Edgar Filing: CHESAPEAKE UTILITIES CORP

Chesapeake Utilities Corporation Annual Report on Form 10-K - FY Ended December 31, 2006

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, 2006

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)

State of Delaware	51-0064146
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]

Indicate by 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, 2006, the last business day of its most recently completed second fiscal quarter, based on the last trade price on that date, as reported by the New York Stock Exchange, was approximately $179.2 million.

As of March 8, 2007, 6,717,348 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2007 Annual Meeting of Stockholders are incorporated by reference in Part III.

Chesapeake Utilities Corporation

Form 10-K

YEAR ENDED DECEMBER 31, 2006

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	1
Item 1A. Risk Factors	8
Item 1B. Unresolved Staff Comments	12
Item 2. Properties	12
Item 3. Legal Proceedings	12
Item 4. Submission of Matters to a Vote of Security Holders	12
Part II	13
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6. Selected Financial Data	16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	45
Item 8. Financial Statements and Supplementary Data	45
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	76
Item 9A. Controls and Procedures	76
Item 9B. Other Information	76
Part III	77
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance	77
Item 11. Executive Compensation	77
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	77
Item 13. Certain Relationships and Related Transactions, and Director Independence	78
Item 14. Principal Accounting Fees and Services	78
Part IV	79
Item 15. Exhibits, Financial Statement Schedules	79
Signatures	83

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 Development of Business

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’s three natural gas distribution divisions serve approximately 59,100 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 366-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. Our propane distribution operation serves approximately 33,300 customers in central and southern Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania, and parts of Florida. The advanced information services segment provides domestic and international clients with information technology related business services and solutions for both enterprise and e-business applications.

(b)

Financial Information about Industry Segments

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

(c)

Narrative Description of Business

Chesapeake is engaged in three primary business activities: natural gas distribution, transmission and marketing, propane distribution and wholesale marketing and advanced information services. In addition to the primary groups, Chesapeake has subsidiaries in other related businesses.

(i) (a) Natural Gas Distribution, Transmission and Marketing

General

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

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Delaware and Maryland. Chesapeake’s Delaware and Maryland utility divisions serve approximately 45,400 customers, of which approximately 45,200 are residential and commercial customers purchasing gas primarily for heating purposes. The remaining customers are industrial. For the year 2006, residential and commercial customers accounted for approximately 77% of the volume delivered by the divisions and 75% of the divisions’ revenue.

Florida. The Florida division distributes natural gas to approximately 13,630 residential and commercial and 100 industrial customers in the 13 Counties of Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee, Liberty, Washington and Citrus. Currently, the industrial customers, which purchase and transport gas on a firm basis, account for approximately 92% of the volume delivered by the Florida division and 43% of the revenues. These customers are primarily engaged in the citrus and phosphate industries and in electric cogeneration.

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

Eastern Shore. The Company’s wholly owned transmission subsidiary, Eastern Shore, owns and operates an interstate natural gas pipeline and provides open access transportation services for affiliated and non-affiliated companies through an integrated gas pipeline 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. Eastern Shore’s rates and services are subject to regulation by the Federal Energy Regulatory Commission (“FERC”).

Adequacy of Resources

General. The Delaware and Maryland divisions have both firm and interruptible contracts with four interstate “open access” pipelines including Eastern Shore. The divisions are directly interconnected with Eastern Shore and services upstream of Eastern Shore are contracted with Transcontinental Gas Pipeline Corporation (“Transco”), Columbia Gas Transmission Corporation (“Columbia”) and Columbia Gulf Transmission Company (“Gulf”). None of the upstream service providers are affiliates 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 supply on the spot market from various suppliers. This gas is transported by the upstream pipelines and delivered to the divisions’ interconnects with Eastern Shore. The divisions also have the capability to use propane-air peak-shaving to supplement or displace the spot market purchases. The Company believes that the availability of gas supply and transportation to the Delaware and Maryland divisions is adequate under existing arrangements to meet the anticipated needs of their customers.

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

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

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

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

The Delaware division currently has contracts for the purchase of firm natural gas supply with several suppliers. These supply contracts provide the availability of a maximum firm daily entitlement of 37,500 Dt and delivered on Transco, Columbia, and/or Gulf systems to Eastern Shore for redelivery under firm transportation contracts. The gas purchase contracts have various expiration dates and daily quantities may vary from day to day and month to month.

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

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

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The Maryland division’s contract with Gulf, which expires in 2009, provides firm transportation capacity of 590 Dt per day for the period November through March and 543 Dt per day for the period April through October.

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

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

Florida. The Florida division receives natural gas from Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System (“Gulfstream”). The Florida division has firm transportation agreements with both of these interstate pipelines. All of the capacity under these agreements has been released to various third parties and PESCO, our natural gas marketing subsidiary. Under terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream should the party that acquired the capacity through release fail to pay for the service.

Chesapeake’s contracts with FGT include transportation service for: (a) daily firm transportation capacity of 27,519 Dt in November through April; 21,123 Dt in May through September, and 27,105 Dt in October, which expires in 2010; and (b) daily firm transportation capacity of 1,000 Dt daily, which expires in 2015.

Chesapeake’s contracts with Gulfstream include transportation service for daily firm transportation capacity of 10,000 Dt daily. The contract with Gulfstream expires May 31, 2022.

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

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

Eastern Shore has retained the firm transportation capacity and firm storage services described above in order to provide swing transportation service and storage service to those customers that requested such service.

Competition

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

Rates and Regulation

General. Chesapeake’s natural gas distribution divisions are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions with respect to various aspects of the 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 costs and normally allow eventual full recovery of gas costs. Adjustments under these mechanisms, which are limited to gas costs, require periodic filings and hearings with the relevant regulatory authority.

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Eastern Shore is subject to regulation by the FERC as an interstate pipeline. The FERC regulates the provision of service, 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 in each jurisdiction in order to ensure the timely filing of rate cases.

Regulatory Proceedings

See discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis — Regulatory Activities.”

(i) (b) Propane Distribution and Wholesale Marketing

General

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

Propane is a form of liquefied petroleum gas, which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is a gas at normal pressure, it is easily compressed into liquid form for storage and transportation. Propane is a clean-burning fuel, gaining increased recognition for its environmental superiority, safety, efficiency, transportability and ease of use relative to alternative forms of energy. Propane is sold primarily in suburban and rural areas, which are not served by natural gas distributors. Demand is typically much higher in the winter months and is significantly affected by seasonal variations, particularly the relative severity of winter temperatures, because of its use in residential and commercial heating.

During 2006, our propane distribution operations served approximately 33,300 propane customers on the Delmarva Peninsula, southeastern Pennsylvania and in Florida and delivered approximately 24.2 million retail and wholesale gallons of propane.

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

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

Adequacy of Resources

The Company’s propane distribution operations purchase propane primarily from suppliers, including major oil companies and independent producers of natural gas liquids. Supplies of propane from these and other sources are readily available for purchase by the Company. Supply contracts generally include minimum (not subject to take-or-pay premiums) and maximum purchase provisions.

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The Company’s propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to its bulk storage facilities. From these facilities, propane is delivered primarily by “bobtail” trucks, owned and operated by the Company, to tanks located at the customer’s premises.

Xeron does not own physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.

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 under the Federal Motor Carrier Safety Act, which is administered by 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 all 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.

(i) (c) Advanced Information Services

General

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

(ii) Seasonal Nature of Business

Revenues from the Company’s residential and commercial natural gas sales and from its propane distribution activities are affected by seasonal variations, since the majority of these sales are to customers using the fuels for heating purposes. Revenues from these customers are accordingly affected by the mildness or severity of the heating season.

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(iii) Capital Budget

A discussion of capital expenditures by business segment and capital expenditures for environmental control facilities are included in Item 7 under the heading “Management Discussion and Analysis — Liquidity and Capital Resources.”

(iv) Employees

As of December 31, 2006, Chesapeake had 437 employees, including 193 in natural gas, 142 in propane and 70 in advanced information services. The remaining 32 employees are considered general and administrative and include officers of the Company, treasury, accounting, internal audit, information technology, human resources and other administrative personnel.

(v) Executive Officers of the Registrant

Information pertaining to the executive officers of the Company is as follows:

John R. Schimkaitis (age 59) Mr. Schimkaitis is President and Chief Executive Officer of Chesapeake and its subsidiaries. Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. He has served as President since 1997. Prior to this, Mr. Schimkaitis served as President and Chief Operating Officer, Executive Vice President, Senior Vice President, Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer and Assistant Secretary of Chesapeake.

Michael P. McMasters (age 48) Mr. McMasters is Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation. He was appointed Senior Vice President in 2004 and has served as Chief Financial Officer since December 1996. He has previously held the positions of Vice President, Treasurer, Director of Accounting and Rates, and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company.

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

Beth W. Cooper (age 40) Ms. Cooper is Vice President, Treasurer and Corporate Secretary of Chesapeake Utilities Corporation. Ms. Cooper has served as Corporate Secretary since July 2005. She previously served as Assistant Treasurer and Assistant Secretary, Director of Internal Audit, Director of Strategic Planning, Planning Consultant, Accounting Manager for Non-regulated Operations and Treasury Analyst. Prior to joining Chesapeake, she was employed as an auditor with Ernst & Young’s Entrepreneurial Services Group.

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

(vi) Financial Information about Geographic Areas

All of the Company’s material operations, customers, and assets occur and are located in the United States.

(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 its 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.

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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 Securities and Exchange Commission 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 principal business, economic and other factors that affect the operations and/or financial performance of the Company include:

Fluctuations in weather have the potential to adversely affect our results of operations, cash flows and financial condition.

Our utility and propane distribution operations are sensitive to fluctuations in weather, and weather conditions directly influence the volume of natural gas and propane delivered by our utility and propane distribution operations to customers. A significant portion of our utility and propane distribution operations’ revenues are derived from the delivery of natural gas and propane to residential and commercial heating customers during the five-month peak heating season of November through March. If the weather is warmer than normal, we deliver less natural gas and propane to customers, and earn less revenue. In addition, hurricanes or other extreme weather conditions could damage production or transportation facilities, which could result in decreased supplies of natural gas and propane, increased supply costs and higher prices for customers.

Regulation of the Company, including changes in the regulatory environment in general, may adversely affect our results of operations, cash flows and financial condition.

The state Public Service Commissions of Delaware, Maryland and Florida regulate our natural gas distribution operations. Eastern Shore, our natural gas transmission subsidiary, is regulated by the FERC. These regulatory agencies set the rates in their respective jurisdictions that we can charge customers for our rate-regulated services. Changes in these rates, as ordered by regulatory commissions, affect our financial performance. Our ability to obtain timely future rate increases and rate supplements to maintain current rates of return depends on regulatory discretion, and there can be no assurance that our divisions and Eastern Shore will be able to obtain rate increases or supplements or continue receiving currently authorized rates of return.

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The amount and availability of natural gas and propane supplies are difficult to predict, which may reduce our earnings.

Natural gas and propane production can be impacted by factors outside of our control, such as weather and refinery closings. If we are unable to obtain sufficient natural gas and propane supplies to meet demand, our results of operations may be negatively impacted.

We rely on having access to interstate pipelines’ transportation and storage capacity. If these pipelines or storage facilities were not available, it may impair our ability to meet our customers’ full requirements.

We must acquire both sufficient natural gas supplies and interstate pipeline and storage capacity to meet customer requirements. We must contract for reliable and adequate delivery capacity for our distribution system, while considering the dynamics of the interstate pipeline and storage capacity market, our own on-system resources, as well as, the characteristics of our customer base. Local natural gas distribution companies, including us, and other participants in the energy industry, have raised concerns regarding the future availability of additional upstream interstate pipeline and storage capacity. Additional available pipeline and storage capacity is a business issue that must be managed by us, as our customer base grows.

Natural gas and propane commodity price changes may affect the operating costs and competitive positions of our natural gas and propane distribution operations, which may adversely affect our results of operations, cash flows and financial condition.

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

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

We compete in a competitive environment and may be faced with losing customers to a competitor.

We compete with third-party suppliers to sell gas to industrial customers. As it relates to transportation services, our competitors include the interstate pipelines if distribution customer is located close enough to the transmission company’s pipeline to make a connection economically feasible.

Our 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. Some of our competitors have significantly greater resources. The retail propane industry is mature, and we foresee only modest growth in total demand. Given this limited growth, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow the propane distribution business is contingent upon execution of our community gas systems strategy to capture market share and to employ service pricing programs that retain and grow our customer base. Any failure to retain and grow our customer base would have an adverse effect on our results.

- Page 9 -

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.

Costs of compliance with environmental laws may be significant.

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long period of time to control environmental effects at current and former operating sites, including former manufactured gas plant sites that we have acquired from third parties. Compliance with these legal requirements requires us to commit capital toward environmental compliance. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines.

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

Further, existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs which may not be fully recoverable by us.

A change in the economic conditions and interest rates may adversely affect our results of operations and cash flows.

A downturn in the economies of the regions in which we operate, which we cannot accurately predict, might adversely affect our ability to increase our customer base and other businesses at the same rate 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 debt to finance accounts receivable, storage gas inventories, and to temporarily finance capital expenditures.

Inflation may impact our results of operations, cash flows and financial position.

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. To help cope with the effects of inflation on our capital investments and returns, we seek rate relief from regulatory commissions for regulated operations while monitoring the returns of our unregulated business operations. There can be no assurance that we will be able to obtain adequate and timely rate relief to offset the effects of inflation. To compensate for fluctuations in propane gas prices, we adjust our propane selling prices to the extent allowed by the market. However, there can be no assurance that we will be able to increase propane sales prices sufficiently to fully compensate for such fluctuations in the cost of propane gas to us.

Changes in technology may adversely affect our advanced information services segment’s results of operations, cash flows and financial condition.

Our advanced information services segment participates in a market that is characterized by rapidly changing technology and accelerating product introduction cycles. The success of our advanced information services segment depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services on a timely basis, and by keeping pace with technological developments and emerging industry standards. There can be no assurance that we will be able to keep up with technological advancements necessary to make our products competitive.

- Page 10 -

Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.

Xeron, our propane wholesale and marketing subsidiary, and PESCO, our natural gas marketing subsidiary in Florida, extend credit to counter-parties. 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 dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If the financial condition of these subsidiaries declines, or if our financial condition declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.

Our use of derivative instruments may adversely affect our results of operations.

Fluctuating commodity prices cause our earnings and financing costs to be impacted. Our propane distribution and wholesale marketing segment uses derivative instruments, including forwards, swaps and puts, to hedge price risk. In addition, we have utilized in the past, and may decide, after further evaluation, to continue to utilize derivative instruments to hedge price risk for our Delaware and Maryland divisions, as well as PESCO. While we have a risk management policy and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial conditions may be adversely impacted.

Inability to access the capital markets may impair our future growth.

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

We are dependent upon access to natural gas supply and the construction of new facilities to support future growth in earnings in our utilities and the interstate pipeline.

Construction of these facilities is subject to various regulatory, development and operational risks, include but not limited to our ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on terms that are acceptable to us; 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; impediments on our ability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; lack of anticipated future growth in natural gas supply; and lack of transportation or throughput commitments.

We are subject to operating and litigation risks that may not be covered by insurance.

Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing natural gas and propane to end users. As a result, we are sometimes a defendant in legal proceedings and litigation 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.

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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. Capacity and utilization of the Company’s facilities can vary significantly due to the seasonal nature of the natural gas and propane distribution businesses.

(b)

Natural Gas Distribution

Chesapeake owns over 965 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas and 726 miles of natural gas distribution mains (and related equipment) in its central Florida service areas. Chesapeake also owns facilities in Delaware and Maryland for propane-air injection during periods of peak demand.

(c)

Natural Gas Transmission

Eastern Shore owns and operates approximately 366 miles of transmission pipelines extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania and Hockessin, Delaware to approximately 75 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 2.0 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 involved in various legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these 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

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Part II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

(a)

Common Stock Price Ranges, Common Stock Dividends and Shareholder Information:

The Company’s Common Stock is listed on the New York Stock Exchange 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 2006 and 2005 were as follows:

Quarter Ended	High		Low		Close		Dividends Declared Per Share
2006
March 31	$	32.47	$	29.97	$	31.24	$	0.285
June 30		31.20		27.90		30.08	$	0.290
September 30		35.65		29.51		30.05	$	0.290
December 31		31.31		29.10		30.65	$	0.290

2005
March 31	$	27.59	$	25.83	$	26.60	$	0.280
June 30		30.95		23.60		30.58	$	0.285
September 30		35.60		29.50		35.16	$	0.285
December 31		35.78		30.32		30.80	$	0.285

Dividend payments 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 2006 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 the other debt covenants during 2006.

At December 31, 2006, there were 1,978 shareholders of record of the Common Stock.

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(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, 2006.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽²⁾		Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs ⁽²⁾
October 1, 2006 through October 31, 2006 ⁽¹⁾		463	$	29.92		0		0
November 1, 2006 through November 30, 2006		0	$	0.00		0		0
December 1, 2006 through December 31, 2006		0	$	0.00		0		0
Total		463	$	29.92		0		0

⁽¹⁾ Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on shares held in Rabbi Trust accounts for certain Senior Executives. During the quarter, 463 shares were purchased through executive dividend deferrals.
⁽²⁾ Except for the purpose described in Footnote ⁽¹⁾, Chesapeake has no publicly announced plans or programs to repurchase its shares.

Discussion on compensation plans of Chesapeake and its subsidiaries for which shares of Chesapeake common stock are authorized for issuance is incorporated herein by reference to the portion of the Proxy Statement captioned “Equity Compensation Plan Information” to be filed not later than March 31, 2007 in connection with the Company’s Annual Meeting to be held on May 2, 2007.

(c)

Chesapeake Utilities Corporation Common Stock Performance Graph

The following Performance Graph compares the yearly percentage change in cumulative total shareholder return on the Company’s common stock during the five fiscal years ended December 31, 2006, with the cumulative return on (i) the S&P 500 Index and (ii) an industry index consisting of 30 Natural Gas Distribution and Integrated Natural Gas Companies as published by C.A Turner Utility Reports.

The thirty companies in the C.A. Turner industry index are as follows: AGL Resources, Inc., Atmos Energy Corporation, Cascade Natural Gas Corporation, Chesapeake Utilities Corporation, Delta Natural Gas Company, Inc., El Paso Corporation, Energen Corporation, Energy West, Inc., EnergySouth. Inc., Equitable Resources, Inc., KeySpan Corporation, Kinder Morgan, Inc., The Laclede Group, Inc., National Fuel Gas Company, New Jersey Resources Corporation, NICOR, Inc., Northwest Natural Gas Company, ONEOK, Inc., Peoples Energy Corporation, Piedmont Natural Gas Co., Inc., Questar Corporation, RGC Resources, Inc., SEMCO Energy, Inc., South Jersey Industries, Inc., Southern Union Company, Southwest Gas Corporation, Southwest Energy Company, UGI Corporation, WGL Holdings, Inc., and The Williams Companies, Inc.

- Page 14 -

The comparison assumes $100 was invested on December 31, 2001 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.

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

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Item 6. Selected Financial Data

For the Years Ended December 31,	2006 ⁽³⁾			2005			2004			2003			2002
Operating *(in thousands of dollars)*⁽¹⁾
Revenues
Natural gas	$	170,374		$	166,582		$	124,246		$	110,247		$	93,588
Propane		48,576			48,976			41,500			41,029			29,238
Advanced informations systems		12,568			14,140			12,427			12,578			12,764
Other and eliminations		(317	)		(68	)		(218	)		(286	)		(334	)
Total revenues	$	231,201		$	229,630		$	177,955		$	163,568		$	135,256

Operating income
Natural gas	$	19,733		$	17,236		$	17,091		$	16,653		$	14,973
Propane		2,534			3,209			2,364			3,875			1,052
Advanced informations systems		767			1,197			387			692			343
Other and eliminations		(103	)		(112	)		128			359			237
Total operating income	$	22,931		$	21,530		$	19,970		$	21,579		$	16,605

Net income from continuing operations	$	10,507		$	10,468		$	9,550		$	10,079		$	7,535


Assets *(in thousands of dollars)*
Gross property, plant and equipment	$	325,836		$	280,345		$	250,267		$	234,919		$	229,128
Net property, plant and equipment ⁽²⁾	$	240,825		$	201,504		$	177,053		$	167,872		$	166,846
Total assets ⁽²⁾	$	324,994		$	295,980		$	241,938		$	222,058		$	223,721
Capital expenditures ⁽¹⁾	$	48,969		$	33,423		$	17,830		$	11,822		$	13,836


Capitalization *(in thousands of dollars)*
Stockholders' equity	$	111,152		$	84,757		$	77,962		$	72,939		$	67,350
Long-term debt, net of current maturities		71,050			58,991			66,190			69,416			73,408
Total capitalization	$	182,202		$	143,748		$	144,152		$	142,355		$	140,758
Current portion of long-term debt	$	7,656		$	4,929		$	2,909		$	3,665		$	3,938
Short-term debt		27,554			35,482			5,002			3,515			10,900
Total capitalization and short-term financing	$	217,412		$	184,159		$	152,063		$	149,535		$	155,596

⁽¹⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
⁽²⁾ SFAS 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001.
⁽³⁾ SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

- Page 16 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2001			2000			1999			1998			1997
Operating *(in thousands of dollars)*⁽¹⁾
Revenues
Natural gas	$	107,418		$	101,138		$	75,637		$	68,770		$	88,108
Propane		35,742			31,780			25,199			23,377			28,614
Advanced informations systems		14,104			12,390			13,531			10,331			7,786
Other and eliminations		(113	)		(131	)		(14	)		(15	)		(182	)
Total revenues	$	157,151		$	145,177		$	114,353		$	102,463		$	124,326

Operating income
Natural gas	$	14,405		$	12,798		$	10,388		$	8,820		$	9,240
Propane		913			2,135			2,622			965			1,137
Advanced informations systems		517			336			1,470			1,316			1,046
Other and eliminations		386			816			495			485			558
Total operating income	$	16,221		$	16,085		$	14,975		$	11,586		$	11,981

Net income from continuing operations	$	7,341		$	7,665		$	8,372		$	5,329		$	5,812


Assets *(in thousands of dollars)*
Gross property, plant and equipment	$	216,903		$	192,925		$	172,068		$	152,991		$	144,251
Net property, plant and equipment ⁽²⁾	$	161,014		$	131,466		$	117,663		$	104,266		$	99,879
Total assets ⁽²⁾	$	222,229		$	211,764		$	166,958		$	145,029		$	145,719
Capital expenditures ⁽¹⁾	$	26,293		$	22,057		$	21,365		$	12,516		$	13,471


Capitalization *(in thousands of dollars)*
Stockholders' equity	$	67,517		$	64,669		$	60,714		$	56,356		$	53,656
Long-term debt, net of current maturities		48,409			50,921			33,777			37,597			38,226
Total capitalization	$	115,926		$	115,590		$	94,491		$	93,953		$	91,882
Current portion of long-term debt	$	2,686		$	2,665		$	2,665		$	520		$	1,051
Short-term debt		42,100			25,400			23,000			11,600			7,600
Total capitalization and short-term financing	$	160,712		$	143,655		$	120,156		$	106,073		$	100,533

⁽¹⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
⁽²⁾ SFAS 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001.
⁽³⁾ SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

- Page 17 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2006 ⁽³⁾			2005			2004			2003			2002
Common Stock Data and Ratios
Basic earnings per share from continuing operations ⁽¹⁾	$	1.74		$	1.79		$	1.66		$	1.80		$	1.37
Diluted earnings per share from continuing operations ⁽¹⁾	$	1.72		$	1.77		$	1.64		$	1.76		$	1.37

Return on average equity from continuing operations ⁽¹⁾		10.7	%		12.9	%		12.7	%		14.4	%		11.2	%

Common equity / total capitalization		61.0	%		59.0	%		54.1	%		51.2	%		47.8	%
Common equity / total capitalization and short-term financing		51.1	%		46.0	%		51.3	%		48.8	%		43.3	%

Book value per share	$	16.62		$	14.41		$	13.49		$	12.89		$	12.16


Market price:
High	$	35.650		$	35.780		$	27.550		$	26.700		$	21.990
Low	$	27.900		$	23.600		$	20.420		$	18.400		$	16.500
Close	$	30.650		$	30.800		$	26.700		$	26.050		$	18.300


Average number of shares outstanding		6,032,462			5,836,463			5,735,405			5,610,592			5,489,424
Shares outstanding at year-end		6,688,084			5,883,099			5,778,976			5,660,594			5,537,710
Registered common shareholders		1,978			2,026			2,026			2,069			2,130

Cash dividends declared per share	$	1.16		$	1.14		$	1.12		$	1.10		$	1.10
Dividend yield (annualized) ⁽²⁾		3.8	%		3.7	%		4.2	%		4.2	%		6.0	%
Payout ratio from continuing operations ^{(1) (4)}		66.7	%		63.7	%		67.5	%		61.1	%		80.3	%


Additional Data
Customers
Natural gas distribution and transmission		59,132			54,786			50,878			47,649			45,133
Propane distribution		33,282			32,117			34,888			34,894			34,566


Volumes
Natural gas distribution and transmission deliveries (in MMCF)		34,321			34,981			31,430			29,375			27,935
Propane distribution (in thousands of gallons)		24,243			26,178			24,979			25,147			21,185


Heating degree-days (Delmarva Peninsula)
Actual HDD		3,931			4,792			4,553			4,715			4,161
10 -year average HDD (normal)		4,372			4,436			4,389			4,409			4,393

Propane bulk storage capacity (in thousands of gallons)		2,315			2,315			2,045			2,195			2,151

Total employees ⁽¹⁾		437			423			426			439			455

⁽¹⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
⁽²⁾ Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then dividing that amount by the closing common stock price at December 31.
⁽³⁾ SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
⁽⁴⁾ The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

- Page 18 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2001			2000			1999			1998			1997
Common Stock Data and Ratios
Basic earnings per share from continuing operations ⁽¹⁾	$	1.37		$	1.46		$	1.63		$	1.05		$	1.17
Diluted earnings per share from continuing operations ⁽¹⁾	$	1.35		$	1.43		$	1.59		$	1.04		$	1.15

Return on average equity from continuing operations ⁽¹⁾		11.1	%		12.2	%		14.3	%		9.7	%		11.1	%

Common equity / total capitalization		58.2	%		55.9	%		64.3	%		60.0	%		58.4	%
Common equity / total capitalization and short-term financing		42.0	%		45.0	%		50.5	%		53.1	%		53.4	%

Book value per share	$	12.45		$	12.21		$	11.71		$	11.06		$	10.72


Market price:
High	$	19.900		$	18.875		$	19.813		$	20.500		$	21.750
Low	$	17.375		$	16.250		$	14.875		$	16.500		$	16.250
Close	$	19.800		$	18.625		$	18.375		$	18.313		$	20.500


Average number of shares outstanding		5,367,433			5,249,439			5,144,449			5,060,328			4,972,086
Shares outstanding at year-end		5,424,962			5,297,443			5,186,546			5,093,788			5,004,078
Registered common shareholders		2,171			2,166			2,212			2,271			2,178

Cash dividends declared per share	$	1.10		$	1.07		$	1.03		$	1.00		$	0.97
Dividend yield (annualized) ⁽²⁾		5.6	%		5.8	%		5.7	%		5.5	%		4.7	%
Payout ratio from continuing operations ^{(1) (4)}		80.3	%		73.3	%		63.2	%		95.2	%		82.9	%


Additional Data
Customers
Natural gas distribution and transmission		42,741			40,854			39,029			37,128			35,797
Propane distribution		35,530			32,117			35,267			34,113			33,123


Volumes
Natural gas distribution and transmission deliveries (in MMCF)		27,264			30,830			27,383			21,400			23,297
Propane distribution (in thousands of gallons)		23,080			28,469			27,788			25,979			26,682


Heating degree-days (Delmarva Peninsula)
Actual HDD		4,368			4,730			4,082			3,704			4,430
10 -year average HDD (normal)		4,446			4,356			4,409			4,493			4,574

Propane bulk storage capacity (in thousands of gallons)		1,958			1,928			1,926			1,890			1,866

Total employees ⁽¹⁾		458			471			466			431			397

⁽¹⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
⁽²⁾ Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then dividing that amount by the closing common stock price at December 31.
⁽³⁾ SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.
⁽⁴⁾ The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

- Page 19 -

Management's Discussion and Analysis

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

INTRODUCTION

This section provides management’s discussion of Chesapeake Utilities Corporation and its consolidated subsidiaries with specific information on results of operations and liquidity and capital resources. 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

Exec

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

·	Executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital.

·	Expanding the natural gas distribution and transmission business through expansion into new geographic areas in our current service territories.

·	Expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities.

·	Utilizing the Company’s expertise across our various businesses to improve overall performance.

·	Enhancing marketing channels to attract new customers and providing reliable and responsive customer service to retain existing customers.

·	Maintaining a capital structure that enables the Company to access capital as needed.

·	Maintaining a consistent and competitive dividend.

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

The following discussions and those later in the document on operating income and segment results include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost 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.

- Page 20 -

Management's Discussion and Analysis

Operating Income

The year 2006 reflects the strong year-over-year operating income growth experienced by the Company’s natural gas operations of $2,497,000, or 14.5 percent. This growth was offset by reductions in operating income from propane and advanced information services. In 2006, both natural gas and propane segments were negatively impacted by weather that was 18 percent warmer than in 2005. The Company estimates that the warmer weather reduced gross margin by $3.4 million in 2006. The natural gas segment was able to overcome the weather impact and show an increase in operating income due to its growth and cost containment efforts. However, as the propane segment is more weather sensitive and is not experiencing the high level of growth of our natural gas segment, its operating income declined when compared to 2005.

Advanced information services experienced a decrease in operating income in 2006 as compared to the prior year due in part to the gain on the sale of Lightweight Association Management Processing System (“LAMPS^TM”) during the fourth quarter of 2005. The LAMPS product was internally developed software that was developed and marketed specifically for REALTOR® Associations.

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

Customer growth in the natural gas and propane businesses remained strong, with the Delmarva and Florida natural gas distribution operations registering 9 and 8 percent increases in residential customers, respectively; and the Delmarva Community Gas Systems (“CGS”) generating a 34 percent increase in propane distribution customers.

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

On September 26, 2006, the Company received approval for a base rate increase from the Maryland Public Service Commission (“PSC”) for our Maryland natural gas operations, with the new base rates effective October 1, 2006. The base rate adjustment results in an increase in base rates of approximately $780,000, which would result in an average increase in revenues of approximately 4.5 percent for the Company’s firm residential, commercial and industrial customers in Maryland. The PSC also approved the Company’s proposal to implement a revenue normalization mechanism for its residential heating and smaller commercial heating customers, reducing the Company’s future risk due to weather and usage changes.

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

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

·	For the year ended December 31, 2006, the Company generated $30.1 million in operating cash flow compared with $13.6 million for the year ended December 31, 2005. The higher cost of natural gas and propane in 2005 had an adverse impact on working capital in 2005.

- Page 21 -

Management's Discussion and Analysis

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

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

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

Critical Accounting Policies

Chesapeake’s reported financial condition and results of operations are affected by the accounting methods, assumptions and estimates that are used in the preparation of the Company’s financial statements. Because most of Chesapeake’s businesses are regulated, the accounting methods used by Chesapeake must comply with the requirements of the regulatory bodies; therefore, the choices available are limited by these regulatory requirements. 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

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.” Costs are deferred when there is a probable expectation that they will be recovered in future revenues as a result of the regulatory process. At December 31, 2006, Chesapeake had recorded regulatory assets of $3.0 million, including $1.1 million for under-recovered purchased gas costs, $1.3 million for tax-related regulatory assets, $139,000 for defined postretirement benefits, and $122,000 for environmental cost recovery. The Company has recorded regulatory liabilities totaling $23.8 million, including $18.4 million for accrued asset removal cost, $2.4 million for over-recovered purchased gas costs, $1.2 million for self-insurance, $1.2 million for cash in/cash out, and $349,000 for over-collected environmental costs at December 31, 2006. 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 to earnings, net of applicable income taxes. Such a charge 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. Additionally, there is uncertainty due to the outcome of legal remedies sought from other potentially responsible parties. At December 31, 2006, Chesapeake had recorded environmental regulatory assets of $122,000 and a regulatory liability of $350,000 for over-collections and an additional liability of $212,000 for environmental costs.

- Page 22 -

Management's Discussion and Analysis

Propane Wholesale Marketing Contracts

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 the 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, 2006, these contracts had net unrealized gains of $8,500 that was recorded in the financial statements. At December 31, 2005, these contracts had net unrealized gains of $46,000 that were recorded in the financial statements.

Operating Revenues

Revenues for the natural gas distribution operations of the Company are based on rates approved by the public service commissions (“PSC”) 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 with customers that have competitive alternatives using approved methodologies. In addition, the natural gas transmission operation can negotiate rates above or below the FERC approved tariff rates.

Chesapeake’s natural gas distribution operations in Delaware and Maryland each have a gas cost recovery mechanism that provides for the adjustment of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.

The Company charges flexible 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 types of supply. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

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 natural gas segment recognizes revenue on an accrual basis. The propane distribution, advanced information services and other segments record revenue in the period the products are delivered and/or services are rendered.

Results of Operations

Net Income & Diluted Earnings Per Share Summary

For the Years Ended December 31,	2006		2005		Increase (decrease)			2005		2004			Increase (decrease)
Net Income *
Continuing operations	$	10,507	$	10,468	$	39		$	10,468	$	9,550		$	918
Discontinued operations		-		-		-			-		(121	)		121
Total Net Income	$	10,507	$	10,468	$	39		$	10,468	$	9,429		$	1,039

Diluted Earnings Per Share
Continuing operations	$	1.72	$	1.77		($0.05	)	$	1.77	$	1.64		$	0.13
Discontinued operations		-		-		-			-		(0.02	)		0.02
Total Earnings Per Share	$	1.72	$	1.77		($0.05	)	$	1.77	$	1.62		$	0.15

* Dollars in thousands.

- Page 23 -

Management's Discussion and Analysis

The Company’s net income from continuing operations increased $39,000 in 2006 when compared to 2005. Net income was $10.50 million, or $1.72 per share (diluted), for 2006, compared to a net income of $10.47 million, or $1.77 per share (diluted).

The Company’s net income from continuing operations increased $918,000, or 10 percent, in 2005 compared to 2004. Net income from continuing operations was $10.5 million, or $1.77 per share (diluted), compared to a net income from continuing operations of $9.6 million, or $1.64 per share (diluted) for 2004.

During 2003, Chesapeake decided to exit the water services business and had sold the assets of six of seven dealerships by December 31, 2003. The remaining operation was sold in 2004. The results of water services were classified as discontinued operations for year 2004. Discontinued operations experienced losses of $0.02 per share (diluted) for 2004.

Operating Income Summary (in thousands)

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

2006 Compared to 2005

Operating income in 2006 increased $1.4 million, or 6.5 percent, greater than 2005, despite adverse weather, which when measured in terms of heating degree-days, was 18 percent warmer. The improved 2006 results of operations when compared to 2005 were impacted by:

·	Weather on the Delmarva Peninsula was 18 percent warmer in 2006 than 2005, which the Company estimates to have cost approximately $3.4 million in gross margin for its Delmarva natural gas and propane distribution operations.

·	Strong residential customer growth of 9 percent and 8 percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2006.

·	The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent, due to additional capacity contracts that went into effect in November 2005 and November 2006.

·	A 67 percent increase in the number of customers for the Company’s natural gas marketing operation.

·	Gross margin for the Delmarva propane distribution operations decreased $834,000, primarily from the warmer weather in 2006.

·	The Delmarva Community Gas Systems continue to experience strong customer growth as the number of customers increased 34 percent in 2006 compared to 2005.

·	Operating income for the advanced information services segment decreased $430,000 in 2006. Although revenues from consulting increased $749,000 in 2006, the 2005 results contained $993,000 of operating income for the LAMPS^TMproduct, which was sold in the fourth quarter 2005.

2005 Compared to 2004

The improvement in results for 2005 versus 2004 was primarily driven by:

·	The LAMPS™ product, including the sale of its property rights, contributed $622,000 to operating income in 2005 for the Company’s advanced information services segment.

·	The Delmarva and Florida natural gas distribution operations experienced strong residential customer growth of 9 percent and 7 percent, respectively, in 2005.

- Page 24 -

Management's Discussion and Analysis

·	Temperatures on the Delmarva Peninsula were 5 percent colder than 2004, which led to increased contributions from the Company’s natural gas and propane distribution operations. This increase was offset by conservation efforts by customers.

·	The natural gas transmission operation achieved gross margin growth of 9 percent due to additional transportation capacity contracts that went into effect in November 2004.

·	A 100 percent increase in the number of customers for the Company’s natural gas marketing operation.

·	An increase of 1.1 million gallons sold by the Delmarva propane distribution operation.

Natural Gas Distribution, Transmission, and Marketing

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

Natural Gas Distribution, Transmission, and Marketing (in thousands)

For the Years Ended December 31,	2006		2005		Increase (decrease)			2005		2004		Increase (decrease)
Revenue	$	170,374	$	166,582	$	3,792		$	166,582	$	124,246	$	42,336
Cost of gas		117,948		116,178		1,770			116,178		77,456		38,722
Gross margin		52,426		50,404		2,022			50,404		46,790		3,614

Operations & maintenance		22,673		23,874		(1,201	)		23,874		21,129		2,745
Depreciation & amortization		6,312		5,682		630			5,682		5,418		264
Other taxes		3,708		3,612		96			3,612		3,152		460
Other operating expenses		32,693		33,168		(475	)		33,168		29,699		3,469

Total Operating Income	$	19,733	$	17,236	$	2,497		$	17,236	$	17,091	$	145

Heating Degree-Day (HDD) and Customer Analysis

For the Years Ended December 31,	2006		2005		Increase (decrease)			2005		2004		Increase (decrease)
Heating degree-day data — Delmarva
Actual HDD		3,931		4,792		(861	)		4,792		4,553		239
10-year average HDD		4,372		4,436		(64	)		4,436		4,383		53

Estimated gross margin per HDD	$	2,013	$	2,234		($221	)	$	2,234	$	1,800	$	434

Estimated dollars per residential customer added:
Gross margin	$	372	$	372	$	0		$	372	$	372	$	0
Other operating expenses	$	111	$	106	$	5		$	106	$	104	$	2

Average number of residential customers
Delmarva		40,535		37,346		3,189			37,346		34,352		2,994
Florida		12,663		11,717		946			11,717		10,910		807
Total		53,198		49,063		4,135			49,063		45,262		3,801

2006 Compared to 2005

Gross margin for the Company’s natural gas segment increased $2.0 million, or 4 percent, and other operating expenses decreased $475,000, or 1 percent, in 2006 compared to 2005. The gross margin increases of $1.8 million 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 lower gross margin of $210,000 for the Delmarva natural gas distribution operations.

- Page 25 -

Management's Discussion and Analysis

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 attributed to new transportation capacity contracts implemented in November 2005 and $612,000 due to new transportation capacity contracts implemented in November 2006. In 2007, the new transportation capacity contracts implemented in November 2006 are expected to generate an additional gross margin of $3.3 million above and beyond 2006 gross margins. An increase of $416,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses are as follow:

·	Payroll costs and incentive compensation increased $108,000 to serve the additional growth experienced by the operation.

·	Higher depreciation and asset removal costs of $558,000 and increased property taxes of $109,000 due to an increase in the level of capital investment.

A reduction of $376,000 as a result of the operation receiving approval from the FERC to recover certain pre-service costs associated with the Bay Crossing Project. Please refer to the Regulatory Matters section under Other Matters within Item 2 of the Management’s Discussion and Analysis for additional details. As a result of this approval, the Company is deferring the pre-service costs that it incurs. In 2006, the Company deferred $188,000 of costs previously incurred and expensed in 2005. As a result of this deferral, the amounts recognized in the Company’s income statement have declined from 2005 by $376,000.

·	There was an increase of approximately $17,000 in other operating expenses relating to various minor items.

Natural Gas Marketing

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

Natural Gas Distribution

Gross margin for the Florida distribution operation increased by $395,000. The impact of an 8 percent growth in residential customers contributed $230,000 to gross margin. In addition to residential customer growth, new commercial and industrial customers contributed $91,000 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 impacted gross margin in 2006 compared to 2005 as temperatures on the Delmarva Peninsula were 18 percent warmer in 2006. The Company estimates that the warmer temperatures in 2006 led to a decrease in gross margin of approximately $1.7 million when compared to 2005. This decrease was partially offset by continued residential customer growth. The average number of residential customers on the Delmarva Peninsula increased 3,189, or 9 percent, for 2006 compared to 2005 and the Company estimates these additional residential customers contributed approximately $1.2 million to gross margin. The remaining $190,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial customers and decrease of interruptible sales.

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

·	Health care costs decreased by $313,000 as a result of the Company changing health care service providers in November 2005 and has subsequently experienced lower costs related to claims.

·	Allowance for uncollectible accounts decreased by $289,000 in 2006 compared to 2005 due to lower revenues and increased collection efforts. Revenues are down due to lower prices and warmer temperatures.

·	Incentive compensation decreased $177,000 in 2006 to reflect lower than expected earnings

·	Lower corporate costs due to lower payroll and related expenses.

·	Depreciation and amortization expense and asset removal cost increased $132, 000 and $186, 000, respectively, as a result of the Company’s continued capital investments.

- Page 26 -

Management's Discussion and Analysis

·	Merchant payment fees increased $136,000 in 2006 compared to 2005 as the Company experienced more customers making payments with the use of credit cards.

·	In addition, there is an increase of approximately $55,000 in other operating expenses relating to various minor items.

2005 Compared to 2004

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

Natural Gas Transmission

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

Natural Gas Marketing

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

Natural Gas Distribution

Gross margin for the Delaware and Maryland distribution divisions increased $1.2 million, as temperatures in 2005 were 5 percent colder than 2004 and the number of residential customers increased 8.7 percent. An increase in gross margin from the colder weather of $534,000 was offset by a decrease of $651,000 in gas deliveries to customers as a result of conservation efforts in response to the higher gas prices. Gross margin for the Florida distribution operations increased $579,000, primarily due to changes in the customer rate design and a 7.4 percent increase in the number of residential customers served. The Company estimates the rate design changes contributed $322,000 in additional gross margin and resulted in the Florida division collecting a greater percentage of revenues from fixed charges, rather than variable charges based upon consumption. Other operating expense for the natural gas distribution operations increased $2.1 million in 2005. Some of the key components of the increase in other operating expenses in 2005, compared to 2004, include the following:

·	The incremental operating and maintenance cost of supporting the residential customers added by the Delmarva and Florida distribution operations was approximately $403,000.

·	In response to higher natural gas prices, the Company increased its allowance for uncollectible accounts by $98,000.

·	The cost of providing health care for our employees increased $180,000.

·	Costs of line location activities increased $177,000.

·	With the additional capital investments, depreciation expense, asset removal cost and property taxes increased $225,000, $130,000 and $319,000, respectively.

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Management's Discussion and Analysis

Propane

The propane segment experienced a decrease of $675,000 in operating income in 2006 compared to 2005, reflecting a gross margin decrease of $1.1 million, which was partially offset by a decrease in operating expenses of $464,000.

During 2005, the propane segment increased operating income by $845,000, or 36 percent, over 2004. Gross margin in 2005 increased $2.6 million over 2004, which more than offset the increase of $1.7 million of operating expenses.

Propane (in thousands)

For the Years Ended December 31,	2006		2005		Increase (decrease)			2005		2004		Increase (decrease)
Revenue	$	48,576	$	48,976		($400	)	$	48,976	$	41,500	$	7,476
Cost of sales		30,780		30,041		739			30,041		25,155		4,886
Gross margin		17,796		18,935		(1,139	)		18,935		16,345		2,590

Operations & maintenance		12,823		13,355		(532	)		13,355		11,718		1,637
Depreciation & amortization		1,659		1,574		85			1,574		1,524		50
Other taxes		780		797		(17	)		797		739		58
Other operating expenses		15,262		15,726		(464	)		15,726		13,981		1,745

Total Operating Income	$	2,534	$	3,209		($675	)	$	3,209	$	2,364	$	845

Propane Heating Degree-Day (HDD) Analysis — Delmarva

For the Years Ended December 31,	2006		2005		Increase (decrease)			2005		2004		Increase (decrease)
Heating degree-days
Actual		3,931		4,792		(861	)		4,792		4,553		239
10-year average		4,372		4,436		(64	)		4,436		4,383		53

Estimated gross margin per HDD	$	1,743	$	1,743	$	0		$	1,743	$	1,691	$	52

2006 Compared to 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 lower when compared to 2005 by $834,000, primarily due to warmer weather. 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 items:

Volumes sold in 2006 decreased 1.9 million gallons, or 8 percent, primarily from temperatures on the Delmarva Peninsula being 18 percent warmer during 2006 when compared to 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.7 million when compared to 2005.

·	Gross margin increased $956,000 from an increase of $0.0302 in the average gross margin per retail gallon in 2006 compared to 2005.

Gross margin for the Delmarva CGS increased $155,000 when compared to the prior period, primarily from an increase in the average number of customers. The average number of customers increased by approximately 1,000 to a total count of approximately 3,900, or a 34 percent increase, when compared to 2005. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide for an additional 7,700 customers.

·	Gross margin was adversely impacted by a $272,000 write-down of propane inventory to reflect the lower of cost or market.

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Management's Discussion and Analysis

·	The remaining gross margin decrease of $29,000 is attributed primarily to customer conservation and changes in the timing of deliveries to customers.

Other operating expenses decreased $335,000 for the Delmarva operations in 2006, compared to 2005. The significant items contributing to the decrease are explained below.

The Company recovered $387,000 in fixed costs from one of its propane suppliers in response to a propane contamination incident that occurred in March 2006. The Company identified that approximately 75,000 gallons of propane that it purchased from the supplier contained above-normal levels of petroleum byproducts.

·	Health care costs decreased by $324,000. The Company changed health care service providers in November 2005 and has subsequently experienced lower costs related to claims.

·	In addition, there is a decrease of approximately $39,000 in other operating expenses relating to various minor items.

·	These lower costs were partially offset by increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, increased payroll costs of $165,000 and higher costs of $74,000 associated with vehicle fuel.

Florida Propane Distribution

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

Propane Wholesale and Marketing

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

2005 Compared to 2004

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

Delmarva Propane Distribution

The gross margin increase for the propane segment was due primarily to an increase of $1.8 million for the Delmarva distribution operations. Volumes sold in 2005 increased 1.1 million gallons or 5 percent. Temperatures in 2005 were 5 percent colder than 2004, causing an estimated gross margin increase of $417,000. Additionally, the gross margin per retail gallon improved by $0.0342 in 2005 compared to 2004. Gross margin per gallon increased as a result of market prices rising greater than the Company’s inventory price per gallon. This trend reverses when market prices decrease and move closer to the Company’s inventory price per gallon. The gross margin increase was partially offset by increased other operating expenses of $1.5 million. The higher other operating costs were attributable to the Pennsylvania start-up costs and expenses related to higher earnings, such as incentive compensation and other taxes, employee benefits, insurance, vehicle fuel and maintenance expenses, and a non-recurring credit of $100,000 for vehicle insurance audits in 2004. The Pennsylvania start-up costs accounted for $722,000, or approximately 49 percent, of the increase in operating expenses.

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Management's Discussion and Analysis

Florida Propane Distribution

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

Propane Wholesale and Marketing

The Company’s propane wholesale marketing operation experienced an increase in gross margin of $445,000 and an increase of $121,000 in other operating expenses, leading to an improvement of $323,000 in operating income over 2004. Wholesale price volatility created trading opportunities during the third and fourth quarters of the year; however, these were partially offset by reduced trading activities particularly in the first half of the year when the wholesale marketing operation followed a conservative marketing strategy, which lowered risk and earnings, in light of continued high wholesale price levels.

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 $767,000 for 2006, $1.2 million for 2005, and $387,000 for 2004.

Advanced Information Services (in thousands)

For the Years Ended December 31,	2006		2005		Increase (decrease)			2005		2004		Increase (decrease)
Revenue	$	12,568	$	14,140		($1,572	)	$	14,140	$	12,427	$	1,713
Cost of sales		7,082		7,181		(99	)		7,181		7,015		166
Gross margin		5,486		6,959		(1,473	)		6,959		5,412		1,547

Operations & maintenance		4,119		5,129		(1,010	)		5,129		4,405		724
Depreciation & amortization		113		123		(10	)		123		138		(15	)
Other taxes		487		510		(23	)		510		482		28
Other operating expenses		4,719		5,762		(1,043	)		5,762		5,025		737

Total Operating Income	$	767	$	1,197		($430	)	$	1,197	$	387	$	810

2006 Compared to 2005

Operating income for advanced information services business decreased $430,000 to $767,000 for 2006 compared to $1.2 million in 2005. The operating income for 2005 included operating income of $993,000 for LAMPS™, inclusive of a $924,000 pre-tax gain on the sale of the product. The LAMPS^TM product was sold to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc., in October 2005.

Revenues for the period decreased $1.6 million compared to 2005, due primarily to elimination of $1.9 million of revenue generated by the LAMPS^TM product in 2005. Consulting revenues increased $749,000 in 2006 when compared to 2005, primarily from offering a new service, Managed Database Administration (“MDBA”), to its customers in 2006 and an increase of 7.6 percent in the average hourly billing rate, while the number of billable hours remained at the same level of 2005. The MDBA service provides third parties with professional database monitoring and support solutions during business hours or around the clock. The MDBA service contributed $470,000 to consulting revenues. Partially offsetting the increase in consulting revenues were decreases of $128,000 and $244,000 from training and product sales and other revenues, respectively.

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Management's Discussion and Analysis

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

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

2005 Compared to 2004

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

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

Cost of sales for 2005 increased $165,000 to $7.2 million, compared to $7.0 million for 2004. The increase in cost of sales was attributed to the LAMPS^TM product. The 2005 and 2004 cost of sales figures included $511,000 and $345,000 of cost for the LAMPS^TM product. Other operating expenses increased $738,000 in 2005 to $5.8 million, compared to $5.0 million in 2004. The increase in other operating cost was attributed to the increase of costs relating to the LAMPS^TM product. The costs associated with the LAMPS^TM product for 2005 and 2004 were $1.2 million and $575,000 respectively. The remaining increase was primarily due to health care claims and office rent, which were offset by cost containment measures implemented in the second quarter of 2005 to reduce operating expenses.

Other Operations and Eliminations

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

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

·	In the third quarter of 2006, actions were taken to reduce operating expenses going forward, which resulted in a charge of $65,000 to other operating expenses associated with staff reductions.

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Management's Discussion and Analysis

·	The 2005 results of operation includes the impact of OnSight completing its first and only contract to date, which occurred in the second quarter of 2005.

Other Operations & Eliminations (in thousands)

For the Years Ended December 31,	2006			2005			Increase (decrease)			2005			2004		Increase (decrease)
Revenue	$	620		$	763			($143	)	$	763		$	647	$	116
Cost of sales		1			116			(115	)		116			-		116
Gross margin		619			647			(28	)		647			647		-

Operations & maintenance		479			472			7			472			278		194
Depreciation & amortization		163			220			(57	)		220			210		10
Other taxes		83			97			(14	)		97			63		34
Other operating expenses		725			789			(64	)		789			551		238

Operating Income — Other		($106	)		($142	)	$	36			($142	)	$	96		($238	)
Operating Income — Eliminations	$	3		$	30			($27	)	$	30		$	32		($2	)

Total Operating Income (Loss)		($103	)		($112	)	$	9			($112	)	$	128		($240	)

Discontinued Operations

In 2003, Chesapeake decided to exit the water services business. Six of seven water dealerships were sold during 2003 and the remaining operation was sold in October 2004. The results of the water companies’ operations, for all periods presented in the consolidated income statements, have been reclassified to discontinued operations and shown net of tax. For 2004, the discontinued operations experienced a net loss of $121,000. The Company did not have any discontinued operations in 2006 and 2005.

Income Taxes

Income tax expense for 2006 was $6.8 million compared to $6.3 million for 2005. Income taxes increased in 2006 compared to 2005, due primarily to increased taxable income. Income taxes increased in 2005 compared to 2004, due to increased income. The effective current federal income tax rate for 2006 and 2005 was 35 percent, whereas the rate for 2004 was 34 percent. During 2006, 2005, and 2004, the Company realized benefit of $220,000, $223,000, and $205,000, respectively, from a change in the tax law that allows tax deductions for dividends paid on Company stock held in Employee Stock Ownership Plans (“ESOP”).

Other Income

Other income was $189,000, $383,000, and $549,000 for the years 2006, 2005, and 2004, respectively. The other income amounts for the years 2006 and 2005 consist of interest income, compared to interest income and gains from the sale of assets for the year 2004.

Interest Expense

Total interest expense for 2006 increased approximately $644,000, or 12.5 percent, compared to 2005. The increase reflects the increase in the average short-term debt balance and higher short-term interest rates in 2006 compared to 2005. The average short-term borrowing balance increased $21.2 million in 2006 to $26.9 million compared to $5.7 million in 2005. The large year-over-year increase in the average short-term borrowing balance was primarily to finance the $39.3 million of net property, plant, and equipment added in 2006. The weighted average interest rate for short-term borrowing increased from 4.47 percent for 2005 to 5.47 percent for 2006. The average long-term debt balance during 2006 was $67.2 million with a weighted average interest rate of 6.98 percent, compared to $67.4 million with a weighted average interest rate of 7.18 percent for 2005. The Company also capitalized $586,000 of interest as part of capital project costs during 2006.

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Management's Discussion and Analysis

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

Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investment in new plant and equipment and the 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 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.

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

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

On December 31, 2006, the Company had four unsecured bank lines of credit with two financial institutions, totaling $80.0 million, none of which required compensating balances. These bank lines provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. Two of the bank lines, totaling $15.0 million, are committed. The other two lines are subject to the banks’ availability of funds. The outstanding balances of short-term debt at December 31, 2006 and 2005 were $27.6 million and $35.5 million, respectively. The level of short-term debt was reduced 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 $45.5 million for capital expenditures during 2007. This amount includes $20.2 million for natural gas distribution, $16.5 million for natural gas transmission, $7.5 million for propane distribution and wholesale marketing, $154,000 for advanced information services and $915,000 million 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 and for the replacement of equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other category includes general plant, computer software and hardware. Financing for the 2007 capital expenditure program is expected from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation, new growth opportunities and availability of capital.

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Management's Discussion and Analysis

Chesapeake expects to incur approximately $75,000 in 2007 and 2008 for environmental-related expenditures. Additional expenditures may be required in future years (see Note M to the Consolidated Financial Statements). Management does not expect financing of future environmental-related expenditures to have a material adverse effect on the financial position or capital resources of the Company.

Cash Flows Provided by Operating Activities

Our cash flows provided by (used in) operating activities were as follows:

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

Year-over-year changes in our cash flows from operating activities are attributable primarily to net income, depreciation and working capital changes. The changes in working capital are impacted by 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.

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

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

In 2005, our net cash flow provided by operating activities was $13.6 million, a decrease of $8.4 million from the same period of 2004. The decrease was primarily a result of increased working capital requirements including increased spending of $5.7 million for seasonal natural gas and propane inventories in advance of the winter sales demand. We spent more on these inventories in 2005 primarily because of higher natural gas and propane prices due to the effects of the hurricanes in the Gulf Coast region. The Company also used $1.2 million of cash to purchase investments for the Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. See Note E on Investments in Item 8 under the heading “Financial Statements and Supplemental Data.”

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $48.9 million, $33.1 million, and $15.5 million during fiscal years 2006, 2005, and 2004, respectively. In fiscal years 2006, 2005, and 2004, $48.8 million, $33.3 million, and $16.4 million, respectively, of cash were utilized for capital expenditures. Additions to property, plant and equipment in 2006 were primarily for natural gas transmission ($28.0 million), natural gas distribution ($16.1 million) and propane distribution ($4.3 million). In both 2006 and 2005, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. Natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system.

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Management's Discussion and Analysis

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities totaled $20.7 million during 2006, $20.4 million during 2005 and cash flows used by financing activities was $8.0 million for 2004. Our significant financing activities for the years 2006, 2005, and 2004 are summarized as follow:

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

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

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

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

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

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

Capital Structure

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

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

The Company increased its capitalization by $38.5 million in 2006 compared to 2005. The increased capitalization was primarily used to fund the $39.3 million of net property, plant, and equipment added in 2006 and for working capital.

As of December 31, 2006, common equity represented 61 percent of total capitalization, compared to 59 percent in 2005.

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Management's Discussion and Analysis

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

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

If short-term borrowing and current portion of long-term debt were included in capitalization, total capitalization increased by $33.3 million in 2006 compared to 2005. The increased capitalization was primarily used to fund a portion of the $39.3 million of net property, plant, and equipment added in 2006 and for other general working capital. In addition, if short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 51 percent and 46 percent for 2006 and 2005, respectively.

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

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

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

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

Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as to the Company’s investors.

Shelf Registration

In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In November 2006, we sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. The net proceeds from the sale were used for general corporate purposes, including financing of capital expenditures, repayment of short-term debt, and general working capital purposes. At December 31, 2006, the Company had approximately $20.0 million remaining under this registration statement.

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Management's Discussion and Analysis

Contractual Obligations

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

	Payments Due by Period
Contractual Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Long-term debt ⁽¹⁾	$	7,656,364	$	14,312,727	$	14,403,636	$	42,333,636	$	78,706,363
Operating leases ⁽²⁾		649,659		919,216		652,026		3,769,640		5,990,541
Purchase obligations ⁽³⁾
Transmission capacity		7,182,746		12,413,145		8,154,556		23,523,355		51,273,802
Storage — Natural Gas		1,363,488		2,698,742		2,666,955		5,163,488		11,892,673
Commodities		17,862,123								17,862,123
Forward purchase contracts — Propane ⁽⁴⁾		13,868,391								13,868,391
Unfunded benefits ⁽⁵⁾		292,445		588,705		614,043		2,710,528		4,205,721
Funded benefits ⁽⁶⁾		323,500		148,364		117,732		1,419,046		2,008,642
Total Contractual Obligations	$	49,198,716	$	31,080,899	$	26,608,948	$	78,919,693	$	185,808,256

⁽¹⁾ Principal payments on long-term debt, see Note H, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item. The expected interest payments on long-term debt are $5.2 million, $8.8 million, $6.9 million and $10.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $ 30.9 million.
⁽²⁾ See Note J, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
⁽³⁾ See Note N, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information.
⁽⁴⁾ The Company has also entered into forward sale contracts. See "Market Risk" of the Management's Discussion and Analysis for further information.
⁽⁵⁾ The Company has recorded long-term liabilities of $4.2 million at December 31, 2006 for unfunded post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 65 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations.
⁽⁶⁾ The Company has recorded long-term liabilities of $2.0 million at December 31, 2006 for funded benefits. These liabilities have been funded using a Rabbi Trust and an asset in the same amount is recorded under Investments on the Balance Sheet. The defined benefit pension plan was closed to new participants on January 1, 1999 and participants in the plan on that date were given the option to leave the plan. See Note K, "Employee Benefit Plans," in the Notes to the Consolidated Financial Statements for further information on the plan. Since the plan modification, no additional funding has been required from the Company and none is expected for the next five years, based on factors in effect at December 31, 2006. However, this is subject to change based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets.

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its natural gas supply and management subsidiary, and propane distribution subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’ default. The liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at December 31, 2006, totaled $21.4 million, with the guarantees expiring on various dates 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, 2007. The letter of credit is provided as security for claims amounts to satisfy the deductibles on the Company’s policies. The current letter of credit was renewed during the second quarter of 2006 when the insurance policies were renewed.

Regulatory Activities

The Company’s natural gas distribution operations are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions. Eastern Shore Natural Gas (“Eastern Shore”). The Company’s natural gas transmission operation is subject to regulation by the FERC.

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Management's Discussion and Analysis

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

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

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

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

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

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

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

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Management's Discussion and Analysis

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

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

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

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

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

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

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

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

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Management's Discussion and Analysis

System Expansion 2006 - 2008. On January 20, 2006, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (the “2006 - 2008 Project”) with the FERC. The application requested authority to construct and operate approximately 55 miles of new pipeline facilities and two new metering and regulating station facilities to provide an additional 47,350 dekatherms per day (“dt/d”) of firm transportation service in accordance with the phased-in customer requests of 26,200 dt/d in 2006, 10,300 dt/d in 2007, and 10,850 dt/d in 2008, at a total estimated cost of approximately $33.6 million. The following table provides a breakdown for the additional amounts of firm capacity per day, the estimated capital investment required, and the estimated annual gross margin contribution for the new services that will become effective November 1^st for each of the respective years of the project:

	Year
	2006	2007	2008
Additional firm capacity per day	26,200	10,300	10,850
Capital investment	$17 million	$8 million	$8 million
Annualized gross margin contribution	$3,670,000	$1,484,000	$1,595,000

A Scoping Meeting was held on March 29, 2006 at which the public and all other interested stakeholders were invited to attend to review the project. No opposition to the project was received. On June 13, 2006, the FERC issued a Certificate to Eastern Shore authorizing it to construct and operate the 2006-2008 Project as proposed. Eastern Shore has completed and placed in service the authorized Phase I facilities. Phase II and Phase III facilities are expected to be constructed in 2007 and 2008, respectively.

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

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

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

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

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

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Management's Discussion and Analysis

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

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

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

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

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

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 the change in interest rates. The Company’s long-term debt consists of senior notes and convertible debentures (see Note H to the Consolidated Financial Statements for annual maturities of consolidated long-term debt). All of Chesapeake’s long-term debt is fixed-rate debt. The carrying value of the Company’s long-term debt, including current maturities, was $78.7 million at December 31, 2006 as compared to a fair value of $81.4 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 finance existing short-term borrowing based in part on the fluctuation in interest rates.

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Management's Discussion and Analysis

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 of propane (including leased storage and rail cars) 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. At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on our price-cap plan that we offer to customers. The Company considers this agreement to be an economic hedge and does not qualify for hedge accounting as described in SFAS 133. At the end of the period, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.

The 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 counterparty or booking out the transaction (booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy). The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment of a net amount equal to the difference between the current market price of the futures contract and the original contract price.

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing operation is subject to commodity price risk on its open positions to the extent that market prices for NGL deviate from fixed contract settlement amounts. Market risk associated with the trading of futures and forward contracts are monitored daily for compliance with Chesapeake’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 oversight officials on a daily basis. Additionally, the Risk Management Committee reviews periodic reports on market and credit risk, approves any exceptions to the Risk Management Policy (within the limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on the forward and futures contracts at December 31, 2006 and 2005 is shown in the following charts.

At December 31, 2006	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	13,797,000	$0.9250 — $1.2100	$1.0107
Purchase	13,733,800	$0.9250 — $1.2200	$1.0098

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2007.

At December 31, 2005	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	20,794,200	$1.0350 — $1.1013	$1.0718
Purchase	20,202,000	$1.0100 — $1.0450	$1.0703

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expired in 2006.

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.

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Management's Discussion and Analysis

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 have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers convert to oil to satisfy their fuel requirements. Lower levels in interruptible sales occur when oil prices are lower relative to 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 side of this business to maximize sales volumes. As a result of the transmission business’ conversion to open access and the Florida division’s restructuring of its services, their businesses have shifted from providing competitive sales service to providing transportation and contract storage services.

The Company’s natural gas distribution operations located in Delaware, Maryland and Florida offer transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended transportation service to residential customers. With transportation service available on the Company’s distribution systems, the Company is competing with third-party suppliers to sell gas to industrial customers. As it relates to transportation services, the Company’s competitors include the interstate transmission company if the distribution customer is located close enough to the transmission company’s pipeline to make a connection economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the distribution operations in this manner. In certain situations, the 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 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 serviced by natural gas pipeline or distribution systems.

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 than does the Company. In addition, changes in the advanced information services business are occurring rapidly, which could adversely impact 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 labor, products and services required for operation, 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. 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 regulated operations while monitoring the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, Chesapeake adjusts its propane selling prices to the extent allowed by the market.

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Management's Discussion and Analysis

Cautionary Statement

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

o	the temperature sensitivity of the natural gas and propane businesses;

o	the effect of spot, forward and futures market prices on the Company’s distribution, wholesale marketing and energy trading businesses;

o	amount and availability of natural gas and propane supplies and the access to interstate pipelines’ transportation and storage capacity;

o	the effects of natural gas and propane commodity price changes may affect the operating costs and competitive positions of our natural gas and propane distribution operations;

o	the effects of competition on the Company’s unregulated and regulated businesses;

o	the effect of changes in federal, state or local regulatory and tax requirements, including deregulation;

o	the effect of changes in technology on the Company’s advanced information services segment;

o	the effects of credit risk and credit requirements on the Company’s energy marketing subsidiaries;

o	the effect of accounting changes;

o	the effect of changes in benefit plan assumptions;

o	the effect of compliance with environmental regulations or the remediation of environmental damage;

o	the effects of general economic conditions and including interest rates on the Company and its customers;

o	the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues;

o	the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions; and

o	the Company’s ability to obtain necessary approvals and permits by regulatory agencies on a timely basis.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Information concerning quantitative and qualitative disclosure about market risk is included in Item 7 under the heading “Management’s Discussion and Analysis — Market Risk.”

Item 8. Financial Statements and Supplementary Data.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in 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, 2006.

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

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Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and Stockholders

of Chesapeake Utilities Corporation

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

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’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. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Boston, MA

March 13, 2007

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Consolidated Statements of Income

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

Earnings Per Share of Common Stock:
Basic
From continuing operations	$	1.74	$	1.79	$	1.66
From discontinued operations		-		-		(0.02	)
Net Income	$	1.74	$	1.79	$	1.64

Diluted
From continuing operations	$	1.72	$	1.77	$	1.64
From discontinued operations		-		-		(0.02	)
Net Income	$	1.72	$	1.77	$	1.62

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

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Consolidated Statements of Cash Flows

For the Years Ended December 31,	2006			2005			2004
*Operating Activities*
Net Income	$	10,506,525		$	10,467,614		$	9,428,767
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		8,243,715			7,568,209			7,257,538
Depreciation and accretion included in other costs		3,102,066			2,705,620			2,611,779
Deferred income taxes, net		(408,533	)		1,510,777			4,559,207
Unrealized gain (loss) on commodity contracts		37,110			(227,193	)		353,183
Unrealized loss on investments		(151,952	)		(56,650	)		(43,256	)
Employee benefits and compensation		382,608			1,621,607			1,536,586
Other, net		(18,596	)		(62,692	)		67,079
Changes in assets and liabilities:
Sale (purchase) of investments		(177,990	)		(1,242,563	)		43,354
Accounts receivable and accrued revenue		9,705,860			(16,831,751	)		(11,723,505	)
Propane inventory, storage gas and other inventory		354,764			(5,704,040	)		(1,741,941	)
Regulatory assets		2,498,954			(1,719,184	)		428,516
Prepaid expenses and other current assets		(271,438	)		36,704			(221,137	)
Other deferred charges		(231,822	)		(102,561	)		(168,898	)
Long-term receivables		137,101			247,600			428,964
Accounts payable and other accrued liabilities		(11,434,370	)		15,569,924			9,731,360
Income taxes receivable (payable)		1,800,913			(2,006,762	)		(229,237	)
Accrued interest		273,672			(42,376	)		(51,272	)
Customer deposits and refunds		2,361,265			462,781			665,549
Accrued compensation		(542,512	)		875,342			(794,194	)
Regulatory liabilities		2,824,068			144,501			(191,266	)
Other liabilities		1,125,590			385,034			55,977
Net cash provided by operating activities		30,116,998			13,599,941			22,003,153

*Investing Activities*
Property, plant and equipment expenditures		(48,845,828	)		(33,319,613	)		(16,435,938	)
Sale of investments		-			-			135,170
Sale of discontinued operations		-			-			415,707
Environmental recoveries (expenditures)		(15,549	)		240,336			369,719
Net cash used by investing activities		(48,861,377	)		(33,079,277	)		(15,515,342	)

*Financing Activities*
Common stock dividends		(5,982,531	)		(5,789,180	)		(5,560,535	)
Issuance of stock for Dividend Reinvestment Plan		321,865			458,757			200,551
Stock issuance		19,698,509			-
Cash settlement of warrants		(434,782	)		-			-
Change in cash overdrafts due to outstanding checks		49,047			874,083			(143,720	)
Net borrowing (repayment) under line of credit agreements		(7,977,347	)		29,606,400			1,184,742
Proceeds from issuance of long-term debt		20,000,000			-			-
Repayment of long-term debt		(4,929,674	)		(4,794,827	)		(3,665,589	)
Net cash provided (used) by financing activities		20,745,087			20,355,233			(7,984,551	)

*Net Increase (Decrease) in Cash and Cash Equivalents*		2,000,708			875,897			(1,496,740	)
*Cash and Cash Equivalents — Beginning of Period*		2,487,658			1,611,761			3,108,501
*Cash and Cash Equivalents — End of Period*	$	4,488,366		$	2,487,658		$	1,611,761

Supplemental Disclosures of Non-Cash Investing Activities:
Capital property and equipment acquired on account,
but not paid as of December 31	$	1,490,890		$	1,367,348		$	1,678,724

Supplemental Disclosure of Cash Flow information
Cash paid for interest	$	5,334,477		$	5,052,013		$	5,280,299
Cash paid for income taxes	$	6,285,272		$	6,342,476		$	1,977,223

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

- Page 49 -

Consolidated Balance Sheets

Assets
At December 31,	2006			2005
Property, Plant and Equipment
Natural gas distribution and transmission	$	269,012,516		$	220,685,461
Propane		44,791,552			41,563,810
Advanced information services		1,054,368			1,221,177
Other plant		9,147,500			9,275,729
Total property, plant and equipment		324,005,936			272,746,177
Less: Accumulated depreciation and amortization		(85,010,472	)		(78,840,413	)
Plus: Construction work in progress		1,829,948			7,598,531
Net property, plant and equipment		240,825,412			201,504,295

Investments		2,015,577			1,685,635

Current Assets
Cash and cash equivalents		4,488,366			2,487,658
Accounts receivable (less allowance for uncollectible accounts of $661,597 and $861,378, respectively)		44,969,182			54,284,011
Accrued revenue		4,325,351			4,716,383
Propane inventory, at average cost		7,187,035			6,332,956
Other inventory, at average cost		1,564,937			1,538,936
Regulatory assets		1,275,653			4,434,828
Storage gas prepayments		7,393,335			8,628,179
Income taxes receivable		1,078,882			2,725,840
Deferred income taxes		1,365,316			-
Prepaid expenses		2,280,900			2,021,164
Other current assets		1,553,284			1,596,797
Total current assets		77,482,241			88,766,752

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		191,878			205,683
Long-term receivables		824,333			961,434
Other regulatory assets		1,765,088			1,178,232
Other deferred charges		1,215,004			1,003,393
Total deferred charges and other assets		4,670,754			4,023,193


Total Assets	$	324,993,984		$	295,979,875

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

- Page 50 -

Consolidated Balance Sheets

Capitalization and Liabilities
At December 31,	2006			2005
Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares) ⁽¹⁾	$	3,254,998		$	2,863,212
Additional paid-in capital		61,960,220			39,619,849
Retained earnings		46,270,884			42,854,894
Accumulated other comprehensive income		(334,550	)		(578,151	)
Deferred compensation obligation		1,118,509			794,535
Treasury stock		(1,118,509	)		(797,156	)
Total stockholders' equity		111,151,552			84,757,183
Long-term debt, net of current maturities		71,050,000			58,990,363
Total capitalization		182,201,552			143,747,546

Current Liabilities
Current portion of long-term debt		7,656,364			4,929,091
Short-term borrowing		27,553,941			35,482,241
Accounts payable		33,870,552			45,645,228
Customer deposits and refunds		7,502,265			5,140,999
Accrued interest		832,392			558,719
Dividends payable		1,939,482			1,676,398
Deferred income taxes		-			1,150,828
Accrued compensation		2,901,053			3,793,244
Regulatory liabilities		4,199,147			550,546
Other accrued liabilities		4,005,795			3,560,055
Total current liabilities		90,460,991			102,487,349

Deferred Credits and Other Liabilities
Deferred income taxes		26,517,098			24,248,624
Deferred investment tax credits		328,277			367,085
Other regulatory liabilities		1,236,254			2,008,779
Environmental liabilities		211,581			352,504
Accrued pension costs		1,608,311			3,099,882
Accrued asset removal cost		18,410,992			16,727,268
Other liabilities		4,018,928			2,940,838
Total deferred credits and other liabilities		52,331,441			49,744,980

Other Commitments and Contingencies *(Note N)*


Total Capitalization and Liabilities	$	324,993,984		$	295,979,875

⁽¹⁾ Shares issued were 6,688,084 and 5,883,099 for 2006 and 2005, respectively.
Shares outstanding were 6,688,084 and 5,883,002 for 2006 and 2005, respectively.

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

- Page 51 -

Statements of Stockholders' Equity

For the Years Ended December 31,	2006			2005			2004
Common Stock
Balance — beginning of year	$	2,863,212		$	2,812,538		$	2,754,748
Dividend Reinvestment Plan		18,685			20,038			20,125
Retirement Savings Plan		14,457			10,255			19,058
Conversion of debentures		8,117			11,004			9,060
Performance shares and options exercised ⁽¹⁾		14,536			9,377			9,547
Stock issuance		335,991			-			-
Balance — end of year		3,254,998			2,863,212			2,812,538

Additional Paid-in Capital
Balance — beginning of year		39,619,849			36,854,717			34,176,361
Dividend Reinvestment Plan		1,148,100			1,224,874			996,715
Retirement Savings Plan		900,354			682,829			946,319
Conversion of debentures		275,300			373,259			307,940
Performance shares and options exercised ⁽¹⁾		887,426			484,170			427,382
Stock issuance		19,362,518			-			-
Exercise warrants, net of tax		(233,327	)		-			-
Balance — end of year		61,960,220			39,619,849			36,854,717

Retained Earnings
Balance — beginning of year		42,854,894			39,015,087			36,008,246
Net income		10,506,525			10,467,614			9,428,767
Cash dividends ⁽²⁾		(7,090,535	)		(6,627,807	)		(6,403,450	)
Loss on issuance of treasury stock		-			-			(18,476	)
Balance — end of year		46,270,884			42,854,894			39,015,087

Accumulated Other Comprehensive Income
Balance — beginning of year		(578,151	)		(527,246	)		-
Minimum pension liability adjustment, net of tax		74,036			(50,905	)		(527,246	)
Gain on funded status of Employee Benefit Plans, net of tax		169,565			-			-
Balance — end of year		(334,550	)		(578,151	)		(527,246	)

Deferred Compensation Obligation
Balance — beginning of year		794,535			816,044			913,689
New deferrals		323,974			130,426			296,790
Payout of deferred compensation		-			(151,935	)		(394,435	)
Balance — end of year		1,118,509			794,535			816,044

Treasury Stock
Balance — beginning of year		(797,156	)		(1,008,696	)		(913,689	)
New deferrals related to compensation obligation		(323,974	)		(130,426	)		(296,790	)
Purchase of treasury stock		(51,572	)		(182,292	)		(344,753	)
Sale and distribution of treasury stock		54,193			524,258			546,536
Balance — end of year		(1,118,509	)		(797,156	)		(1,008,696	)


Total Stockholders’ Equity	$	111,151,552		$	84,757,183		$	77,962,444

⁽¹⁾ Includes amounts for shares issued for Directors' compensation.
⁽²⁾ Cash dividends declared per share for 2006, 2005 and 2004 were $1.16, $1.14 and $1.12, respectively.

Statements of Comprehensive Income

For the Years Ended December 31,	2006		2005			2004
Net income	$	10,506,525	$	10,467,614		$	9,428,767
Pension liability adjustment, net of tax of $48,889, $33,615 and $347,726, respectively		74,036		(50,905	)		(527,246	)
Comprehensive Income	$	10,580,561	$	10,416,709		$	8,901,521

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

- Page 52 -

Consolidated Statements of Income Taxes

For the Years Ended December 31,	2006			2005			2004
Current Income Tax Expense
Federal	$	5,994,296		$	3,687,800		$	1,221,155
State		1,424,485			789,233			618,916
Investment tax credit adjustments, net		(54,816	)		(54,816	)		(54,816	)
Total current income tax expense		7,363,965			4,422,217			1,785,255

Deferred Income Tax Expense ⁽¹⁾
Property, plant and equipment		1,697,024			1,380,628			4,230,650
Deferred gas costs		(2,085,066	)		1,064,310			283,547
Pensions and other employee benefits		(97,436	)		(340,987	)		(49,620	)
Environmental expenditures		(5,580	)		(98,229	)		(150,864	)
Other		(36,345	)		(115,923	)		(397,878	)
Total deferred income tax expense		(527,403	)		1,889,799			3,915,835
Total Income Tax Expense	$	6,836,562		$	6,312,016		$	5,701,090

Reconciliation of Effective Income Tax Rates
Federal income tax expense ⁽²⁾	$	6,070,080		$	5,872,871		$	5,185,257
State income taxes, net of federal benefit		804,988			708,192			736,176
Other		(38,506	)		(269,047	)		(220,343	)
Total Income Tax Expense	$	6,836,562		$	6,312,016		$	5,701,090
Effective income tax rate		39.4	%		37.6	%		37.4	%

At December 31,		2006			2005
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	27,997,744		$	26,795,452
Environmental costs		204,149			-
Deferred gas costs		-			1,664,252
Other		870,424			612,943
Total deferred income tax liabilities		29,072,317			29,072,647

Deferred income tax assets:
Pension and other employee benefits		2,225,944			2,289,370
Self insurance		468,922			575,303
Environmental costs		-			181,734
Deferred gas costs		528,814			-
Other		696,855			626,788
Total deferred income tax assets		3,920,535			3,673,195
Deferred Income Taxes Per Consolidated Balance Sheet	$	25,151,782		$	25,399,452

⁽¹⁾ Includes ($54,000), $146,000 and $386,000 of deferred state income taxes for the years 2006, 2005 and 2004, respectively.
⁽²⁾ Federal income taxes were recorded at 35% for the years 2006 and 2005. They were recorded at 34% in 2004.

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

- Page 53 -

Notes to the Consolidated Financial Statements

A. Summary of Accounting Policies

Nature of Business

Chesapeake Utilities Corporation (“Chesapeake” or “the Company”) is engaged in natural gas distribution to approximately 59,100 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas transmission subsidiary operates an intrastate 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 approximately 33,300 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 Public Service Commissions with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore Natural Gas Company is an open access pipeline and is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Our financial statements are prepared in accordance with generally accepted accounting principles, 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. 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 3 percent for natural gas distribution and transmission, 5 percent for propane, 11 percent for advanced information services and 7 percent for general plant.

- Page 54 -

Notes to the Consolidated Financial Statements


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

⁽¹⁾ Certain immaterial account balances may fall outside this range.

The regulated operations compute depreciation in accordance with rates approved by either the state Public Service Commission or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage value.

The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.

⁽²⁾ Includes buildings, structures used in connection with natural gas and propane operations, improvements to those facilities and leasehold improvements.

Cash and Cash Equivalents

The Company’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 the market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.

Regulatory Assets, Liabilities and Expenditures

The Company 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, 2006 and 2005, 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.

- Page 55 -

Notes to the Consolidated Financial Statements

At December 31,	2006		2005
Regulatory Assets
Current
Underrecovered purchased gas costs	$	1,076,921	$	4,016,522
Conservation cost recovery		51,408		303,930
Swing transportation imbalances		-		454
PSC Assessment		22,290		-
Flex rate asset		81,926		113,922
Other		43,108		-
Total current		1,275,653		4,434,828

Non-Current
Income tax related amounts due from customers		1,300,544		711,961
Deferred regulatory and other expenses		188,686		89,258
Deferred gas supply		15,201		15,201
Deferred post retirement benefits		138,949		166,739
Environmental regulatory assets and expenditures		121,708		195,073
Total non-current		1,765,088		1,178,232

Total Regulatory Assets	$	3,040,741	$	5,613,060

Regulatory Liabilities
Current
Self insurance — current	$	568,897	$	44,221
Overrecovered purchased gas costs		2,351,553		-
Shared interruptible margins		100,355		3,039
Operational flow order penalties		7,831		7,831
Swing transportation imbalances		1,170,511		495,455
Total current		4,199,147		550,546

Non-Current
Self insurance — long-term		600,787		1,383,247
Income tax related amounts due to customers		285,819		327,893
Environmental overcollections		349,648		297,639
Total non-current		1,236,254		2,008,779

Accrued asset removal cost		18,410,992		16,727,268

Total Regulatory Liabilities	$	23,846,393	$	19,286,593

Included in the regulatory assets listed above are $133,000 of which is accruing interest. Of the remaining regulatory assets, $1.4 million will be collected in approximately one to two years, $310,000 will be collected within approximately 3 to 10 years, and $1.4 million are awaiting regulatory approval for recovery, but once approved are 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 it is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note F “Goodwill and Other Intangible Assets” for additional discussions of this area.

- Page 56 -

Notes to the Consolidated Financial Statements

Other Deferred Charges

Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances. Deferred post-employment benefits are adjusted based on current age, the present value of the projected annual benefit received and estimated life expectancy.

Income Taxes and Investment Tax Credit Adjustments

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

Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements bases and tax bases of assets and liabilities and are measured using current effective income tax rates. 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. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

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 $8,500 and $46,000 at December 31, 2006 and 2005, respectively. Trading liabilities are recorded in other accrued liabilities. Trading assets are recorded in prepaid expenses and other current 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 in SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are accounted for on an accrual basis.

The propane distribution operation has entered into a fair value hedge of its inventory, in order to mitigate the impact of wholesale price fluctuations. At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on our price-cap plan that we offer to customers. The Company considers this agreement to be an economic hedge and does not qualify for hedge accounting as described in SFAS 133. At the end of the period, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.

- Page 57 -

Notes to the Consolidated Financial Statements

Earnings Per Share

The calculations of both basic and diluted earnings per share from continuing operations are presented in the following chart.

For the Periods Ended December 31,	2006		2005		2004
Calculation of Basic Earnings Per Share:
Net Income	$	10,506,525	$	10,467,614	$	9,549,667
Weighted average shares outstanding		6,032,462		5,836,463		5,735,405
Basic Earnings Per Share	$	1.74	$	1.79	$	1.66

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income — Basic	$	10,506,525	$	10,467,614	$	9,549,667
Effect of 8.25% Convertible debentures		105,024		123,559		139,097
Adjusted numerator — Diluted	$	10,611,549	$	10,591,173	$	9,688,764

Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,032,462		5,836,463		5,735,405
Effect of dilutive securities
Stock options		-		-		1,784
Warrants		-		11,711		7,900
8.25% Convertible debentures		122,669		144,378		162,466
Adjusted denominator — Diluted		6,155,131		5,992,552		5,907,555

Diluted Earnings Per Share	$	1.72	$	1.77	$	1.64

Operating Revenues

Revenues for the natural gas distribution operations of the Company are based on rates approved by the various public service commissions. 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 our regulated natural gas distribution operations the ability to negotiate rates with customers that have competitive alternatives using approved methodologies. In addition, the natural gas transmission operation can negotiate rates above or below the FERC-approved tariff rates.

Chesapeake’s Maryland and Delaware natural gas distribution operations each have a gas cost recovery mechanism that provides for the adjustment of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.

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

The propane wholesale marketing operation records trading activity net on the Company’s income statement, on a mark-to-market basis, 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.

Certain Risks and Uncertainties

The 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.

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Notes to the Consolidated Financial Statements

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

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

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”. This statement improves financial reporting by requiring an employer to recognize the over-funded or under-funded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. The Company is required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. The Company adopted SFAS No. 158 as of December 31, 2006. Based on the fair value of plan assets and their related funded status at December 31, 2006, the adoption of SFAS 158 resulted in an increase in total assets by approximately $282,000, an increase in total liabilities by approximately $112,000 and an increase to total shareholders equity by approximately $170,000. Please refer to Note K “Employee Benefit Plans,” for details of each of the Company’s benefit plans.

In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes”. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. This interpretation 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. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. Chesapeake is required to adopt FIN No. 48 in the first quarter of 2007. The Company is currently evaluating the impact that this interpretation will have on our financial statements.

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Notes to the Consolidated Financial Statements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Chesapeake will be required to adopt SFAS No. 157 in the first quarter of 2008. The Company has not yet evaluated the impact that this statement will have on our financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, which expresses the SEC’s views regarding the process of quantifying financial statement misstatements. The application of the guidance in this bulletin is applicable at December 31, 2006. The implementation of this bulletin did not have any impact on the Company’s financial statements.

Reclassification of Prior Years’ Amounts

Certain prior years’ amounts have been reclassified to conform to the current year’s presentation.

B. Business Dispositions and Discontinued Operations

During 2003, Chesapeake decided to exit the water services business and sold six of its seven operations. The remaining operation was sold in October 2004. At December 31, 2006, all property and assets of the water subsidiary have been sold. The results of operations for all water service businesses have been reclassified to discontinued operations for all periods presented. Operating revenues for discontinued operations was $1.1 million and operating losses for discontinued operations was $94,000 for 2004. A loss of $52,000, net of tax, was recorded for 2004 on the sale of the water operations. The Company did not have any discontinued operations in 2006 and 2005.

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Notes to the Consolidated Financial Statements

C. Segment Information

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

For the Years Ended December 31,	2006			2005			2004
Operating Revenues, Unaffiliated Customers
Natural gas distribution, transmission and marketing	$	170,114,514		$	166,388,562		$	124,073,939
Propane		48,575,976			48,975,349			41,499,687
Advanced information services		12,509,077			14,121,441			12,381,815
Other		1,024			144,384			-
Total operating revenues, unaffiliated customers	$	231,200,591		$	229,629,736		$	177,955,441

Intersegment Revenues ⁽¹⁾
Natural gas distribution, transmission and marketing	$	259,969		$	193,404		$	172,427
Propane		-			668			-
Advanced information services		58,532			18,123			45,266
Other		618,493			618,492			647,378
Total intersegment revenues	$	936,994		$	830,687		$	865,071

Operating Income
Natural gas distribution, transmission and marketing	$	19,733,487		$	17,235,810		$	17,091,360
Propane		2,534,035			3,209,388			2,363,884
Advanced information services		767,160			1,196,544			387,193
Other and eliminations		(103,371	)		(111,243	)		127,309
Total operating income	$	22,931,311		$	21,530,499		$	19,969,746

Depreciation and Amortization
Natural gas distribution, transmission and marketing	$	6,312,277		$	5,682,137		$	5,418,007
Propane		1,658,554			1,574,357			1,524,016
Advanced information services		112,729			122,569			138,007
Other and eliminations		160,155			189,146			177,508
Total depreciation and amortization	$	8,243,715		$	7,568,209		$	7,257,538

Capital Expenditures
Natural gas distribution, transmission and marketing	$	43,894,614		$	28,433,671		$	13,945,214
Propane		4,778,891			3,955,799			3,395,190
Advanced information services		159,402			294,792			84,185
Other		321,204			739,079			404,941
Total capital expenditures	$	49,154,111		$	33,423,341		$	17,829,530
⁽¹⁾ All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

At December 31,		2006			2005			2004
Identifiable Assets
Natural gas distribution, transmission and marketing	$	252,292,600		$	225,667,049		$	184,412,301
Propane		60,170,200			57,344,859			47,531,106
Advanced information services		2,573,810			2,062,902			2,387,440
Other		9,957,374			10,905,065			7,379,794
Total identifiable assets	$	324,993,984		$	295,979,875		$	241,710,641

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Notes to the Consolidated Financial Statements

Chesapeake uses the management approach to identify operating segments. Chesapeake organizes its business around differences in products or services and the operating results of each segment are regularly reviewed by the Company’s chief operating decision maker in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income.

The Company’s operations are all 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, 2006 had a gain in fair value of $8,500 and at December 31, 2005 had a gain in fair value of $46,000 based on market rates. 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, 2006, including current maturities, had an estimated fair value of $81.4 million as compared to a carrying value of $78.7 million. At December 31, 2005, the estimated fair value was approximately $68.5 million as compared to a carrying value of $63.9 million. These estimates are based on published corporate borrowing rates for debt instruments with similar terms and average maturities.

E. Investments

The investment balances at December 31, 2006 and 2005 represent a Rabbi Trust (“the 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, we are required to report the securities at their fair value, with any unrealized gains and losses included in other income. We also have an associated liability that is recorded and adjusted each month, along with other expense, for the gains and losses incurred by the trust. At December 31, 2006 and 2005, total investments had a fair value of $2.0 million and $1.7 million.

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, 2006 and 2005. Testing for 2006 and 2005 has indicated that no impairment has occurred.

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Notes to the Consolidated Financial Statements

The carrying value and accumulated amortization of intangible assets subject to amortization for the two years ended December 31, 2006 are as follows:

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

Amortization of intangible assets was $14,000 for the years ended December 31, 2006 and 2005, respectively. The estimated annual amortization of intangibles is $14,000 per year for each of the years 2007 through 2011, respectively.

G. Stockholders’ Equity

The changes in the common stock shares issued and outstanding are shown in the table below:

For the Years Ended December 31,	2006			2005			2004
Common Stock shares issued and outstanding ⁽¹⁾
Shares issued — beginning of period balance		5,883,099			5,778,976			5,660,594
Dividend Reinvestment Plan ⁽²⁾		38,392			41,175			40,993
Retirement Savings Plan		29,705			21,071			39,157
Conversion of debentures		16,677			22,609			18,616
Employee award plan		350			-			-
Performance shares and options exercised ⁽³⁾		29,516			19,268			19,616
Public offering		690,345			-			-
Shares issued — end of period balance ⁽⁴⁾		6,688,084			5,883,099			5,778,976

Treasury shares — beginning of period balance		(97	)		(9,418	)		-
Purchases		-			(4,852	)		(15,316	)
Dividend Reinvestment Plan		-			2,142			-
Retirement Savings Plan		-			12,031			-
Other issuances		97			-			5,898
Treasury Shares — end of period balance		-			(97	)		(9,418	)

Total Shares Outstanding		6,688,084			5,883,002			5,769,558

⁽¹⁾ 12,000,000 shares are authorized at a par value of $0.4867 per share.
⁽²⁾ Includes shares purchased with reinvested dividends and optional cash payments.
⁽³⁾ Includes shares issued for Directors' compensation.
⁽⁴⁾ Includes 48,187, 37,528, and 48,175 shares at December 31, 2006, 2005 and 2004, respectively, held in a Rabbi Trust established by the Company relating to the Executive Deferred Compensation Plan.

In 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, 2006, Chesapeake does not have any stock warrants outstanding.

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Notes to the Consolidated Financial Statements

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

H. Long-term Debt

The outstanding long-term debt, net of current maturities, is as shown below.

At December 31,	2006		2005		2004
Uncollateralized senior notes:
7.97% note, due February 1, 2008	$	1,000,000	$	2,000,000	$	3,000,000
6.91% note, due October 1, 2010		2,727,273		3,636,363		4,545,454
6.85% note, due January 1, 2012		4,000,000		5,000,000		6,000,000
7.83% note, due January 1, 2015		14,000,000		16,000,000		20,000,000
6.64% note, due October 31, 2017		27,272,727		30,000,000		30,000,000
5.50% note, due October 12, 2020		20,000,000		-		-
Convertible debentures:
8.25% due March 1, 2014		1,970,000		2,254,000		2,644,000
Promissory note		80,000		100,000		-
Total Long-Term Debt	$	71,050,000	$	58,990,363	$	66,189,454

Annual maturities of consolidated long-term debt for the next five years are as follows: $7,656,364 for 2007;$7,656,364 for 2008; $6,656,364 for 2009,$6,656,364 for 2010 and $7,747,273 for 2011.

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 2006 and 2005, debentures totaling $284,000 and $385,000, respectively, were converted to stock. The debentures are also redeemable for cash at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000. In 2006, 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

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

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Notes to the Consolidated Financial Statements

As of December 31, 2006, the Company had four unsecured bank lines of credit with two financial institutions, totaling $80.0 million, none of which required compensating balances. These bank lines provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. Two of the bank lines, totaling $15.0 million, are committed. The other two lines are subject to the banks’ availability of funds. Under these lines of credit, the outstanding balances of short-term debt at December 31, 2006 and 2005 were $27.6 million and $35.5 million, respectively. The annual weighted average interest rates on short-term debt were 5.47 percent and 4.47 percent for 2006 and 2005, respectively. The Company also had a letter of credit outstanding in the amount of $775,000 that reduced the amounts available under the lines of credit.

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 $680,000, $837,000, and $934,000 for 2006, 2005 and 2004, respectively. Future minimum payments under the Company’s current lease agreements are $650,000, $496,000, $423,000, $331,000 and $321,000 for the years 2007 through 2011, respectively; and $3.8 million thereafter, totaling $6.0 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. As a result of the amendments to the Defined Pension Plan, a gain of approximately $172,000 (after tax) was recorded during 2004.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). The Company adopted SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize all obligations related to defined benefit 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.

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Notes to the Consolidated Financial Statements

SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. The Company is also required to 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.”

Based on the funded status of the Company’s defined benefit pension and postretirement benefit plans as of December 31, 2006, the effects of adopting SFAS 158 on the Company’s financial statement is set forth in the following table.

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

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

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

The amounts in AOCI for the respective retirement plans that are expected to be recognized as a component of net benefit cost in 2007 is set forth in the following table.

	Defined Benefit Pension			Executive Excess Defined Benefit		Total
Prior service cost (credit)		($4,699	)		-		-
Loss (gain)		(6,846	)		51,279		136,978

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 toward the Defined Pension Plan in 2007. The measurement dates for the Pension Plan were December 31, 2006 and 2005, respectively.

The following schedule summarizes the assets of the Defined Pension Plan, by investment type, at December 31, 2006, 2005 and 2004:

At December 31,	2006			2005			2004
Asset Category
Equity securities		77.34	%		76.12	%		72.64	%
Debt securities		18.59	%		23.28	%		12.91	%
Other		4.07	%		0.60	%		14.45	%
Total		100.00	%		100.00	%		100.00	%

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Notes to the Consolidated Financial Statements

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. Additionally, as changes are made to holdings, cash, money market funds or United States Treasury Bills may be held temporarily by the fund. Investments in the following are prohibited: options, guaranteed investment contracts, real estate, venture capital, private placements, futures, commodities, limited partnerships and Chesapeake stock. Additionally, short selling and margin transactions are prohibited. During 2004, Chesapeake modified its investment policy to allow the Employee Benefits Committee to reallocate investments to better match the expected life of the plan.

The following schedule sets forth the funded status of the Defined Pension Plan at December 31, 2006, 2005 and 2004:

At December 31,	2006			2005			2004
Change in benefit obligation:
Benefit obligation — beginning of year	$	12,399,621		$	12,053,063		$	11,948,755
Service cost		-			-			338,352
Interest cost		635,877			645,740			690,620
Change in assumptions		(301,851	)		388,979			573,639
Actuarial loss		607			28,895			220,842
Amendments		-			-			883,753
Effect of curtailment/settlement		-			-			(2,171,289	)
Benefits paid		(1,284,529	)		(717,056	)		(431,609	)
Benefit obligation — end of year		11,449,725			12,399,621			12,053,063

Change in plan assets:
Fair value of plan assets — beginning of year		11,780,866			12,097,248			11,301,548
Actual return on plan assets		1,543,950			400,674			1,227,309
Benefits paid		(1,284,529	)		(717,056	)		(431,609	)
Fair value of plan assets — end of year		12,040,287			11,780,866			12,097,248

Reconciliation of funded status: ⁽¹⁾
Plan assets in excess (less than) benefit obligation at year-end		590,560			(618,755	)		44,185
Unrecognized prior service cost		-			(34,259	)		(38,958	)
Unrecognized net actuarial gain		-			(129,739	)		(850,224	)
Net amount accrued	$	590,560			($782,753	)		($844,997	)

Assumptions:
Discount rate		5.50	%		5.25	%		5.50	%
Expected return on plan assets		6.00	%		6.00	%		7.88	%

⁽¹⁾ After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.

Net periodic pension costs for the defined benefit Pension Plan for 2006, 2005, and 2004 include the components as shown below:

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

- Page 67 -

Notes to the Consolidated Financial Statements

The following actuarial assumptions were used in calculating net periodic pension cost or benefit.

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

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

Executive Excess Defined Benefit Pension Plan

The Company also sponsors an unfunded executive excess defined benefit pension plan. As noted above, this 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 $2.29 million and $2.32 million at December 31, 2006 and 2005, respectively.

Net periodic pension costs for the executive excess benefit pension plan for 2006, 2005, and 2004 include the components as shown below:

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

- Page 68 -

Notes to the Consolidated Financial Statements

The following schedule sets forth the status of the executive excess defined benefit plan:

At December 31,	2006			2005			2004
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,322,471		$	2,162,952		$	1,406,190
Service cost		-			-			105,913
Interest cost		119,588			119,658			87,568
Actuarial (gain) loss		(65,886	)		133,839			713,225
Amendments		-			-			60,000
Effect of curtailment/settlement		-			-			(184,844	)
Benefits paid		(89,203	)		(93,978	)		(25,100	)
Benefit obligation — end of year		2,286,970			2,322,471			2,162,952

Change in plan assets:
Fair value of plan assets — beginning of year		-			-			-
Employer contributions		89,203			93,978			25,100
Benefits paid		(89,203	)		(93,978	)		(25,100	)
Fair value of plan assets — end of year		-			-			-

Funded status		(2,286,970	)		(2,322,471	)		(2,162,952	)
Unrecognized net actuarial loss		-			959,492			874,972
Net amount accrued ⁽¹⁾		($2,286,970	)		($1,362,979	)		($1,287,980	)

Assumptions:
Discount rate		5.50	%		5.25	%		5.50	%

⁽¹⁾ After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.

The assumptions used for the discount rate of the plan were reviewed by the Company and increased from 5.25 percent to 5.50 percent, reflecting an increase in the interest rates of high quality bonds and a reduction in the expected life of the plan. Since the Plan is frozen in regards to additional years of service and compensation, the rate of assumed pay rate increases is not applicable. The measurement dates for the executive excess benefit plan were December 31, 2006 and 2005, respectively.

Other Postretirement Benefits

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

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

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

- Page 69 -

Notes to the Consolidated Financial Statements

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

At December 31,	2006			2005			2004
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,534,684		$	1,599,280		$	1,471,664
Retirees		264,470			(59,152	)		91,747
Fully-eligible active employees		(114,082	)		(31,761	)		22,071
Other active		78,036			26,317			13,798
Benefit obligation — end of year	$	1,763,108		$	1,534,684		$	1,599,280

Funded status		($1,763,108	)		($1,534,684	)		($1,599,280	)
Unrecognized transition obligation		-			22,282			50,141
Unrecognized net actuarial loss		-			751,450			899,228
Net amount accrued ⁽¹⁾		($1,763,108	)		($760,952	)		($649,911	)

Assumptions:
Discount rate		5.50	%		5.25	%		5.50	%

⁽¹⁾ After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.

The health care inflation rate for 2006 is assumed to be 6 percent for medical and 8 percent for prescription drugs. These rates are projected to gradually decrease to ultimate rates of 5 and 6 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 $250,000 as of January 1, 2007, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2007 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 $207,000 as of January 1, 2007, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2007 by approximately $13,000. The measurement dates were December 31, 2006 and 2005, respectively.

Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the years 2007 through 2011 and the aggregate of the next five years for each of the plans previously described.

	Defined Benefit Pension Plan ⁽¹⁾		Executive Excess Defined Benefit Pension Plan ⁽²⁾		Other Post-Retirement Benefits ⁽²⁾
2007	$	721,575	$	88,096	$	180,205
2008		713,699		86,868		182,977
2009		1,447,370		85,513		185,059
2010		898,179		84,026		204,870
2011		460,335		82,411		194,448
Years 2012 through 2016		4,714,092		758,013		1,010,982

⁽¹⁾ The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
⁽²⁾ Benefit payments are expected to be paid out of the general funds of the Company.

Retirement Savings Plan

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 that elected to no longer participate in the Defined Benefit Plan. The Company makes matching contributions on a basis of up to six percent of each employee's pre-tax compensation for the year for all of the Company’s employees, except the employees for our Advanced Information Services segment. The match is between 100 percent and 200 percent, based on a combination of the employee’s age and years of service. The first 100 percent of the funds are matched with Chesapeake common stock. The remaining match is invested in the Company’s 401(k) Plan according to each employee’s election options.

- Page 70 -

Notes to the Consolidated Financial Statements

Effective July 1, 2006, the matching 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 open to Company executives over a specific income threshold. Participants receive a cash only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the twenty-one mutual funds available for investment. These same funds are available for investment of employee contributions within the Retirement Savings Plan.

The Company’s contributions to the 401(k) plans totaled $1,612,000, $1,681,000 and $1,497,000 for the years ended December 31, 2006, 2005, and 2004, respectively. As of December 31, 2006, there are 77,479 shares reserved to fund future contributions to the Retirement Savings Plan.

L. Share-Based Compensation Plans

Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” which establishes accounting for equity instruments exchanged for employee services. Prior to January 1, 2006, the Company accounted for share-based compensation to employees in accordance with Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The Company also followed the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” Commencing January 1, 2006, the Company elected to adopt the modified prospective method as provided by SFAS No. 123R and, accordingly, financial statement amounts for the prior periods presented have not been retrospectively adjusted to reflect the fair value of expensing stock-based compensation.

Stock Options

The Company did not have any stock options outstanding at December 31, 2006 or December 31, 2005, nor were any stock options issued during 2006.

Director Stock Compensation Plan (“DSCP”)

Under the Company’s DSCP, each non-employee director receives an annual retainer of 600 shares of common stock and an additional 150 shares of common stock for services as a committee chairman, subject to adjustment in future years consistent with the terms of the DSCP. Shares issued under the DSCP are fully vested as of the date of the grant. At the date of grant, the Company records a prepaid expense equal to the fair value of the shares issued and amortizes the expense equally over the service period of one year. Compensation expense recorded by the Company relating to the DSCP awards was $165,000 and $140,000 for 2006 and 2005, respectively.

- Page 71 -

Notes to the Consolidated Financial Statements

A summary of restricted stock activity for the DSCP as of December 31, 2006 is presented below:

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

As of December 31, 2006, there were 63,300 shares reserved for issuance under the terms of the Company’s Director’s Stock Compensation Plan.

Performance Incentive Plans (“PIP”)

The Company’s Compensation Committee of the Board of Directors is authorized to grant to key employees of the Company the rights to receive awards of shares of the Company’s common stock, contingent upon the achievement of established performance goals. These goals consist of annual or three-year performance targets. The awards are made pursuant to the Company’s Performance Incentive Plan, subject to certain post-vesting transfer restrictions, and are granted in the first quarter of each year and are issued based upon the performance achieved in the previous fiscal year or three-year award period. In the first quarters of 2006 and 2005, the Company issued 23,666 and 10,130 shares, respectively, to key employees as PIP stock awards for each of the preceding fiscal years. Please note that 2005 concluded the three-year performance period and these awards were issued in the first quarter of 2006 and included in the 23,666 stock awards.

The Company accrues an expense each month of the fiscal year representing an estimate of the value of the stock awards granted for the current fiscal year. This accrual process matches the compensation expense with the employees’ service period rather than recognizing the expense on the issue date, which occurs in the first quarter of the subsequent year. The shares issued under the PIP are fully vested and the fair value of each share is equal to the estimated market price of the Company’s stock on the date issued. Compensation expense recorded by the Company in 2006 and 2005 relating to the PIP was $544,000 and $721,000, respectively.

A summary of restricted stock activity for the PIP for 2006 is presented below:

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

As of December 31, 2006, there were 293,480 shares reserved for issuance under the terms of the Company’s Performance Incentive Plan.

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 gas manufacturing plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former gas manufacturing 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 gas manufacturing plant site located in Cambridge, Maryland. The following provides details of each site.

- Page 72 -

Notes to the Consolidated Financial Statements

Dover Gas Light Site

The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action 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 United States 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, 2006, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through December 2006 from other parties or through rates. As of December 31, 2006, 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 permanently decommission 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. In November 2002, Chesapeake submitted a letter to the MDE requesting a No Further Action determination. The Company has been in discussions with the MDE regarding such request and is awaiting a determination from the MDE.

Through December 31, 2006, the Company has incurred approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $1.8 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover through its rates charged to customers the remaining $1.1 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 an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven site with the FDEP. The Work Plan described the Company’s proposal to undertake an AS/SVE pilot study to evaluate the site. After discussions with the FDEP, the Company filed a modified Work Plan, the 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.

- Page 73 -

Notes to the Consolidated Financial Statements

The Company has accrued a liability of $212,000 as of December 31, 2006 for the Winter Haven Coal Gas site. Through December 31, 2006, the Company has incurred approximately $1.7 million of environmental costs associated with this site. At December 31, 2006, the Company had collected $90,000 through rates in excess of costs incurred. A regulatory asset of approximately $122,000, representing the uncollected portion of the estimated clean-up costs, has also been recorded. The Company expects to recover the remaining 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 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 requirements 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 gas manufacturing 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.

N. Other Commitments and Contingencies

Natural Gas and Propane Supply

The Company’s natural gas and propane distribution operations have entered into contractual commitments for gas from various suppliers. The contracts have various expiration dates. In November 2004, 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. The contract expires March 31, 2007.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Florida natural gas supply and management subsidiary, and Delmarva propane distribution subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’ default. The liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at December 31, 2006 totaled $21.4 million, with the guarantees expiring on various dates in 2007.

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.

- Page 74 -

Notes to the Consolidated Financial Statements

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. 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

2006
Operating Revenue	$	90,950,672	$	44,303,752	$	35,141,531		$	60,804,636
Operating Income	$	11,437,228	$	3,205,368	$	162,137		$	8,126,578
Net Income (Loss)	$	6,096,416	$	1,132,509		($656,579	)	$	3,934,179
Earnings per share:
Basic	$	1.03	$	0.19		($0.11	)	$	0.63
Diluted	$	1.01	$	0.19		($0.11	)	$	0.62

2005
Operating Revenue	$	77,845,248	$	42,220,377	$	35,155,121		$	74,408,990
Operating Income (Loss)	$	11,504,343	$	2,324,945		($99,149	)	$	7,800,360
Net Income (Loss)	$	6,232,796	$	795,924		($693,774	)	$	4,132,668
Earnings per share:
Basic	$	1.08	$	0.14		($0.12	)	$	0.70
Diluted	$	1.05	$	0.14		($0.12	)	$	0.69

- Page 75 -

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.

None

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, 2006. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2006.

Changes in Internal Controls

During the quarter ended December 31, 2006, there was no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

See Management’s Report on Internal Control Over Financial Reporting in Item 8, “Financial Statements and Supplemental Data.”

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, 2006. In addition, on May 26, 2006 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.

Item 9B. Other Information.

The Company filed a Current Report on Form 8-K, dated November 29, 2006, discussing the Compensation Committee’s (the “Committee”) actions on that date, including their approval of the compensation arrangements relating to the executive officers of the Company for 2007.

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

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

- Page 76 -

Part III

Item 10. Directors, Executive Officers of the Registrant and Corporate Governance.

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, 2007 in connection with the Company’s Annual Meeting to be held on May 2, 2007.

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

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, 2007, in connection with the Company’s Annual Meeting to be held on May 2, 2007.

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, 2007 in connection with the Company’s Annual Meeting to be held on May 2, 2007.

- Page 77 -

The following table sets forth information as of December 31, 2006, 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

⁽¹⁾

N/A

381,431

⁽²⁾

Equity compensation plans not approved by security holders

⁽³⁾

N/A

Total

381,481

⁽¹⁾ All options to purchase shares under the 1992 Performance Incentive Plan, as amended, were exercised as of 12/31/05.

⁽²⁾ Includes 293,481 shares under the 2005 Performance Incentive Plan, 63,300 shares available under the 2005 Directors Stock Compensation Plan, and 24,650 shares available under the 2005 Employee Stock Awards Plan.

⁽³⁾ All warrants were exercised in 2006.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

None

Item 14. Principal Accounting Fees and Services.

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

- Page 78 -

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, 2006, 2005 and 2004

·	Consolidated Balance Sheets at December 31, 2006 and December 31, 2005

·	Consolidated Statements of Cash Flows for each of the three years ended December 31, 2006, 2005 and 2004

·	Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2006, 2005 and 2004

·	Consolidated Statements of Comprehensive Income for each of the three years ended December 31, 2006, 2005 and 2004

·	Consolidated Statements of Income Taxes for each of the three years ended December 31, 2006, 2005 and 2004

·	Notes to Consolidated Financial Statements

2. Financial Statement Schedule — 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

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

Amended 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 Bylaws of Chesapeake Utilities Corporation, effective February 24, 2005, is incorporated herein by reference to Exhibit 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.

· 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.

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· 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 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 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 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 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 5.1

Opinion of Baker & Hostetler LLP is incorporated herein by reference to Exhibit 5.1 of the Company’s Registration Statement on Form S-3, Reg. No. 333-135602, dated July 5, 2006.

· Exhibit 5.2

Opinion of Baker & Hostetler LLP is incorporated herein by reference to Exhibit 5.1 of the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.

· Exhibit 10.1*

Non-Employee Director Compensation Arrangements, incorporated herein by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.

· Exhibit 10.2*

Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 2005, is incorporated herein by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.

· Exhibit 10.3*

Chesapeake Utilities Corporation Directors Stock Compensation Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

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· Exhibit 10.4*

Chesapeake Utilities Corporation Employee Stock Award Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

· Exhibit 10.5*

Chesapeake Utilities Corporation Performance Incentive Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

· Exhibit 10.6*

Deferred Compensation Program (as amended and restated as of December 7, 2006) is incorporated herein by reference to Exhibit 10 of the Company’s Current Report on Form 8-K, filed December 13, 2006, File No. 001-11590.

· Exhibit 10.7*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.

· Exhibit 10.8*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.

· Exhibit 10.9*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.

· Exhibit 10.10*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.

· Exhibit 10.11*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is filed herewith.

· Exhibit 10.12*

Performance Share Agreement dated December 15, 2006, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.

· Exhibit 10.13*

Performance Share Agreement dated December 23, 2006, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.

· Exhibit 10.14*

Performance Share Agreement dated December 27, 2006, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.

· Exhibit 10.15*

Performance Share Agreement dated December 29, 2006, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.

· Exhibit 10.16*

· Exhibit 12

Computation of Ratio of Earning to Fixed Charges, filed herewith.

· Exhibit 14

Code of Ethics for Financial Officers, filed herewith.

· Exhibit 21

Subsidiaries of the Registrant, filed herewith.

· Exhibit 23.1

Consent of Independent Registered Public Accounting Firm is incorporated herein by reference to Exhibit 23.1 to the Company’s Registration Statement on Form S-3, Reg. No. 333-135602, dated July 5, 2006.

· Exhibit 23.2

Consent of Independent Registered Public Accounting Firm is incorporated herein by reference to Exhibit 23.1 to the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.

· Exhibit 23.3

Consent of Baker & Hostetler LLP (included in Exhibit 5.1).

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· Exhibit 23.4

Consent of Baker & Hostetler LLP (included in Exhibit 5.2).

· Exhibit 23.5

Consent of Independent Registered Public Accounting Firm, filed herewith.

· Exhibit 24

Power of Attorney is incorporated herein by reference to Exhibit 24.1 of the Company’s Registration Statement on Form S-3, Reg. No. 333-135602, dated July 5, 2006.

· Exhibit 31.1

Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 13, 2007, filed herewith.

· Exhibit 31.2

Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 13, 2007, filed herewith.

· Exhibit 32.1

Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 13, 2007, filed herewith.

· Exhibit 32.2

Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 13, 2007, filed herewith.

* Management contract or compensatory plan or agreement.

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Signatures

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

Chesapeake Utilities Corporation

By: /s/ John R. Schimkaitis

John R. Schimkaitis

President and Chief Executive Officer

Date: March 13, 2007

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 21, 2007	Date: March 13, 2007

/s/ Michael P. McMasters	/s/ Richard Bernstein
Michael P. McMasters, Senior Vice President	Richard Bernstein, Director
and Chief Financial Officer	Date: February 21, 2007
(Principal Financial and Accounting Officer)
Date: March 13, 2007

/s/ Eugene H. Bayard	/s/ Thomas J. Bresnan
Eugene H. Bayard, Director	Thomas J. Bresnan, Director
Date: February 21, 2007	Date: March 13, 2007

/s/ Thomas P. Hill	/s/ Walter J. Coleman
Thomas P. Hill, Director	Walter J. Coleman, Director
Date: February 21, 2007	Date: February 21, 2007

/s/ J. Peter Martin	/s/ Joseph E. Moore, Esq.
J. Peter Martin, Director	Joseph E. Moore, Esq., Director
Date: February 21, 2007	Date: February 21, 2007

/s/ Calvert A. Morgan, Jr.,
Calvert A. Morgan, Jr., Director
Date: February 21, 2007

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Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts

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


⁽¹⁾ Recoveries.
⁽²⁾ Uncollectible accounts charged off.

Upon written request, Chesapeake will provide, free of charge, a copy of any Exhibit to the 2006 Annual Report on Form 10-K not included in this document.