan, and 24,300 shares available under the 2005 Employee Stock Awards Plan.
 
                                   
(3) All warrants were exercised in 2006.
                           

 
Item 13. Certain Relationships and Related Transactions, and Director Independence.
 
None
 
- Page 57 -

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 Public Accounting Firm” to be filed not later than March 31, 2008, in connection with the Company’s Annual Meeting to be held on May 1, 2008.
 
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, 2007, 2006 and 2005;
 
·  
Consolidated Balance Sheets at December 31, 2007 and December 31, 2006;
 
·  
Consolidated Statements of Cash Flows for each of the three years ended December 31, 2007, 2006, and 2005;
 
·  
Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2007, 2006, and 2005;
 
·  
Consolidated Statements of Comprehensive Income for each of the three years ended December 31, 2007, 2006, and 2005;
 
·  
Consolidated Statements of Income Taxes for each of the three years ended December 31,2007, 2006, and 2005;
 
·  
Notes to the Consolidated Financial Statements.
 
 
 
2.
Financial Statement Schedule:
·  
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.
 
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’s common stock, is incorporated herein by reference to Exhibit 1.1 of the Company’s Current Report on Form 8-K, filed November 16, 2007, 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’s 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 12, 2007, is filed herewith.
 
· Exhibit 4.1  
Form of Indenture between the Company 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’s Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989.
 
· Exhibit 4.2  
Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593.
 
· Exhibit 4.3  
Note Purchase Agreement, entered into by the Company on October 2, 1995, pursuant to which the Company 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 Company hereby agrees to furnish a copy of that agreement to the SEC upon request.
 
· Exhibit 4.4  
Note Purchase Agreement, entered into by the Company on December 15, 1997, pursuant to which the Company 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 Company hereby agrees to furnish a copy of that agreement to the SEC upon request.
 
· Exhibit 4.5  
Note Purchase Agreement entered into by the Company on December 27, 2000, pursuant to which the Company 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 Company hereby agrees to furnish a copy of that agreement to the SEC upon request.
 
· Exhibit 4.6  
Note Agreement entered into by the Company on October 31, 2002, pursuant to which the Company privately placed $30 million of its 6.64% Senior Notes, due in 2017, is incorporated herein by reference to Exhibit 2 of the Company’s Current Report on Form 8-K, filed November 6, 2002, File No. 001-11590.
 
· Exhibit 4.7  
Note Agreement entered into by the Company on October 18, 2005, pursuant to which the Company, 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’s Annual Report on Form 10-K for the year ended December 31, 2005, File No. 001-11590.
 
· 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’s 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’s 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’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.
 
· 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’s 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’s Proxy Statement dated March 28, 2005,  in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.
 
· Exhibit 10.3*  
Chesapeake Utilities Corporation Employee Stock Award Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005, in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.
 
· Exhibit 10.4*  
Chesapeake Utilities Corporation Performance Incentive Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005, in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.
 
· Exhibit 10.5*  
Deferred Compensation Program (amended and restated as of December 7, 2006) is incorporated herein by reference to Exhibit 10 of the Company’s Current Report on Form 8-K, filed December 13, 2006, File No. 001-11590.
 
· Exhibit 10.6*  
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’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.
 
· Exhibit 10.7*  
Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.
 
· Exhibit 10.8*  
Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.9 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.
 
· Exhibit 10.9*  
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 10.10*  
*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 10.11*  
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, filed herewith.
 
· Exhibit 10.12*  
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 filed herewith.
 
· Exhibit 10.13*  
Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.
 
· Exhibit 10.14*  
Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.
 
· Exhibit 10.15*  
Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.
 
· Exhibit 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 Stephen C. Thompson, is filed herewith.
 
· Exhibit 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 Beth W. Cooper, is filed herewith.
 
· Exhibit 10.18*  
Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.
 
· Exhibit 10.19*  
Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.
 
· Exhibit 10.20*  
Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.
 
- Page 58 -

· Exhibit 12  
Computation of Ratio of Earning to Fixed Charges is filed herewith.
 
· 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.
 
· Exhibit 14.2  
Business Code of Ethics and Conduct is filed herewith.
 
· Exhibit 16  
Letter Regarding Change in Certifying Accountant is filed herewith.
 
· Exhibit 21  
Subsidiaries of the Registrant is filed herewith.
 
· Exhibit 22  
Published Report Regarding Matters Submitted to Vote of Security Holders is incorporated herein by reference to Part II, Item 4 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2006, File No. 001-11590.
 
· Exhibit 23.1  
Consent of Independent Registered Public Accounting Firm is filed herewith.
 
· Exhibit 23.2  
Consent of Preceding Independent Registered Public Accounting Firm for years 2006 and 2005 is filed herewith.
 
· Exhibit 31.1  
Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 10, 2008, is filed herewith.
 
· Exhibit 31.2  
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 10, 2008, is filed herewith.
 
· Exhibit 32.1  
Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 10, 2008, 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 10, 2008, is filed herewith.
 
 
* Management contract or compensatory plan or agreement.
 
- Page 59 -

 
Signatures
 

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

Chesapeake Utilities Corporation

By:         /s/ John R. Schimkaitis
  John R. Schimkaitis
  President and Chief Executive Officer
              Date:  March 10, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/  Ralph J. Adkins                                                                        /s/  John R. Schimkaitis
Ralph J. Adkins, Chairman of the Board                                      John R. Schimkaitis, President,
and Director                                                                                     Chief Executive Officer and Director
Date:  February 20, 2008                                                                 Date:  March 10, 2008

/s/  Michael P. McMasters                                                        /s/  Richard Bernstein
Michael P. McMasters, Senior Vice President                           Richard Bernstein, Director
and Chief Financial Officer                                                            Date:  February 20, 2008
(Principal Financial and Accounting Officer)
Date:  March 10, 2008

/s/  Eugene H. Bayard                                                                   /s/  Thomas J. Bresnan
Eugene H. Bayard, Director                                                           Thomas J. Bresnan, Director
Date:  February 20, 2008                                                                 Date:  March 10, 2008

/s/  Thomas P. Hill, Jr.                                                                  /s/  Walter J. Coleman
Thomas P. Hill, Jr., Director                                                            Walter J. Coleman, Director
Date:  February 20, 2008                                                                  Date:  February 20, 2008

/s/  J. Peter Martin                                                                        /s/  Joseph E. Moore, Esq.
J. Peter Martin, Director                                                                   Joseph E. Moore, Esq., Director
Date:  February 20, 2008                                                                   Date:  February 20, 2008

/s/  Calvert A. Morgan, Jr.
Calvert A. Morgan, Jr., Director
Date:  February 20, 2008



 
 
- Page 60 -

 

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 10, 2008 relating to the consolidated financial statements of Chesapeake Utilities Corporation as of December 31, 2007 and for the year then ended, which is contained in Item 8 of this Form 10-K also included the audit of the financial statement schedules listed in Item 15.  These financial statement schedules are the responsibility of the Chesapeake Utilities Corporation’s management.  Our responsibility is to express an opinion on these financial statement schedules based on our audit.
 
In our opinion such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.




/s/ Beard Miller Company LLP
————————————————
Beard Miller Company LLP
Reading, Pennsylvania
March 10, 2008



 
 

 


 
Chesapeake Utilities Corporation and Subsidiaries
 
Schedule II
 
Valuation and Qualifying Accounts
 
                               
                               
                               
                               
         
Additions
             
For the Year Ended December 31,
 
Balance at Beginning of Year
   
Charged to Income
   
Other Accounts (1)
   
Deductions (2)
   
Balance at End of Year
 
Reserve Deducted From Related Assets
                         
Reserve for Uncollectible Accounts
                             
2007
  $ 661,597     $
818,561
    $ 26,190     $ (554,273 )   $ 952,075  
2006
  $ 861,378     $ 381,424     $ 65,519     $ (646,724 )   $ 661,597  
2005
  $ 610,819     $ 632,644     $ 158,409     $ (540,494 )   $ 861,378  
                                         
                                         
(1)  Recoveries.
                                       
(2) Uncollectible accounts charged off.
                                 
 

 
 
 

 


 
Upon written request,
Chesapeake will provide, free of
charge, a copy of any exhibit to
the 2007 Annual Report on
Form 10-K not included
in this document.