Chesapeake Utilities (CPK) 10-K 2005 FY Annual report

 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, 2005              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, 2005, 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 $170 million.

As of March 2, 2006, 5,925,945 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders are incorporated by reference in Part III.

Chesapeake Utilities Corporation

Form 10-K

YEAR ENDED DECEMBER 31, 2005

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	1
Item 1A. Risk Factors	8
Item 1B. Unresolved Staff Comments	11
Item 2. Proprties	11
Item 3. Legal Proceedings	11
Item 4. Submission of Matters to a Vote of Security Holders	11
Part II	12
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	12
Item 6. Selected Financial Data	14
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	36
Item 8. Financial Statements and Supplemental Data	36
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	67
Item 9A. Controls and Procedures	67
Item 9B. Other Information	67
Part III	68
Item 10. Directors and Executive Officers of the Registrant	68
Item 11. Executive Compensation	68
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	68
Item 13. Certain Relationships and Related Transactions	69
Item 14. Principal Accounting Fees and Services	69
Part IV	70
Item 15. Exhibits, Financial Statement Schedules	70
Signatures	73

Part I

Safe Harbor for Forward-Looking Statements

References in this document to “Chesapeake,” “the Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation and/or its wholly owned subsidiaries, as appropriate. Chesapeake Utilities Corporation has made statements in this Form 10-K 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 margins, capital expenditures, environmental remediation costs, regulatory approvals, 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.

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 54,800 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 331-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 32,900 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 and transmission, 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 and Transmission

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”).

Delaware and Maryland. Chesapeake’s Delaware and Maryland utility divisions serve approximately 42,000 customers, of which approximately 41,800 are residential and commercial customers purchasing gas primarily for heating purposes. The remainder are industrial customers. For the year 2005, residential and commercial customers accounted for approximately 75% of the volume delivered by the divisions and 68% of the divisions’ revenue.

- Page 1 -

Florida. The Florida division distributes natural gas to approximately 13,100 residential and commercial and 100 industrial customers in Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee, Liberty and Citrus Counties. Currently the industrial customers, which purchase and transport gas on a firm basis, account for approximately 90% of the volume delivered by the Florida division and 45% of the revenues. These customers are primarily engaged in the citrus and phosphate industries and in electric cogeneration. PESCO provides natural gas supply management services to 285 customers on the Company’s Florida division, which operates as Central Florida Gas and an additional 424 customers on the Peoples Gas system, a subsidiary of TECO Energy, headquartered in Tampa, Florida. During 2005, Chesapeake formed a new wholly owned subsidiary, Peninsula Pipeline Company, Inc. to deliver natural gas 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 which 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 six (6) months notice for termination; (b) firm transportation capacity of 311 Dt per day for December through February, expiring in 2006; (c) firm transportation capacity of 174 Dt per day, which expires in 2008; (d) firm transportation capacity of 1,842 Dt, currently released from Eastern Shore, which expires in 2006; (e) firm storage service, providing a total capacity of 142,830 Dt, with provisions to continue from year to year, subject to six (6) months notice for termination; and (f) firm storage service, providing a total capacity of 17,967 Dt, currently released from Eastern Shore, which expires in 2006.

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.

- Page 2 -

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 43,787 Dt per day for the period December through February, 42,565 Dt per day for the months of November, March and April, and 33,489 Dt per day for the period May through October, with various expiration dates ranging from 2005 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, which expires in 2006.

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 29,700 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 from year to year, subject to six (6) months notice for termination; (b) firm transportation capacity of 155 Dt per day for December through February, expiring in 2006; (c) firm transportation capacity of 973 Dt, currently released from Eastern Shore, which expires in 2006; (d) firm storage service providing a total capacity of 33,120 Dt, with provisions to continue from year to year, subject to six months notice for termination ; and (e) firm storage service, providing a total capacity of 5,489 Dt, currently released from Eastern Shore, which expires in 2006.

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; and (e) firm storage service providing a peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which expires in 2018. 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.

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 16,278 Dt per day for the period December through February, 15,554 Dt per day for the months of November, March and April and 10,993 Dt per day for the period May through October, with various expiration dates ranging from 2006 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, which expires in 2006.

- Page 3 -

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 firm daily entitlement of 7,500 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 transportation service from Florida Gas Transmission Company (“FGT”), a major interstate pipeline. Chesapeake has contracts with FGT for: (a) daily firm transportation capacity of 27,579 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.

The Florida division also began receiving transportation service from Gulfstream Natural Gas System (“Gulfstream”), beginning in June 2002. Chesapeake has a contract with Gulfstream for daily firm transportation capacity of 10,000 Dt daily. The contract with Gulfstream expires May 31, 2022.

PESCO currently has a contract with Eagle Energy Partners for the purchase of firm natural gas supply. This contract provides the availability of a maximum firm daily entitlement of 7,500 MMBtus. The gas purchase contract expires in April 2006.

Eastern Shore. Eastern Shore has 2,720 thousand cubic feet (“Mcf”) of firm transportation capacity under contract with Transco, which expires in 2008. Eastern Shore also has contracts with Transco for: (a) 5,406 Mcf of firm peak day entitlements and total storage capacity of 267,981 Mcf, which expires in 2013; and (b) 1,640 Mcf of firm peak day entitlements and total storage capacity of 10,283 Mcf, which expires in 2006.

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.

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.”

- Page 4 -

(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 2005, our propane distribution operations served approximately 32,900 propane customers on the Delmarva Peninsula, southeastern Pennsylvania and in Florida and delivered approximately 26 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 domestic oil companies and independent producers of gas liquids and oil. 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.

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 in portable cylinders or 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.”

- Page 5 -

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 wholly owned subsidiary, 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.

(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, 2005, Chesapeake had 423 employees, including 185 in natural gas, 140 in propane and 60 in advanced information services. The remaining 38 employees are considered general and administrative and include officers of the Company, treasury, accounting, internal audit, information technology, human resources and other administrative personnel.

- Page 6 -

(v) Executive Officers of the Registrant

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

John R. Schimkaitis (age 58) 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.

Paul M. Barbas (age 49) Mr. Barbas is Chief Operating Officer of Chesapeake Utilities Corporation. He was appointed to his current position effective January 1, 2006. He previously served as Executive Vice President and President of Chesapeake Service Company. He was appointed Executive Vice President in 2004 and served as Vice President and President of Chesapeake Service Company since joining the company in 2003. Prior to joining Chesapeake, Mr. Barbas was Executive Vice President of Allegheny Power. Mr. Barbas joined Allegheny Energy as President of Allegheny Ventures in 1999 and was appointed Executive Vice President of Allegheny Power in 2001. Prior to 1999 Mr. Barbas held a variety of executive positions within G.E. Capital.

Michael P. McMasters (age 47) 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 45) 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 39) 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 53) 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 25-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 (“the 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.

- Page 7 -

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 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 the company’s results of operations, cash flows and financial condition.

The Company’s regulated utility and propane distribution operations are weather sensitive, with a significant portion of its revenues derived from the delivery of natural gas and propane to residential and commercial heating customers during the winter season. Generally, weather conditions directly influence the volume of natural gas and propane delivered by the regulated utility and propane distribution operations.

Regulation of Chesapeake, including changes in the regulatory environment in general, may adversely affect the company’s results of operations, cash flows and financial condition.

The state Public Service Commissions of Delaware, Maryland and Florida regulate the natural gas distribution operations. The Company’s natural gas transmission operation is regulated by the FERC. These regulatory commissions set the rates in their respective jurisdictions that the Company can charge customers for its rate-regulated services. Changes in these rates, as ordered by regulatory commissions, affect the Company’s financial performance.

The Company expects that regulatory commissions will continue to set the prices for delivery service that give it an opportunity to earn a just and reasonable rate of return on the capital invested in its distribution system and to recover reasonable operating expenses.

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 the Company’s control, such as weather and refinery closings. The Company believes it has adequate resources to meet its customer’s needs. See discussion on adequacy of resources in Item 1 under the heading “Business — Narrative Description of Business.”

- Page 8 -

Chesapeake relies on direct connections to interstate pipelines and storage capacity. If these pipelines or storage facilities were unable to deliver for any reason it could impair Chesapeake’s ability to meet its customers’ full requirements.

Chesapeake is responsible for acquiring both sufficient natural gas supplies and interstate pipeline and storage capacity to meet customer requirements. As such, Chesapeake must contract for reliable and adequate delivery capacity to its distribution system, while considering the dynamics of the interstate pipeline and storage capacity market, its own on-system peak-shaving facilities, as well as the characteristics of its customer base.

Local distribution companies, including Chesapeake, along with other participants in the energy industry, have raised concerns regarding the gradual depletion in the availability of additional upstream interstate pipeline and storage capacity. Diminishing pipeline and storage capacity is a business issue that must be managed by the Company, whose customer base has grown at an annual rate between seven and nine percent. This rate of growth is expected to continue. To help maintain the adequacy of pipeline and storage capacity for its growing customer base, the Company has contracted with various interstate pipeline and storage companies for the acquisition of additional existing capacity, as well as, the construction of new capacity by ESNG. The Company will continue to monitor other opportunities to acquire or participate in obtaining additional pipeline and storage capacity that will improve or maintain the high level of service expected by its customer base.

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

Natural Gas

Increased prices of natural gas are being driven by increased demand that is exceeding the growth in available supply. As discussed above, the fall 2005 hurricane season significantly reduced the current and anticipated availability of natural gas supply from the Gulf Coast region, causing a dramatic rise in natural gas prices during the fourth quarter of fiscal year 2005. The higher natural gas prices resulted in significant increases in the cost of gas billed to customers during the upcoming 2005-2006 winter heating season. Under its regulated gas cost recovery mechanisms, Chesapeake records cost of gas expense equal to the cost of gas recovered in revenues from customers. Accordingly, an increase in the cost of gas due to an increase in the purchase price of the natural gas commodity generally has no direct effect on the regulated utility’s net revenues and net income. However, 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 firm customers that may result due to lower natural gas consumption caused by customer conservation. Increases in the price of natural gas also can affect the Company’s 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 retail sales price and product cost. The unit cost of propane is subject to volatile changes as a result of product supply or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that the Company will be able to pass on product cost increases fully or immediately, particularly when product 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, as was experienced in fiscal 2005, retail sales volumes may be negatively impacted by customer conservation efforts and increased amounts of uncollected accounts.

The replacement of less efficient gas appliances with more energy efficient appliances will result in a decline of consumption per customer, which will lead to reduced revenues.

Natural gas and propane supply requirements may be affected by changes in natural gas and propane consumption by end-use customers. Natural gas and propane usage per customer will decline as customers replace older, less efficient gas appliances with more efficient appliances. In addition, homebuilders in each of the growth areas are installing the newer, more efficient appliances in the homes they build.

- Page 9 -

Each of Chesapeake’s segments competes in a competitive environment and may be faced with losing customers to a competitor.

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

A change in Chesapeake’s approved rate mechanisms for recovery of environmental remediation costs at former manufacturer gas sites could adversely affect the company’s results of operations, cash flows and financial condition.

The Company and its subsidiaries are subject to federal, state and local laws and regulations related to environmental matters. These evolving laws and regulations may require expenditures over a long time frame to control environmental effects. Refer to Note M of the Notes to Consolidated Financial Statements for a further discussion of these matters.

A change in the economic conditions and interest rates could adversely affect the company’s results of operations and cash flows.

The Company and its subsidiaries operate in one of the fastest growing regions in the nation. The continued prosperity of this region, supported by a relatively low interest-rate environment, has allowed our regulated utility to expand its delivery services to its customer base at a rate of growth approximately twice the national industry average during the past five years. A downturn in the economy of the region in which we operate, or a significant increase in interest rates, which cannot be predicted with accuracy, might adversely affect the Company’s ability to grow its regulated utility customer base and other businesses at the same rate they have grown in the recent past.

The Company has been operating in a relatively low interest-rate environment in the recent past as it relates to long-term debt financings. Short-term interest rates had been relatively low in relation to historical levels; however, actions and communications by the Federal Reserve in the past year have resulted in increases in short-term interest rates. A rise in interest rates without the recovery of the higher cost of debt in the sales and/or transportation rates the Company charges its utility customers could adversely affect future earnings. A rise in short-term interest rates would negatively affect the results of operations, which depend on short-term debt to finance accounts receivable and storage gas inventories.

Inflation / Deflation conditions may impact Chesapeake’s results of operations, cash flows, and financial position.

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

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

The 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.

The Company’s propane wholesale and marketing operation has credit risk that could adversely affect the Company’s results of operations, cash flows, and financial condition.

The propane wholesale and marketing operation extends credit to its counter-parties. Despite prudent credit policies, the Company 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 collateral the Company has secured is inadequate, the Company could experience financial losses.

Chesapeake’s use of derivative instruments could adversely affect the company’s results of operations.

The Company’s propane distribution operation uses derivative instruments, including forwards, swaps, and puts, to hedge propane price risk. Fluctuating propane prices cause earnings and financing costs of Chesapeake to be impacted. The use of derivative instruments that are not perfectly matched to the exposure could adversely affect the Company’s results of operations, cash flows, and financial conditions.

- Page 10 -

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 Atlanta, 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 880 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas and 695 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 331 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

- Page 11 -

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 2005 and 2004 were as follows:

Quarter Ended	High		Low		Close		Dividends Declared Per Share
2005
March 31	$	27.5900	$	25.8300	$	26.6000	$	0.2800
June 30		30.9500		23.6000		30.5800		0.2850
September 30		35.6000		59.5000		35.1620		0.2850
December 31		35.7799		30.3227		30.8000		0.2850
2004
March 31	$	26.5100	$	24.3000	$	25.6200	$	0.2750
June 30		26.2000		20.4200		22.7000		0.2800
September 30		25.4000		22.1000		25.1000		0.2800
December 31		27.5500		24.5000		26.7000		0.2800

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 2005 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.

At December 31, 2005, there were approximately 2,026 shareholders of record of the Common Stock.

- Page 12 -

(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, 2005.

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, 2005 through October 31, 2005 (1)		295	$	36.00		0		0
November 1, 2005 through November 30, 2005		0	$	0.00		0		0
December 1, 2005 through December 31, 2005		0	$	0.00		0		0
Total		295	$	36.00		0		0
(1) Chesapeake purchased shares of stock on the open market to add to shares held in a Rabbi Trust to adjust the balance to the contractual value. 295 shares were purchased through executive dividend deferrals.
(2) Chesapeake has no publicly announced plans or programs to repurchase its shares.

See discussion on compensation plans of Chesapeake and its subsidiaries under which shares of Chesapeake common stock are authorized for issuance in Item 12 under the heading “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

- Page 13 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2005			2004			2003			2002 (1)			2001 (1)
Operating (in thousands of dollars) (3)
Revenues
Natural gas distribution and transmission	$	166,582		$	124,246		$	110,247		$	93,588		$	107,418
Propane		48,976			41,500			41,029			29,238			35,742
Advanced informations systems		14,140			12,427			12,578			12,764			14,104
Other and eliminations		(68	)		(218	)		(286	)		(334	)		(113	)
Total revenues	$	229,630		$	177,955		$	163,568		$	135,256		$	157,151
Operating income
Natural gas distribution and transmission	$	17,236		$	17,091		$	16,653		$	14,973		$	14,405
Propane		3,209			2,364			3,875			1,052			913
Advanced informations systems		1,197			387			692			343			517
Other and eliminations		(112	)		128			359			237			386
Total operating income	$	21,530		$	19,970		$	21,579		$	16,605		$	16,221
Net income from continuing operations	$	10,468		$	9,550		$	10,079		$	7,535		$	7,341
Assets (in thousands of dollars)
Gross property, plant and equipment	$	280,345		$	250,267		$	234,919		$	229,128		$	216,903
Net property, plant and equipment (4)	$	201,504		$	177,053		$	167,872		$	166,846		$	161,014
Total assets (4)	$	295,980		$	241,938		$	222,058		$	223,721		$	222,229
Capital expenditures (3)	$	33,423		$	17,830		$	11,822		$	13,836		$	26,293
Capitalization (in thousands of dollars)
Stockholders' equity	$	84,757		$	77,962		$	72,939		$	67,350		$	67,517
Long-term debt, net of current maturities		58,991			66,190			69,416			73,408			48,409
Total capitalization	$	143,748		$	144,152		$	142,355		$	140,758		$	115,926
Current portion of long-term debt	$	4,929		$	2,909		$	3,665		$	3,938		$	2,686
Short-term debt		35,482			5,002			3,515			10,900			42,100
Total capitalization and short-term financing	$	184,159		$	152,063		$	149,535		$	155,596		$	160,712
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.
(2) The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.
(3) 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.
(4) The years 2005, 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS 143.

- Page 14 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2000 (1)			1999 (1)			1998 (2)			1997 (2)			1996 (2)
Operating (in thousands of dollars) (3)
Revenues
Natural gas distribution and transmission	$	101,138		$	75,637		$	68,770		$	88,108		$	90,044
Propane		31,780			25,199			23,377			28,614			36,727
Advanced informations systems		12,390			13,531			10,331			7,786			7,230
Other and eliminations		(131	)		(14	)		(15	)		(182	)		(243	)
Total revenues	$	145,177		$	114,353		$	102,463		$	124,326		$	133,758
Operating income
Natural gas distribution and transmission	$	12,798		$	10,388		$	8,820		$	9,240		$	9,627
Propane		2,135			2,622			965			1,137			2,668
Advanced informations systems		336			1,470			1,316			1,046			1,056
Other and eliminations		816			495			485			558			560
Total operating income	$	16,085		$	14,975		$	11,586		$	11,981		$	13,911
Net income from continuing operations	$	7,665		$	8,372		$	5,329		$	5,812		$	7,764
Assets (in thousands of dollars)
Gross property, plant and equipment	$	192,925		$	172,068		$	152,991		$	144,251		$	134,001
Net property, plant and equipment (4)	$	131,466		$	117,663		$	104,266		$	99,879		$	94,014
Total assets (4)	$	211,764		$	166,958		$	145,029		$	145,719		$	155,786
Capital expenditures (3)	$	22,057		$	21,365		$	12,516		$	13,471		$	15,399
Capitalization (in thousands of dollars)
Stockholders' equity	$	64,669		$	60,714		$	56,356		$	53,656		$	50,700
Long-term debt, net of current maturities		50,921			33,777			37,597			38,226			28,984
Total capitalization	$	115,590		$	94,491		$	93,953		$	91,882		$	79,684
Current portion of long-term debt	$	2,665		$	2,665		$	520		$	1,051		$	3,526
Short-term debt		25,400			23,000			11,600			7,600			12,735
Total capitalization and short-term financing	$	143,655		$	120,156		$	106,073		$	100,533		$	95,945
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.
(2) The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.
(3) 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.
(4) The years 2005, 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS 143.

- Page 15 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2005			2004			2003			2002 (1)			2001 (1)
Common Stock Data and Ratios
Basic earnings per share from continuing operations (3)	$	1.79		$	1.66		$	1.80		$	1.37		$	1.37
Diluted earnings per share from continuing operations (3)	$	1.77		$	1.64		$	1.76		$	1.37		$	1.35
Return on average equity from continuing operations (3)		12.9	%		12.7	%		14.4	%		11.2	%		11.1	%
Common equity / total capitalization		59.0	%		54.1	%		51.2	%		47.8	%		58.2	%
Common equity / total capitalization and short-term financing		46.0	%		51.3	%		48.8	%		43.3	%		42.0	%
Book value per share	$	14.41		$	13.49		$	12.89		$	12.16		$	12.45
Market price:
High	$	35.780		$	27.550		$	26.700		$	21.990		$	19.900
Low	$	23.600		$	20.420		$	18.400		$	16.500		$	17.375
Close	$	30.800		$	26.700		$	26.050		$	18.300		$	19.800
Average number of shares outstanding		5,836,463			5,735,405			5,610,592			5,489,424			5,367,433
Shares outstanding at year-end		5,845,571			5,730,801			5,612,935			5,500,357			5,394,516
Registered common shareholders		2,026			2,026			2,069			2,130			2,171
Cash dividends declared per share	$	1.14		$	1.12		$	1.10		$	1.10		$	1.10
Dividend yield (annualized) (4)		3.7	%		4.2	%		4.2	%		6.0	%		5.6	%
Payout ratio from continuing operations (3) (5)		63.7	%		67.5	%		61.1	%		80.3	%		80.3	%
Additional Data
Customers
Natural gas distribution and transmission		54,786			50,878			47,649			45,133			42,741
Propane distribution		35,367			34,888			34,894			34,566			35,530
Volumes
Natural gas deliveries (in MMCF)		34,981			31,430			29,375			27,935			27,264
Propane distribution (in thousands of gallons)		26,178			24,979			25,147			21,185			23,080
Heating degree-days (Delmarva Peninsula)		4,792			4,553			4,715			4,161			4,368
Propane bulk storage capacity (in thousands of gallons)		2,315			2,045			2,195			2,151			1,958
Total employees (3)		423			426			439			455			458
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.
(2) The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.
(3) 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.
(4) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend declared by four (4), then dividing that amount by the closing common stock price at December 31.
(5) 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 16 -

Item 6. Selected Financial Data

For the Years Ended December 31,	2000 (1)			1999 (1)			1998 (2)			1997 (2)			1996 (2)
Common Stock Data and Ratios
Basic earnings per share from continuing operations (3)	$	1.46		$	1.63		$	1.05		$	1.17		$	1.58
Diluted earnings per share from continuing operations (3)	$	1.43		$	1.59		$	1.04		$	1.15		$	1.54
Return on average equity from continuing operations (3)		12.2	%		14.3	%		9.7	%		11.1	%		16.1	%
Common equity / total capitalization		55.9	%		64.3	%		60.0	%		58.4	%		63.6	%
Common equity / total capitalization and short-term financing		45.0	%		50.5	%		53.1	%		53.4	%		52.8	%
Book value per share	$	12.21		$	11.71		$	11.06		$	10.72		$	10.26
Market price:
High	$	18.875		$	19.813		$	20.500		$	21.750		$	18.000
Low	$	16.250		$	14.875		$	16.500		$	16.250		$	15.125
Close	$	18.625		$	18.375		$	18.313		$	20.500		$	16.875
Average number of shares outstanding		5,249,439			5,144,449			5,060,328			4,972,086			4,912,136
Shares outstanding at year-end		5,290,001			5,186,546			5,093,788			5,004,078			4,939,515
Registered common shareholders		2,166			2,212			2,271			2,178			2,213
Cash dividends declared per share	$	1.07		$	1.03		$	1.00		$	0.97		$	0.93
Dividend yield (annualized) (4)		5.8	%		5.7	%		5.5	%		4.7	%		5.5	%
Payout ratio from continuing operations (3) (5)		73.3	%		63.2	%		95.2	%		82.9	%		58.9	%
Additional Data
Customers
Natural gas distribution and transmission		40,854			39,029			37,128			35,797			34,713
Propane distribution		35,563			35,267			34,113			33,123			31,961
Volumes
Natural gas deliveries (in MMCF)		30,830			27,383			21,400			23,297			24,835
Propane distribution (in thousands of gallons)		28,469			27,788			25,979			26,682			29,975
Heating degree-days (Delmarva Peninsula)		4,730			4,082			3,704			4,430			4,717
Propane bulk storage capacity (in thousands of gallons)		1,928			1,926			1,890			1,866			1,860
Total employees (3)		471			466			431			397			338
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.
(2) The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.
(3) 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.
(4) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend declared by four (4), then dividing that amount by the closing common stock price at December 31.
(5) 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 17 -

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

Business Description

Chesapeake Utilities Corporation (“Chesapeake” or “the Company”) is a diversified utility company engaged in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses.

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, 2005, Chesapeake had recorded regulatory assets of $5.6 million, including $4.0 million for under-recovered purchased gas costs, $712,000 for tax-related regulatory assets, and $304,000 for conservation cost recovery. The Company has recorded regulatory liabilities totaling $19.3 million, including $16.7 million for accrued asset removal cost, $1.4 million for self-insurance, $483,000 for cash in/cash out, and $328,000 for tax-related regulatory assets at December 31, 2005. 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 gas manufacturing 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 state 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, 2005, Chesapeake had recorded environmental regulatory assets of $195,000 and a regulatory liability of $298,000 for over-collections and an additional liability of $353,000 for environmental costs.

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, 2005, these contracts had net unrealized gains of $46,000 that was recorded in the financial statements. At December 31, 2004, these contracts had net unrealized losses of $182,000 that were recorded in the financial statements.

- Page 18 -

Operating Revenues

Revenues for the natural gas distribution operations of the Company are based on rates approved by the public service commissions of the jurisdictions in which we operate. The natural gas transmission operation’s revenues are based on rates approved by the Federal Energy Regulatory Commission (“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.

Goodwill Impairment

In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” Chesapeake no longer amortizes goodwill. Instead, 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 initial test was performed upon adoption of SFAS No. 142 on January 1, 2002, and again at the end of each subsequent year. These tests were based on subjective measurements, including discounted cash flows of expected future operating results and market valuations of similar businesses. The propane unit had $674,000 in goodwill at both December 31, 2005 and 2004. Testing for 2005 and 2004 has indicated that no impairment has occurred.

Results of Operations

Net Income & Diluted Earnings Per Share Summary
For the Years Ended December 31,	2005		2004			Increase (decrease)		2004			2003			Increase (decrease)
Net Income *
Continuing operations	$	10,468	$	9,550		$	918	$	9,550		$	10,080			($530	)
Discontinued operations		-		(121	)		121		(121	)		(788	)		667
Total Net Income	$	10,468	$	9,429		$	1,039	$	9,429		$	9,292		$	137
Diluted Earnings Per Share
Continuing operations	$	1.77	$	1.64		$	0.13	$	1.64		$	1.76			($0.12	)
Discontinued operations		-		(0.02	)		0.02		(0.02	)		(0.13	)		0.11
Total Earnings Per Share	$	1.77	$	1.62		$	0.15	$	1.62		$	1.63			($0.01	)
* Dollars in thousands.

- Page 19 -

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.

Net income from continuing operations for 2004 was $9.6 million, or $1.64 per share (diluted), a decline of $530,000 compared to net income from continuing operations of $10.1 million, or $1.76 per share (diluted), for 2003.

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 years 2004 and 2003. Discontinued operations experienced losses of $0.02 and $0.13 per share (diluted) for 2004 and 2003, respectively.

Operating Income Summary (in thousands)
For the Years Ended December 31,	2005			2004		Increase (decrease)			2004		2003		Increase (decrease)
Business Segment:
Natural gas distribution & transmission	$	17,236		$	17,091	$	145		$	17,091	$	16,653	$	438
Propane		3,209			2,364		845			2,364		3,875		(1,511	)
Advanced information services		1,197			387		810			387		692		(305	)
Other & eliminations		(112	)		128		(240	)		128		359		(231	)
Total Operating Income	$	21,530		$	19,970	$	1,560		$	19,970	$	21,579		($1,609	)

The improvement in results for 2005 was primarily driven by:

·   The Lightweight Association Management Processing Systems (“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 LAMPS product was an internally developed software that was developed and marketed specifically for REALTOR® Associations.

·   The Delmarva and Florida natural gas distribution operations experienced strong residential customer growth of 8.7 percent and 7.4 percent, respectively, in 2005.

·   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 of 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.

Improvement in Chesapeake’s 2005 overall results compared to 2004 was primarily related to a $924,000 pre-tax gain on the sale of its LAMPS™ by the Company’s advanced information service operation, continued strong customer growth, and colder weather, which led to increased contributions from the Company’s natural gas and propane operations. The Company’s natural gas operations experienced an increase of 7.9 percent in residential customers. Weather, measured in heating degree-days, was 5 percent colder than 2004. The gross margin increases from growth and weather was partially offset by energy conservation efforts by customers in light of increased natural gas and propane costs and also, an increase in operating expenses.

Chesapeake’s 2004 results reflected strong customer growth, warmer weather as compared to 2003, customers’ energy conservation and costs incurred to comply with Sarbanes-Oxley. Weather, measured in heating degree-days, was 4 percent warmer than 2003. Management estimates that warmer weather negatively impacted gross margin by $566,000. The natural gas segment was able to offset the impact of warmer weather through customer growth of 7 percent. Additionally, the Company incurred approximately $600,000 of expenses through December 31, 2004 related to compliance with Section 404 of Sarbanes-Oxley. These costs include incremental audit fees, expansion of the Internal Audit Department and the temporary hiring of an outside consultant. The increase in operating income from the Company’s natural gas operations was more than offset by decreases in the propane and advanced information services businesses.

- Page 20 -

The following discussions of 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.

Natural Gas Distribution and Transmission

The natural gas distribution and transmission segment earned operating income of $17.2 million for 2005, $17.1 million for 2004, and $16.7 million for 2003, resulting in increases of $145,000 for 2005 and $438,000 for 2004.

Natural Gas Distribution and Transmission (in thousands)
For the Years Ended December 31,	2005		2004		Increase (decrease)		2004		2003		Increase (decrease)
Revenue	$	166,582	$	124,246	$	42,336	$	124,246	$	110,247	$	13,999
Cost of gas		116,178		77,456		38,722		77,456		65,495		11,961
Gross margin		50,404		46,790		3,614		46,790		44,752		2,038
Operations & maintenance		23,874		21,129		2,745		21,129		19,893		1,236
Depreciation & amortization		5,682		5,418		264		5,418		5,188		230
Other taxes		3,612		3,152		460		3,152		3,018		134
Other operating expenses		33,168		29,699		3,469		29,699		28,099		1,600
Total Operating Income	$	17,236	$	17,091	$	145	$	17,091	$	16,653	$	438

Natural Gas Heating Degree-Day (HDD) and Customer Analysis
For the Years Ended December 31,	2005		2004		Increase (decrease)		2004		2003		Increase (decrease)
Heating degree-day data — Delmarva
Actual HDD		4,792		4,553		239		4,553		4,715		(162	)
10-year average HDD		4,436		4,383		53		4,383		4,409		(26	)
Estimated gross margin per HDD	$	2,234	$	1,800	$	434	$	1,800	$	1,680	$	120
Estimated dollars per residential customer added:
Gross margin	$	372	$	372	$	0	$	372	$	360	$	12
Other operating expenses	$	106	$	104	$	2	$	104	$	100	$	4
Average number of residential customers
Delmarva		37,346		34,352		2,994		34,352		31,996		2,356
Florida		11,717		10,910		807		10,910		10,189		721
Total		49,063		45,262		3,801		45,262		42,185		3,077

2005 Compared to 2004

Revenue and cost of gas increased in 2005 compared to 2004, primarily due to changes in natural gas commodity prices. Increased prices of natural gas costs are being driven by increased demand that is exceeding the growth of available supply. The fall 2005 hurricane season significantly reduced the current and anticipated availability of natural gas supply from the Gulf Coast region, causing a dramatic rise in natural gas prices during the fourth quarter of 2005. Commodity cost changes are passed on to the ratepayers through a gas cost recovery or purchased gas cost adjustment in all jurisdictions; therefore, they have limited impact on the Company’s profitability. However, higher commodity prices may cause customers to reduce their energy consumption through conservation efforts and may cause the Company to have higher uncollectible accounts. 

- Page 21 -

Natural gas gross margin increased $3.6 million, or 7.7 percent, for 2005 compared to 2004. 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. These additional contracts will contribute approximately $53,000 monthly to gross margins. An increase of $980,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in expenses are associated with higher customer counts caused by continued economic growth, as well as higher depreciation and property taxes due to an increase in the level of capital investments.

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 the number of customers is attributed to the additional customers that are on the Peoples Gas system for which the Company provides services. 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.

Gross margin for the Delaware and Maryland distribution divisions increased $1.2 million, as temperatures in 2005 were 5 percent colder 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.

2004 Compared to 2003

Gross margin grew by $2.0 million in 2004 compared to 2003. The Company estimates that warmer weather reduced gross margin by $292,000. After adjusting for the effect of weather, gross margin would have increased 5.3 percent. The Company estimates that residential and commercial growth for the distribution operations generated $1.1 million of gross margin increase. The Company added 3,077 residential customers, an increase of 7 percent, in 2004. This growth was net of lower consumption per customer, which reflects customer conservation efforts in light of higher energy costs and a higher mix of apartments rather than single family homes in the customer additions for some divisions. Additionally, the natural gas supply and management services operation increased gross margin by $565,000, primarily through industrial customer growth and resale of seasonal excess capacity on upstream pipelines. The natural gas transmission operation also achieved gross margin growth of $716,000, due to additional transportation services provided to its firm customers.

- Page 22 -

Higher other operating expenses partially offset the gross margin increase. Operating expenses increased $1.6 million, or 5.7 percent, which includes $382,000 of expenses related to Sarbanes-Oxley Section 404 compliance implementation. The higher other operating expenses reflect the costs to support customer growth.

Propane

During 2005, the propane segment increased operating income by $845,000, or 36 percent, over 2004. In addition, gross margin increased $2.6 million, which more than offset the increase of $1.7 million of operating expenses. During 2004, the propane segment experienced a decrease of $1.5 million in operating income compared to 2003, reflecting a gross margin decrease of $1.9 million, partially offset by a decrease in operating expenses of $411,000.

Propane (in thousands)
For the Years Ended December 31,	2005		2004		Increase (decrease)		2004		2003		Increase (decrease)
Revenue	$	48,976	$	41,500	$	7,476	$	41,500	$	41,029	$	471
Cost of sales		30,041		25,155		4,886		25,155		22,762		2,393
Gross margin		18,935		16,345		2,590		16,345		18,267		(1,922	)
Operations & maintenance		13,355		11,718		1,637		11,718		12,053		(335	)
Depreciation & amortization		1,574		1,524		50		1,524		1,506		18
Other taxes		797		739		58		739		833		(94	)
Other operating expenses		15,726		13,981		1,745		13,981		14,392		(411	)
Total Operating Income	$	3,209	$	2,364	$	845	$	2,364	$	3,875		($1,511	)

Propane Heating Degree-Day (HDD) Analysis — Delmarva
For the Years Ended December 31,	2005		2004		Increase (decrease)		2004		2003		Increase (decrease)
Heating degree-days
Actual		4,792		4,553		239		4,553		4,715		(162	)
10-year average		4,436		4,383		53		4,383		4,409		(26	)
Estimated gross margin per HDD	$	1,743	$	1,691	$	52	$	1,691	$	1,670	$	21

2005 Compared to 2004

The increases in revenues and cost of sales in 2005 compared to 2004 were caused both by increases in volumes and by increases in the commodity prices of propane. Commodity price changes are passed on to the customer, subject to competitive market conditions.

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 will reverse 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 are 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 start-up costs accounted for $722,000, or approximately 49 percent, of the increase in operating expenses.

- Page 23 -

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. The higher expenses of $147,000 were attributed to business growth, such as payroll, vehicle fuel and maintenance, insurance, and depreciation expense.

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.

2004 Compared to 2003

Increases in revenues and cost of sales in 2004 were caused by an increase in the commodity prices of propane, partially offset by lower sales volumes due to warmer weather. Commodity price changes are generally passed on to the customer, subject to competitive market conditions. High commodity prices may cause customers to reduce their energy consumption through conservation efforts and may cause higher bad debt expense.

Propane distribution gross margin declined $1.2 million and propane wholesale marketing gross margin fell by $710,000. The Company estimates that warmer weather negatively impacted gross margin by $274,000. After adjusting for the impact of weather, gross margin decreased 9 percent. Lower retail gross margin per gallon in the distribution business reduced gross margin by approximately $493,000. In addition, lower sales volumes, not attributable to the weather, reduced gross margin by approximately $197,000, including $172,000 related to customers in the poultry industry. The closing of a poultry processing plant in the fourth quarter of 2003 is estimated to have reduced gross margin by $129,000. The plant is not expected to reopen. An outbreak of avian influenza on the Delmarva Peninsula in the first quarter of 2004 also contributed to the lower sales volumes. The influenza outbreak was contained. Volumes were also down partially due to customers conserving energy in light of higher energy costs. Finally, gross margin earned from a non-recurring service project in 2003 contributed $192,000 to the decline in gross margin.

The Company’s propane wholesale marketing operation contributed $373,000 to operating income; however, this was a decrease of $533,000 compared to 2003. This reflects a conservative strategy taken in the wholesale marketing operation, due to the high level of energy prices.

Other operating expenses decreased $411,000 despite additional costs of $142,000 associated with the implementation of Sarbanes-Oxley Section 404 compliance procedures. The decrease included reductions in incentive compensation, revenue-related taxes and lower delivery costs.

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 $1.2 million for 2005, $387,000 for 2004, and $692,000 for 2003.

- Page 24 -

Advanced Information Services (in thousands)
For the Years Ended December 31,	2005		2004		Increase (decrease)			2004		2003		Increase (decrease)
Revenue	$	14,140	$	12,427	$	1,713		$	12,427	$	12,578		($151	)
Cost of sales		7,181		7,015		166			7,015		7,018		(3	)
Gross margin		6,959		5,412		1,547			5,412		5,560		(148	)
Operations & maintenance		5,129		4,405		724			4,405		4,196		209
Depreciation & amortization		123		138		(15	)		138		191		(53	)
Other taxes		510		482		28			482		481		1
Other operating expenses		5,762		5,025		737			5,025		4,868		157
Total Operating Income	$	1,197	$	387	$	810		$	387	$	692		($305	)

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. The sale 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 account for the decrease in revenue when compared to 2004. This decrease is 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 is related to the sale of the webproEX software to QAD that took place in 2003. As part of the sale agreement, Chesapeake receives a percentage of revenues after certain annual revenue and performance targets have been reached by QAD.

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 is attributed to the LAMPS^TM product. The 2005 and 2004 cost of sales figures includes $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 is attributed to the increase of costs relating to the LAMPS^TM product. The costs associated with the LAMPS^TM product for 2005 and 2004 are $1.2 million and $575,000 respectively. The remaining increase is 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.

2004 compared to 2003

The decrease in gross margin and operating income in 2004 was due to the non-recurring revenue recorded in 2003 on the sale of some rights to one of the Company’s internally-developed software products to a third party software provider. Absent the sale, gross margin would have increased by $351,000; however, the increase was partially offset by higher costs associated with continued investment in the Company’s LAMPS™ product and Sarbanes-Oxley compliance costs of $60,000.

Other Operations and Eliminations

Other operations and eliminating entries generated an operating loss of $112,000 for 2005 compared to income of $128,000 for 2004. Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries. In addition, in August 2004 the Company formed OnSight Energy, LLC (“OnSight”) to provide distributed energy services. The increase in revenues in 2005 is primarily attributed to OnSight completing its first contract in the second quarter of 2005. Other operating expenses increased in 2005 as a result of a full year of operation by OnSight, compared to a partial year in 2004. Eliminations are entries required to eliminate activities between business segments from the consolidated results.

- Page 25 -

Other Operations & Eliminations (in thousands)
For the Years Ended December 31,	2005			2004		Increase (decrease)			2004		2003		Increase (decrease)
Revenue	$	763		$	647	$	116		$	647	$	702		($55	)
Cost of sales		116			-		116			-		-		-
Gross margin		647			647		-			647		702		(55	)
Operations & maintenance		472			279		193			279		79		200
Depreciation & amortization		220			210		10			210		238		(28	)
Other taxes		97			63		34			63		55		8
Other operating expenses		789			552		237			552		372		180
Operating Income — Other		($142	)	$	95		($237	)	$	95	$	330		($235	)
Operating Income — Eliminations	$	30		$	33		($3	)	$	33	$	29	$	4
Total Operating Income (Loss)		($112	)	$	128		($240	)	$	128	$	359		($231	)

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, compared to a net loss of $788,000 for 2003. The Company did not have any discontinued operations in 2005.

Income Taxes

Operating income taxes increased in 2005 compared to 2004, due to increased taxable income. Operating income taxes decreased in 2004 compared to 2003, due to decreased income. The effective current federal income tax rate for 2005 was 35%, whereas the rate for both 2004 and 2003 was 34%. During 2005, 2004 and 2003, the Company benefited of $223,000, $205,000, and 197,000, 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 $383,000, $549,000 and $238,000 for the years 2005, 2004 and 2003, respectively. The other income amounts for the years 2005 and 2003 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 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 7.2 percent, compared to $71.3 million with a weighted average interest rate of 7.2 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 3.7 percent for 2004 to 4.6 percent for 2005.

Total interest expense for 2004 decreased approximately $438,000, or 8 percent, compared to 2003. The decrease reflects the decrease in the average long-term debt balance. The average long-term debt balance during 2004 was $71.3 million with a weighted average interest rate of 7.2 percent, compared to $75.4 million with a weighted average interest rate of 7.2 percent in 2003. The average short-term borrowing balance in 2004 was $870,000, a decrease from $3.5 million in 2003. The weighted average interest rate for short-term borrowing increased from 2.4 percent for 2003 to 3.7 percent for 2004.

- Page 26 -

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 and short-term borrowing to meet normal working capital requirements and to temporarily finance capital expenditures. During 2005, net cash provided by operating activities was $13.3 million, cash used by investing activities was $32.8 million and cash provided by financing activities was $20.4 million.

During 2004, net cash provided by operating activities was $23.4 million, cash used by investing activities was $16.9 million and cash used by financing activities was $8.0 million.

As of December 31, 2005, the Board of Directors has authorized the Company to borrow up to $50.0 million of short-term debt from various banks and trust companies. On December 31, 2005, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $65.0 million. 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 three lines are subject to the banks’ availability of funds. The outstanding balances of short-term borrowing at December 31, 2005 and 2004 were $35.5 million and $5.0 million, respectively. In 2005 and 2004, Chesapeake used funds provided by operations and financing to fund net investing.

Chesapeake has budgeted $54.4 million for capital expenditures during 2006. This amount includes $20.8 million for natural gas distribution, $26.7 million for natural gas transmission, $5.7 million for propane distribution and wholesale marketing, $178,000 for advanced information services and $1.0 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 2006 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.

Chesapeake expects to incur approximately $300,000 in 2006 and $25,000 in 2007 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.

Capital Structure

As of December 31, 2005, common equity represented 59.0 percent of total capitalization, compared to 54.1 percent in 2004. 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 46.0 percent and 51.3 percent, respectively. 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.

- Page 27 -

Cash Flows from Operating Activities

The primary drivers for the Company’s operating cash flows are cash payments received from gas customers, offset by payments made by the Company for gas costs, operation and maintenance expenses, taxes and interest costs.

Net cash provided by operating activities totaled $13.3 million, $23.4 million and $23.0 million for fiscal years 2005, 2004 and 2003, respectively. A description of certain material changes in working capital from December 31, 2004 to December 31, 2005 is listed below:

·   Accounts receivable and accrued revenue increased $16.8 million. The increase in receivables is attributed to higher gas and propane sale invoices in response to the higher natural gas and propane prices.

·   Propane inventory, storage gas and other inventory increased $5.7 million, primarily due to higher propane and natural gas prices.

·   The Company 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”.

·   Accounts payable and other accrued liabilities increased $15.3 million largely to fund the higher natural gas and propane purchases due mostly to higher prices.

During 2004, propane inventory, storage gas, and other inventory rose $1.7 million due to higher natural gas costs and increased storage capacity. During 2004 and 2003, Accounts receivable and accrued revenue increased $11.7 million and $3.6 million, respectively, primarily in response to higher gas and propane sale invoices in response to the higher natural gas and propane prices. Accounts payable and other accrued liabilities increased $11.1 million and $564,000, respectively, in 2004 and 2003 due to higher natural gas and propane purchases.

Cash Flows Used in Financing Activities

Cash flows received from financing totaled $20.4 million for 2005 and the cash used in financing activities totaled $8.0 million and $16.4 million for fiscal years 2004 and 2003, respectively. During fiscal year 2005, the Company increased the net amount of cash borrowed under its short-term lines of credits by $29.6 million. Additionally, the Company paid common stock dividends totaling $5.8 million and reduced its outstanding long-term notes payable balance by $4.8 million.

Cash flows used in financing activities during year 2004 reflected a $3.7 million repayment of long-term notes payable, coupled with common stock dividend payments totaling $5.6 million. Additionally during year 2004, the Company increased the net amount of cash borrowed from its short-term lines of credits by $1.2 million. During year 2003, cash flows used in financing activities reflected a $3.9 million repayment of long-term notes payable, a $7.4 million net repayment of short-term lines of credit, and payment of common stock dividends totaling $5.4 million.

On June 29, 2005, the Company entered into an agreement in principle with Prudential Investment Management Inc. Subsequently, the Company executed a Note Agreement, dated October 18, 2005, with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company), pursuant to which the investors agreed, subject to certain conditions, to purchase from the Company $20 million in principal of 5.5 percent Senior Notes (the “Notes”) issued by the Company; provided, that the Company elects to effect the sale of the Notes at any time prior to January 15, 2007. The terms of the Notes will require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes.

- Page 28 -

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $32.8 million, $16.9 million and $5.9 million during fiscal years 2005, 2004 and 2003, respectively. In fiscal years 2005, 2004 and 2003, $33.0 million, $17.8 million and $11.8 million, respectively, of cash was utilized for capital expenditures. Additions to property, plant and equipment in 2005 were primarily for natural gas transmission ($15.0 million), natural gas distribution ($13.3 million) and propane distribution ($3.8 million). In both 2005 and 2004, 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. Additionally, cash of $240,000, $370,000 and $2.2 million was received in years 2005, 2004, and 2003, respectively, for the recovery of environmental costs through rates charged to customers. The year 2003 included cash proceeds of $3.7 million received from the sale of discontinued operations.

Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2005:

	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)	$	4,929,091	$	15,312,727	$	13,312,727	$	30,364,909	$	63,919,454
Operating leases (2)		645,576		1,062,394		692,741		2,376,302		4,777,013
Purchase obligations (3)
Transmission capacity		7,585,816		12,497,472		11,890,259		25,015,062		56,988,609
Storage — Natural Gas		1,422,987		2,709,353		2,696,217		6,518,563		13,347,120
Commodities		20,012,976		-		-		-		20,012,976
Forward purchase contracts — Propane (4)		21,622,201		-		-		-		21,622,201
Unfunded benefits (5)		259,399		528,995		551,782		2,678,755		4,018,931
Funded benefits (6)		68,680		129,697		111,081		1,376,178		1,685,636
Total Contractual Obligations	$	56,546,726	$	32,240,638	$	29,254,807	$	68,329,769	$	186,371,940
(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 $4.5 million, $7.7 million, $5.7 million and $7.2 million, respectively, for the periods indicated above. Expected interest payments for all periods total $25.1 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 $4.0 million at December 31, 2005 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 $1.7 million at December 31, 2005 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, 2005. 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.

- Page 29 -

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, advanced information services, and the Florida natural gas supply and management services subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases and office rent in the event of the subsidiaries’ default. The liabilities for these purchases are included in our Consolidated Financial Statements. The guarantees at December 31, 2005, totaled $11.2 million and expire on various dates in 2006.

The Company has issued a letter of credit to its main insurance company for $694,000, which expires May 31, 2006. The letter of credit was provided as security for claims amounts below the deductibles on the Company’s policies.

Regulatory Activities

The Company’s natural gas distribution operations are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions. The natural gas transmission operation is subject to regulation by the FERC.

Delaware. On October 3, 2005, the Delaware division filed its annual Gas Sales Service Rates (“GSR”) application that was effective for service rendered on and after November 1, 2005 with the Delaware Public Service Commission (“Delaware PSC”). On October 11, 2005, the Delaware PSC approved the GSR charges, subject to full evidentiary hearings and a final decision. An evidentiary hearing is currently scheduled for April 6, 2006, with a final decision by the Delaware PSC expected during the second or third quarter of 2006.

On November 1, 2005, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) Rate application that was effective for service rendered on and after December 1, 2005. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 8, 2005, subject to full evidentiary hearings and a final decision. An evidentiary hearing is currently scheduled for April 5, 2006, with a final decision by the Delaware PSC expected during the second or third quarter of 2006.

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 and traditional ratemaking processes, natural gas has not been extended to 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 during the first half of 2006.

Maryland. On December 8, 2005, the Maryland Public Service Commission (“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, 2005. On January 12, 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. The Maryland PSC did not receive any appeals or written exceptions to the proposed findings and as a result a final order was issued on February 14, 2006.

Florida. On August 25, 2004, the Florida division filed a petition with the Florida Public Service Commission (“Florida PSC”) for authorization to restructure rates and establish new customer classifications. The filing was revenue-neutral, but would allow the Florida division to collect a greater percentage of revenues from fixed charges, rather than variable charges based upon consumption. On February 1, 2005, the Florida PSC voted to approve the petition, as modified by the PSC staff. The Florida PSC issued a final order on February 22, 2005.

- Page 30 -

On May 16, 2005, the Florida division filed 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 Public Service Commission approved the Company’s request on July 19, 2005, and service to the existing WCI facility is expected to begin during the first quarter of 2006. WCI is located in Washington County in the Florida panhandle and would become 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 FPSC 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. A determination that PPC does qualify as a natural gas transmission company would provide opportunities for investment to deliver gas service to industrial customers in Florida by an intra-state pipeline, instead of through Chesapeake Utilities Corporation, to certain niche markets.

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. Chesapeake understands that the other matter has now been resolved and Eastern Shore intends to resubmit its gas supply realignment filing during first quarter of 2006.

On April 1, 2003, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity (“Application”) before the FERC requesting authorization to construct the necessary facilities to enable Eastern Shore to provide additional daily firm transportation capacity of 15,100 dekatherms over a three-year period commencing November 1, 2003. On October 8, 2003, the FERC issued an order granting Eastern Shore the authority to construct and operate certain pipeline and measurement facilities in its service territories as requested. Phases I and II of the Application began providing services November 1, 2003 and 2004, respectively. On December 22, 2004, Eastern Shore filed to amend the above-referenced Application to seek FERC authorization to construct and operate new pipeline facilities to provide an additional 7,450 dekatherms of daily firm transportation service, as requested by its customers, to be available November 1, 2005. On June 27, 2005, the FERC issued an Order Amending Certificate, granting approval to Eastern Shore to construct and operate the additional pipeline facilities requested. Phase III began November 1, 2005. 

On December 9, 2005, Eastern Shore filed revised tariff sheets to replace its existing fixed price penalties with penalties that are the higher of a fixed price or a multiple of a daily index price. The revised penalties are applicable to customers who violate operational Flow Orders and customers who take unauthorized overrun quantities that could threaten the operational integrity of the pipeline, or to Eastern Shore’s ability to render reliable service. By letter order dated January 6, 2006, the FERC accepted Eastern Shore’s proposed changes, effective December 21, 2005.

Eastern Shore is also following the FERC’s recent rulemaking pertaining to creditworthiness standards for customers of interstate natural gas pipelines. FERC has not yet issued its final rules in this proceeding. Upon such issuance, Eastern Shore will evaluate its currently effective tariff creditworthiness provisions to determine whether any actions will need to be taken to conform to the FERC’s final rules.

Environmental Matters

The Company continues to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at three other 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.

- Page 31 -

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 first mortgage bonds, 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 and was not entered into for trading purposes. The carrying value of the Company’s long-term debt, including current maturities, was $63.9 million at December 31, 2005, as compared to a fair value of $68.5 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.

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, 2005, the propane distribution operation had entered into a put contract to protect the value of 2.1 million gallons of propane inventory from a drop in fair value. The Company settled the put in January 2006, which resulted in a benefit of $28,000.

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 counter party or booking out the transaction (booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy). The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment 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, 2005 and 2004 is shown in the following charts.

- Page 32 -

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 expire in 2006.

At December 31, 2004	Quantity in gallons		Estimated Market Prices		Weighted Average Contract Prices
Forward Contracts
Sale		10,044,510		$0.7725 — $0.7750		$0.7828
Purchase		9,975,000		$0.7300 — $0.7500		$0.8007
Futures Contracts
Sale		378,000		$0.7450 — $0.7500		$0.7868
Purchase		420,000		$0.7200 — $0.7300		$0.7500
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expired in 2005.

The Company’s natural gas distribution 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.

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.

- Page 33 -

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.

Recent Pronouncements

In December 2004, the FASB released a revision (“Share-Based Payment”) to SFAS No. 123 “Accounting for Stock-Based Compensation,” referred to as SFAS No. 123R. In April 2005, the SEC approved a new rule that delayed the effective date for SFAS No. 123R until the first annual period beginning after June 15, 2005. This Statement establishes financial accounting and reporting standards for stock-based employee compensation plans. Those plans include all arrangements by which employees receive shares of stock or other equity instruments of the employer or the employer incurs liabilities to employees in amounts based on the price of the employer’s stock. Examples are stock purchase plans, stock options, restricted stock and stock appreciation rights. The adoption of this pronouncement will not have a material impact on the Company’s financial statements.

In March 2005, the FASB issued Interpretation No. 47 (“FIN No. 47”), “Accounting for Conditional Asset Retirement Obligations,” an interpretation of SFAS No. 143. FIN No. 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. FIN No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company adopted FIN No. 47 during the fourth quarter of 2005 and it did not have a material impact on its financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3”. SFAS No. 154 primarily requires retrospective application to prior periods’ financial statements for the direct effects 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 applies to all voluntary changes in accounting principle and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company is required to adopt the provision of SFAS No. 154, as applicable, beginning in fiscal year 2006.

- Page 34 -

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   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 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 on the Company and its customers;

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

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.

- Page 35 -

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 Supplemental 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, 2005.

Management’s assessment of the effectiveness of Chesapeake’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

- Page 36 -

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 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 financial statements 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 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.

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, 2005, 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, 2005, 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.

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.

- Page 37 -

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 6, 2006

- Page 38 -

This page intentionally left blank.

- Page 39 -

Consolidated Statements of Income
For the Years Ended December 31,	2005		2004			2003
Operating Revenues	$	229,629,736	$	177,955,441		$	163,567,592
Operating Expenses
Cost of sales, excluding costs below		153,514,739		109,626,377			95,246,819
Operations		40,181,649		35,146,595			33,526,804
Maintenance		1,818,981		1,518,774			1,737,855
Depreciation and amortization		7,568,209		7,257,538			7,089,836
Other taxes		5,015,659		4,436,411			4,386,878
Total operating expenses		208,099,237		157,985,695			141,988,192
Operating Income		21,530,499		19,969,746			21,579,400
Other income net of other expenses		382,626		549,156			238,439
Interest charges		5,133,495		5,268,145			5,705,911
Income Before Income Taxes		16,779,630		15,250,757			16,111,928
Income taxes		6,312,016		5,701,090			6,032,445
Net Income from Continuing Operations		10,467,614		9,549,667			10,079,483
Loss from discontinued operations, net of tax benefit of $0, $59,751 and $74,997		-		(120,900	)		(787,607	)
Net Income	$	10,467,614	$	9,428,767		$	9,291,876
Earnings Per Share of Common Stock:
Basic
From continuing operations	$	1.79	$	1.66		$	1.80
From discontinued operations		-		(0.02	)		(0.14	)
Net Income	$	1.79	$	1.64		$	1.66
Diluted
From continuing operations	$	1.77	$	1.64		$	1.76
From discontinued operations		-		(0.02	)		(0.13	)
Net Income	$	1.77	$	1.62		$	1.63

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

- Page 40 -

Consolidated Statements of Cash Flows
For the Years Ended December 31,	2005			2004			2003
Operating Activities
Net Income	$	10,467,614		$	9,428,767		$	9,291,876
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		7,568,209			7,257,538			8,030,399
Depreciation and accretion included in other costs		2,705,619			2,611,779			2,468,647
Deferred income taxes, net		1,510,776			4,559,207			2,397,594
Unrealized (loss) gain on commodity contracts		(227,193	)		353,183			457,901
Employee benefits and compensation		1,621,607			1,536,586			2,042,093
Other, net		(62,692	)		67,079			15,874
Changes in assets and liabilities:
Sale (purchase) of investments		(1,242,563	)		43,354			-
Accounts receivable and accrued revenue		(16,831,750	)		(11,723,505	)		(3,565,363	)
Propane inventory, storage gas and other inventory		(5,704,040	)		(1,741,941	)		(466,412	)
Regulatory assets		(1,719,184	)		428,516			116,153
Prepaid expenses and other current assets		36,703			(221,137	)		(316,425	)
Other deferred charges		(102,562	)		(168,898	)		43,844
Long-term receivables		247,600			428,964			(101,373	)
Accounts payable and other accrued liabilities		15,258,551			11,079,661			564,270
Income taxes receivable (payable)		(2,006,763	)		(229,237	)		25,090
Accrued interest		(42,374	)		(51,272	)		(47,464	)
Customer deposits and refunds		462,781			665,549			128,704
Accrued compensation		875,342			(794,194	)		910,587
Regulatory liabilities		144,499			(191,266	)		466,923
Environmental and other liabilities		328,383			12,721			550,977
Net cash provided by operating activities		13,288,563			23,351,454			23,013,895
Investing Activities
Property, plant and equipment expenditures		(33,008,235	)		(17,784,240	)		(11,790,364	)
Sale of investments		-			135,170			-
Sale of discontinued operations		-			415,707			3,732,649
Environmental recoveries and other		240,336			369,719			2,127,248
Net cash used by investing activities		(32,767,899	)		(16,863,644	)		(5,930,467	)
Financing Activities
Common stock dividends		(5,789,179	)		(5,560,535	)		(5,403,536	)
Issuance of stock for Dividend Reinvestment Plan		458,756			200,551			347,546
Change in cash overdrafts due to outstanding checks		874,083			(143,720	)		(46,853	)
Net borrowing (repayment) under line of credit agreements		29,606,400			1,184,743			(7,384,743	)
Repayment of long-term debt		(4,794,827	)		(3,665,589	)		(3,945,617	)
Net cash used by financing activities		20,355,233			(7,984,550	)		(16,433,203	)
Net Increase (Decrease) in Cash and Cash Equivalents		875,897			(1,496,740	)		650,225
Cash and Cash Equivalents — Beginning of Period		1,611,761			3,108,501			2,458,276
Cash and Cash Equivalents — End of Period	$	2,487,658		$	1,611,761		$	3,108,501
Supplemental Disclosure of Cash Flow information
Cash paid for interest	$	5,052,013		$	5,280,299		$	5,648,332
Cash paid for income taxes	$	6,342,476		$	1,977,223		$	3,767,816

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

- Page 41 -

Consolidated Balance Sheets
Assets
At December 31,	2005			2004
Property, Plant and Equipment
Natural gas distribution and transmission	$	220,685,461		$	198,306,668
Propane		41,563,810			38,344,983
Advanced information services		1,221,177			1,480,779
Other plant		9,275,729			9,368,153
Total property, plant and equipment		272,746,177			247,500,583
Less: Accumulated depreciation and amortization		(78,840,413	)		(73,213,605	)
Plus: Construction work in progress		7,598,531			2,766,209
Net property, plant and equipment		201,504,295			177,053,187
Investments		1,685,635			386,422
Current Assets
Cash and cash equivalents		2,487,658			1,611,761
Accounts receivable (less allowance for uncollectible accounts of $861,378 and $610,819, respectively)		54,284,011			36,938,688
Accrued revenue		4,716,383			5,229,955
Propane inventory, at average cost		6,332,956			4,654,119
Other inventory, at average cost		1,538,936			1,056,530
Regulatory assets		4,434,828			2,435,284
Storage gas prepayments		8,628,179			5,085,382
Income taxes receivable		2,725,840			719,078
Prepaid expenses		2,021,164			1,759,643
Other current assets		1,596,797			459,908
Total current assets		88,766,752			59,950,348
Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		205,683			219,964
Long-term receivables		961,434			1,209,034
Other regulatory assets		1,178,232			1,542,741
Other deferred charges		1,003,393			902,281
Total deferred charges and other assets		4,023,193			4,548,471
Total Assets	$	295,979,875		$	241,938,428

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

- Page 42 -

Consolidated Balance Sheets
Capitalization and Liabilities
At December 31,	2005			2004
Capitalization
Stockholders' equity
Common Stock, par value $.4867 per share; (authorized 12,000,000 shares) (1)	$	2,863,212		$	2,812,538
Additional paid-in capital		39,619,849			36,854,717
Retained earnings		42,854,894			39,015,087
Accumulated other comprehensive income		(578,151	)		(527,246	)
Deferred compensation obligation		794,535			816,044
Treasury stock		(797,156	)		(1,008,696	)
Total stockholders' equity		84,757,183			77,962,444
Long-term debt, net of current maturities		58,990,363			66,189,454
Total capitalization		143,747,546			144,151,898
Current Liabilities
Current portion of long-term debt		4,929,091			2,909,091
Short-term borrowing		35,482,241			5,001,758
Accounts payable		45,645,228			30,938,272
Customer deposits and refunds		5,140,999			4,678,218
Accrued interest		558,719			601,095
Dividends payable		1,676,398			1,617,245
Deferred income taxes payable		1,150,828			571,876
Accrued compensation		3,793,244			2,680,370
Regulatory liabilities		550,546			571,111
Other accrued liabilities		3,560,055			1,800,540
Total current liabilities		102,487,349			51,369,576
Deferred Credits and Other Liabilities
Deferred income taxes payable		24,248,624			23,350,414
Deferred investment tax credits		367,085			437,909
Other regulatory liabilities		2,008,779			1,578,374
Environmental liabilities		352,504			461,656
Accrued pension costs		3,099,882			3,007,949
Accrued asset removal cost		16,727,268			15,024,849
Other liabilities		2,940,838			2,555,803
Total deferred credits and other liabilities		49,744,980			46,416,954
Other Commitments and Contingencies (Note N)
Total Capitalization and Liabilities	$	295,979,875		$	241,938,428
(1) Shares issued were 5,883,099 and 5,778,976 for 2005 and 2004, respectively.
Shares outstanding were 5,883,002 and 5,769,558 for 2005 and 2004, respectively.

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

- Page 43 -

Consolidated Statements of Stockholders' Equity
For the Years Ended December 31,	2005			2004			2003
Common Stock
Balance — beginning of year	$	2,812,538		$	2,754,748		$	2,694,935
Dividend Reinvestment Plan		20,038			20,125			24,888
Retirement Savings Plan		10,255			19,058			21,047
Conversion of debentures		11,004			9,060			9,144
Performance shares and options exercised (1)		9,377			9,547			4,734
Balance — end of year		2,863,212			2,812,538			2,754,748
Additional Paid-in Capital
Balance — beginning of year		36,854,717			34,176,361			31,756,983
Dividend Reinvestment Plan		1,224,874			996,715			1,066,386
Retirement Savings Plan		682,829			946,319			899,475
Conversion of debentures		373,259			307,940			310,293
Performance shares and options exercised (1)		484,170			427,382			143,224
Balance — end of year		39,619,849			36,854,717			34,176,361
Retained Earnings
Balance — beginning of year		39,015,087			36,008,246			32,898,283
Net income		10,467,614			9,428,767			9,291,876
Cash dividends (2)		(6,627,807	)		(6,403,450	)		(6,181,913	)
Loss on issuance of treasury stock		-			(18,476	)		-
Balance — end of year		42,854,894			39,015,087			36,008,246
Accumulated Other Comprehensive Income
Balance — beginning of year		(527,246	)		-			-
Minimum pension liability adjustment, net of tax		(50,905	)		(527,246	)		-
Balance — end of year		(578,151	)		(527,246	)		0
Deferred Compensation Obligation
Balance — beginning of year		816,044			913,689			711,109
New deferrals		130,426			296,790			202,580
Payout of deferred compensation		(151,935	)		(394,435	)		-
Balance — end of year		794,535			816,044			913,689
Treasury Stock
Balance — beginning of year		(1,008,696	)		(913,689	)		(711,109	)
New deferrals related to compensation obligation		(130,426	)		(296,790	)		(202,580	)
Purchase of treasury stock		(182,292	)		(344,753	)		-
Sale and distribution of treasury stock		524,258			546,536			-
Balance — end of year		(797,156	)		(1,008,696	)		(913,689	)
Total Stockholders’ Equity	$	84,757,183		$	77,962,444		$	72,939,355
(1) Includes amounts for shares issued for Directors’ compensation.
(2) Cash dividends declared per share for 2005, 2004 and 2003 were $1.14, $1.12 and $1.10, respectively.

Consolidated Statements of Comprehensive Income
For the Years Ended December 31,	2005			2004			2003
Net income	$	10,467,614		$	9,428,767		$	9,291,876
Minimum pension liability adjustment, net of tax of $33,615 and $347,726, respectively		(50,905	)		(527,246	)		-
Comprehensive Income	$	10,416,709		$	8,901,521		$	9,291,876

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

- Page 44 -

Consolidated Statements of Income Taxes
For the Years Ended December 31,	2005			2004			2003
Current Income Tax Expense
Federal	$	3,687,800		$	1,221,155		$	4,168,433
State		789,233			618,916			948,023
Investment tax credit adjustments, net		(54,816	)		(54,816	)		(54,816	)
Total current income tax expense		4,422,217			1,785,255			5,061,640
Deferred Income Tax Expense (1)
Property, plant and equipment		1,380,628			4,230,650			1,980,070
Deferred gas costs		1,064,310			283,547			105,846
Pensions and other employee benefits		(340,987	)		(49,620	)		(203,229	)
Environmental expenditures		(98,229	)		(150,864	)		(866,206	)
Other		(115,923	)		(397,878	)		(45,676	)
Total deferred income tax expense		1,889,799			3,915,835			970,805
Total Income Tax Expense	$	6,312,016		$	5,701,090		$	6,032,445
Reconciliation of Effective Income Tax Rates
Federal income tax expense (2)	$	5,872,871		$	5,185,257		$	5,478,056
State income taxes, net of federal benefit		708,192			736,176			737,370
Other		(269,047	)		(220,343	)		(182,981	)
Total Income Tax Expense	$	6,312,016		$	5,701,090		$	6,032,445
Effective income tax rate		37.6	%		37.4	%		37.4	%
At December 31,		2005			2004
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	26,795,452		$	25,736,718
Deferred gas costs		1,664,252			599,945
Other		612,943			749,259
Total deferred income tax liabilities		29,072,647			27,085,922
Deferred income tax assets:
Pension and other employee benefits		2,289,370			1,914,402
Self insurance		575,303			535,755
Environmental costs		181,734			83,510
Other		626,788			629,965
Total deferred income tax assets		3,673,195			3,163,632
Deferred Income Taxes Per Consolidated Balance Sheet	$	25,399,452		$	23,922,290
(1) Includes $146,000, $386,000 and $113,000 of deferred state income taxes for the years 2005, 2004 and 2003, respectively.
(2) Federal income taxes were recorded at 35% for the year 2005. They were recorded at 34% in both 2004 and 2003.

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

- Page 45 -

A. Summary of Accounting Policies

Nature of Business

Chesapeake Utilities Corporation (“Chesapeake” or “the Company”) is engaged in natural gas distribution to approximately 54,800 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 32,900 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 significant 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 property is stated at original cost while the assets of the non-utility segments are recorded at 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. 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 46 -

At December 31,	2005			2004			Useful Life (1)
Plant in service
Mains	$	113,111,408		$	99,154,938		24-37 years
Services — utility		29,010,008			25,733,797		14-28 years
Compressor station equipment		23,853,871			23,766,105		28 years
Liquefied petroleum gas equipment		22,162,867			21,483,969		30-39 years
Meters and meter installations		15,165,212			13,656,918		Propane 15-33 years, Natural gas 17-49 years
Measuring and regulating station equipment		12,219,964			10,142,531		17-37 years
Office furniture and equipment		9,572,926			10,171,180		Non-regulated 3-10 years, Regulated 3-20 years
Transportation equipment		9,822,272			9,425,605		2-11 years
Structures and improvements		9,161,696			9,177,011		5-44 years(2)
Land and land rights		5,646,852			4,703,683		Not depreciable, except certain regulated assets
Propane bulk plants and tanks		6,097,036			5,024,462		15 - 40 years
Various		16,922,065			15,060,384		Various
Total plant in service		272,746,177			247,500,583
Plus construction work in progress		7,598,531			2,766,209
Less accumulated depreciation		(78,840,413	)		(73,213,605	)
Net property, plant and equipment	$	201,504,295		$	177,053,187
(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 Federal Energy Regulatory Commission. 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. The appliance inventory is valued at first-in first-out (“FIFO”). 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, 2005 and 2004, 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 47 -

At December 31,	2005		2004
Regulatory Assets
Current
Underrecovered purchased gas costs	$	4,016,522	$	1,479,358
Conservation cost recovery		303,930		186,234
Swing transportation imbalances		454		32,707
Flex rate asset		113,922		736,985
Total current		4,434,828		2,435,284
Non-Current
Income tax related amounts due from customers		711,961		711,961
Deferred regulatory and other expenses		89,258		200,746
Deferred gas supply		15,201		15,201
Deferred gas required for operations		-		141,082
Deferred post retirement benefits		166,739		194,529
Environmental regulatory assets and expenditures		195,073		279,222
Total non-current		1,178,232		1,542,741
Total Regulatory Assets	$	5,613,060	$	3,978,025
Regulatory Liabilities
Current
Self insurance — current	$	44,221	$	127,000
Shared interruptible margins		3,039		135,098
Operational flow order penalties		7,831		130,338
Swing transportation imbalances		495,455		178,675
Total current		550,546		571,111
Non-Current
Self insurance — long-term		1,383,247		1,221,101
Income tax related amounts due to customers		327,893		324,974
Environmental overcollections		297,639		32,299
Total non-current		2,008,779		1,578,374
Accrued asset removal cost		16,727,268		15,024,849
Total Regulatory Liabilities	$	19,286,593	$	17,174,334

Included in the regulatory assets listed above are $1.8 million of which are accruing interest. Of the remaining regulatory assets, $2.7 million will be collected in approximately one to two years, $360,000 will be collected within approximately 3 to 10 years, and $729,000 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

Goodwill and other intangible assets are associated with the acquisition of non-utility companies. In accordance with SFAS No. 142, goodwill is not amortized, but is tested for impairment on an annual basis and when events change. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

- Page 48 -

Other Deferred Charges

Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred, then 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 $46,000 and unrealized losses of $182,000 at December 31, 2005 and 2004, 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 fair value hedges of its inventory, in order to mitigate the impact of wholesale price fluctuations. At December 31, 2005, propane distribution had entered into a put contract to protect 2.1 million gallons of propane inventory from a drop in value below the strike price of the put. The Company settled the put in January 2006, which resulted in a benefit of $28,000.

- Page 49 -

Earnings Per Share

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

For the Period Ended December 31,	2005		2004		2003
Calculation of Basic Earnings Per Share from Continuing Operations:
Income from continuing operations	$	10,467,614	$	9,549,667	$	10,079,483
Weighted average shares outstanding		5,836,463		5,735,405		5,610,592
Basic Earnings Per Share from Continuing Operations	$	1.79	$	1.66	$	1.80
Calculation of Diluted Earnings Per Share from Continuing Operations:
Reconciliation of Numerator:
Income from continuing operations — Basic	$	10,467,614	$	9,549,667	$	10,079,483
Effect of 8.25% Convertible debentures		123,559		139,097		157,557
Adjusted numerator — Diluted	$	10,591,173	$	9,688,764	$	10,237,040
Reconciliation of Denominator:
Weighted shares outstanding — Basic		5,836,463		5,735,405		5,610,592
Effect of dilutive securities
Stock options		-		1,784		1,361
Warrants		11,711		7,900		5,481
8.25% Convertible debentures		144,378		162,466		184,532
Adjusted denominator — Diluted		5,992,552		5,907,555		5,801,966
Diluted Earnings Per Share from Continuing Operations	$	1.77	$	1.64	$	1.76

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.

- Page 50 -

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 FASB released a revision (“Share-Based Payment”) to SFAS No. 123 “Accounting for Stock-Based Compensation,” referred to as SFAS No. 123R. In April 2005, the SEC approved a new rule that delayed the effective date for SFAS No. 123R until the first annual period beginning after June 15, 2005. This Statement establishes financial accounting and reporting standards for stock-based employee compensation plans. Those plans include all arrangements by which employees receive shares of stock or other equity instruments of the employer or the employer incurs liabilities to employees in amounts based on the price of the employer’s stock. Examples are stock purchase plans, stock options, restricted stock and stock appreciation rights. The Company adoption of this pronouncement will not have a material impact on the financial statements.

In March 2005, the FASB issued Interpretation No. 47 (“FIN No. 47”), “Accounting for Conditional Asset Retirement Obligations” an interpretation of SFAS No. 143. FIN No. 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. FIN No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company adopted FIN No. 47 in the fourth quarter of 2005. The adoption of this interpretation did not have a material impact on the company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3”. SFAS 154 primarily requires retrospective application to prior periods’ financial statements for the direct effects 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 applies to all voluntary changes in accounting principle and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company is required to adopt the provision of SFAS 154, as applicable, beginning in fiscal year 2006.

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 disposed of in October 2004. At December 31, 2005, Chesapeake owned one piece of property that was formerly used by a water subsidiary. That property was listed for sale at December 31, 2005 and subsequently sold in January 2006. The results of operations for all water service businesses have been reclassified to discontinued operations for all periods presented. A loss of $52,000 and a gain of $12,000, net of tax, were recorded for 2004 and 2003, respectively, on the sale of the water operations. The Company did not have any discontinued operations in 2005.

- Page 51 -

Operating revenues for discontinued operations were $1.1 million and $9.8 million for 2004 and 2003, respectively. Operating losses for discontinued operations were $94,000 and $917,000 for 2004 and 2003, respectively. The balance sheet included the following discontinued operations for December 31, 2004:

·   Net property, plant, and equipment of $184,000;

·   Cash and other current assets were $5,000 and $63,000, respectively;

·   Common stock, additional paid-in capital, and retained deficits were $51,000, $3.9 million, and $6.5 million, respectively; and

·   Due to affiliates and other current liabilities were $2.7 million and $45,000, respectively.

- Page 52 -

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,	2005			2004		2003
Operating Revenues, Unaffiliated Customers
Natural gas distribution and transmission	$	166,388,562		$	124,073,939	$	110,071,054
Propane		48,975,349			41,499,687		41,029,121
Advanced information services		14,121,441			12,381,815		12,476,746
Other		144,384			-		($9,329	)
Total operating revenues, unaffiliated customers	$	229,629,736		$	177,955,441	$	163,567,592
Intersegment Revenues(1)
Natural gas distribution and transmission	$	193,404		$	172,427	$	175,757
Propane		668			-		-
Advanced information services		18,123			45,266		100,804
Other		618,492			647,378		711,159
Total intersegment revenues	$	830,687		$	865,071	$	987,720
Operating Income
Natural gas distribution and transmission	$	17,235,810		$	17,091,360	$	16,653,111
Propane		3,209,388			2,363,884		3,875,351
Advanced information services		1,196,544			387,193		691,909
Other and eliminations		(111,243	)		127,309		359,029
Total operating income	$	21,530,499		$	19,969,746	$	21,579,400
Depreciation and Amortization
Natural gas distribution and transmission	$	5,682,137		$	5,418,007	$	5,188,273
Propane		1,574,357			1,524,016		1,506,201
Advanced information services		122,569			138,007		190,548
Other and eliminations		189,146			177,508		204,814
Total depreciation and amortization	$	7,568,209		$	7,257,538	$	7,089,836
Capital Expenditures
Natural gas distribution and transmission	$	28,433,671		$	13,945,214	$	9,078,043
Propane		3,955,799			3,395,190		2,244,583
Advanced information services		294,792			84,185		76,924
Other		739,079			404,941		422,789
Total capital expenditures	$	33,423,341		$	17,829,530	$	11,822,339
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

At December 31,	2005		2004		2003
Identifiable Assets
Natural gas distribution and transmission	$	225,667,049	$	184,412,301	$	170,758,784
Propane		57,344,859		47,531,106		38,359,251
Advanced information services		2,062,902		2,387,440		2,912,733
Other		10,905,065		7,379,794		7,791,796
Total identifiable assets	$	295,979,875	$	241,710,641	$	219,822,564

- Page 53 -

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, 2005 had a gain in fair value of $46,000 and at December 31, 2004 had a loss in fair value of $182,000 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, 2005, including current maturities, had an estimated fair value of $68.5 million as compared to a carrying value of $63.9 million. At December 31, 2004, the estimated fair value was approximately $74.8 million as compared to a carrying value of $69.1 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, 2005 and 2004, 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.

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, 2005 and 2004. Testing for 2005 and 2004 has indicated that no impairment has occurred.

- Page 54 -

The carrying value and accumulated amortization of intangible assets subject to amortization for the two years ended December 31, 2005 are as follows:

	December 31, 2005				December 31, 2004
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	115,333	$	67,845	$	115,333	$	60,155
Acquisition costs		263,659		105,465		263,659		98,873
Total	$	378,992	$	173,310	$	378,992	$	159,028

Amortization of intangible assets was $14,000 and $15,000 for the years ended December 31, 2005 and 2004, respectively. The estimated annual amortization of intangibles is $14,000 per year for each of the years 2006 through 2010, 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,	2005			2004			2003
Common Stock shares issued and outstanding(1)
Shares issued — beginning of period balance		5,778,976			5,660,594			5,537,710
Dividend Reinvestment Plan (2)		41,175			40,993			51,125
Retirement Savings Plan		21,071			39,157			43,245
Conversion of debentures		22,609			18,616			18,788
Performance shares and options exercised (3)		19,268			19,616			9,726
Shares issued — end of period balance (4)		5,883,099			5,778,976			5,660,594
Treasury shares — beginning of period balance		(9,418	)		-			-
Purchases		(4,852	)		(15,316	)		-
Dividend Reinvestment Plan		2,142			-			-
Retirement Savings Plan		12,031			-			-
Other issuances		-			5,898			-
Treasury Shares — end of period balance		(97	)		(9,418	)		-
Total Shares Outstanding		5,883,002			5,769,558			5,660,594
(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 37,528, 48,175, and 47,659 shares at December 31, 2005, 2004 and 2003, respectively, held in a Rabbi Trust established by the Company relating to the Supplemental Executive Retirement Savings 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 share 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. The warrants are exercisable during a seven-year period after the grant date. At December 31, 2005, the Company had outstanding warrants of 30,000 at an average exercise price of $18.125 per share — 15,000 warrants expire in 2007 and the remaining 15,000 expire in 2008.

- Page 55 -

H. Long-term Debt

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

At December 31,	2005		2004
Uncollateralized senior notes:
7.97% note, due February 1, 2008	$	2,000,000	$	3,000,000
6.91% note, due October 1, 2010		3,636,363		4,545,454
6.85% note, due January 1, 2012		5,000,000		6,000,000
7.83% note, due January 1, 2015		16,000,000		20,000,000
6.64% note, due October 31, 2017		30,000,000		30,000,000
Convertible debentures:
8.25% due March 1, 2014		2,254,000		2,644,000
Promissory note		100,000		-
Total Long-Term Debt	$	58,990,363	$	66,189,454
Annual maturities of consolidated long-term debt for the next five years are as follows: $4,929,091 for 2006; $7,656,364 for 2007; $7,656,364 for 2008; $6,656,364 for 2009 and $6,656,364 for 2010.

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 2005 and 2004, debentures totaling $385,000 and $317,000, 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. During 2005, debentures totaling $5,000 were redeemed for cash. In 2004, no debentures were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.

On June 29, 2005, the Company entered into an agreement in principal with Prudential Investment Management Inc. Subsequently, the Company executed a Note Agreement, dated October 18, 2005, with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company), pursuant to which the investors agreed, subject to certain conditions, to purchase from the Company $20 million in principal of 5.5 percent Senior Notes (the “Notes”) issued by the Company provided that the Company elects to effect the sale of the Notes at any time prior to January 15, 2007. The terms of the Notes will require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes.

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, 2005, the Board of Directors (“Board”) had authorized the Company to borrow up to $50.0 million from various banks and trust companies under short-term lines of credit. As of December 31, 2005, the Company had three uncommitted and two committed, short-term bank lines of credit totaling $65.0 million, none of which required compensating balances. Under these lines of credit, the Company had short-term debt outstanding of approximately $35.5 million and $5.0 million at December 31, 2005 and 2004, respectively. The annual weighted average interest rates were 4.6 percent for 2005 and 3.7 percent for 2004. The Company also had a letter of credit outstanding in the amount of $694,000 that reduced the amounts available under the lines of credit.

- Page 56 -

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 $837,000, $934,000 and $1.1 million for 2005, 2004 and 2003, respectively. Future minimum payments under the Company’s current lease agreements are $646,000, $597,000, $466,000, $395,000 and $298,000 for the years of 2006 through 2010, respectively; and $2.4 million thereafter, totaling $4.8 million.

K. Employee Benefit Plans

Retirement Plans

Before 1999, Company employees generally participated in both a defined benefit 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 benefit Pension Plan to new participants. Employees who participated in the defined benefit Pension Plan at that time were given the option of remaining in (and continuing to accrue benefits under) the Pension Plan or receiving an enhanced matching contribution in the Retirement Savings Plan.

Because the defined benefit 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 Pension Plan to maintain its tax-qualified status. To avoid jeopardizing the tax-qualified status of the Pension Plan, the Company’s Board of Directors amended the defined benefit 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 benefit Pension Plan and the Retirement Savings Plan, effective January 1, 2005, so that Pension Plan participants who are actively employed by the Company on that date (1) receive two additional years of benefit service credit to be used in calculating their Pension Plan benefit (subject to the Pension Plan’s limit of 35 years of benefit service credit), (2) have the option to receive their 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 benefit 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 Pension Plan, a gain of approximately $172,000 (after tax) was recorded during 2004.

Defined Benefit Pension Plan

As described above, effective January 1, 2005, the defined benefit 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 in 2006. The measurement dates for the Pension Plan were December 31, 2005 and 2004, respectively.

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

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

- Page 57 -

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 Pension Plan at December 31, 2005 and 2004:

At December 31,	2005			2004
Change in benefit obligation:
Benefit obligation — beginning of year	$	12,053,063		$	11,948,755
Service cost		-			338,352
Interest cost		645,740			690,620
Change in assumptions		388,979			573,639
Actuarial loss		28,895			220,842
Amendments		-			883,753
Effect of curtailment/settlement		-			(2,171,289	)
Benefits paid		(717,056	)		(431,609	)
Benefit obligation — end of year		12,399,621			12,053,063
Change in plan assets:
Fair value of plan assets — beginning of year		12,097,248			11,301,548
Actual return on plan assets		400,674			1,227,309
Benefits paid		(717,056	)		(431,609	)
Fair value of plan assets — end of year		11,780,866			12,097,248
Funded status		(618,755	)		44,185
Unrecognized prior service cost		(34,259	)		(38,958	)
Unrecognized net actuarial gain		(129,739	)		(850,224	)
Net amount accrued		($782,753	)		($844,997	)
Assumptions:
Discount rate		5.25	%		5.50	%
Rate of compensation increase		4.00	%		4.00	%
Expected return on plan assets		6.00	%		7.88	%

The assumptions used for the discount rate of the plan were reviewed by the Company and lowered from 5.5 percent to 5.25 percent, reflecting a reduction 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 was lowered from 7.88 percent to 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. There was no change in the assumed compensation rate increases. The accumulated benefit obligation was $12.4 million and $12.1 million at December 31, 2005 and 2004, respectively.

- Page 58 -

Net periodic pension costs for the defined benefit Pension Plan for 2005, 2004 and 2003 include the components as shown below:

For the Years Ended December 31,	2005			2004			2003
Components of net periodic pension cost:
Service cost	$	0		$	338,352		$	325,366
Interest cost		645,740			690,620			684,239
Expected return on assets		(703,285	)		(869,336	)		(784,476	)
Amortization of:
Transition assets		-			(11,328	)		(15,104	)
Prior service cost		(4,699	)		(4,699	)		(4,699	)
Net periodic pension cost (benefit)		($62,244	)	$	143,609		$	205,326

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

For the Years Ended December 31,	2005			2004			2003
Assumptions:
Discount rate		5.50	%		5.88	%		6.50	%
Rate of compensation increase		4.00	%		4.00	%		4.50	%
Expected return on plan assets		6.00	%		7.88	%		8.50	%

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 $2.3 million and $2.2 million at December 31, 2005 and 2004, respectively. Accrued pension costs at December 31, 2005 include $959,000 related to a minimum pension liability. The minimum pension liability is a component of other comprehensive income.

Net periodic pension costs for the executive excess benefit pension plan for 2005, 2004 and 2003 include the components as shown below:

For the Years Ended December 31,	2005		2004		2003
Components of net periodic pension cost:
Service cost	$	0	$	105,913	$	107,877
Interest cost		119,658		87,568		80,039
Amortization of:
Prior service cost		-		2,090		2,787
Actuarial loss		49,319		21,699		18,677
Net periodic pension cost	$	168,977	$	217,270	$	209,380

- Page 59 -

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

At December 31,	2005			2004
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,162,952		$	1,406,190
Service cost		-			105,913
Interest cost		119,658			87,568
Actuarial loss		133,839			713,225
Amendments		-			60,000
Effect of curtailment/settlement		-			(184,844	)
Benefits paid		(93,978	)		(25,100	)
Benefit obligation — end of year		2,322,471			2,162,952
Change in plan assets:
Fair value of plan assets — beginning of year		-			-
Employer contributions		93,978			25,100
Benefits paid		(93,978	)		(25,100	)
Fair value of plan assets — end of year		-			-
Funded status		(2,322,471	)		(2,162,952	)
Unrecognized net actuarial loss		959,492			874,972
Net amount accrued		($1,362,979	)		($1,287,980	)
Assumptions:
Discount rate		5.25	%		5.50	%
Rate of compensation increase		4.00	%		4.00	%

The assumptions used for the discount rate of the plan were reviewed by the Company and lowered from 5.5 percent to 5.25 percent, reflecting a reduction in the interest rates of high quality bonds and a reduction in the expected life of the plan. There was no change in the assumed pay rate increases. The measurement dates for the executive excess benefit plan were December 31, 2005 and 2004, respectively.

Other Post-Retirement Benefits

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

Net periodic post-retirement costs for 2005, 2004 and 2003 include the following components:

For the Years Ended December 31,	2005		2004		2003
Components of net periodic post-retirement cost:
Service cost	$	6,257	$	5,354	$	5,138
Interest cost		77,872		86,883		85,319
Amortization of:
Transition obligation		27,859		27,859		27,859
Actuarial loss		88,291		78,900		66,271
Net periodic post-retirement cost	$	200,279	$	198,996	$	184,587

- Page 60 -

The following schedule sets forth the status of the post-retirement health care and life insurance plan:

At December 31,	2005			2004
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,599,280		$	1,471,664
Retirees		(59,152	)		91,747
Fully-eligible active employees		(31,761	)		22,071
Other active		26,317			13,798
Benefit obligation — end of year	$	1,534,684		$	1,599,280
Funded status		($1,534,684	)		($1,599,280	)
Unrecognized transition obligation		22,282			50,141
Unrecognized net actuarial loss		751,450			899,228
Net amount accrued		($760,952	)		($649,911	)
Assumptions:
Discount rate		5.25	%		5.50	%

The health care inflation rate for 2005 is assumed to be 8 percent for medical and 10 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 post-retirement benefit obligation by approximately $204,000 as of January 1, 2006, and would increase the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2006 by approximately $13,000. A one percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated post-retirement benefit obligation by approximately $169,000 as of January 1, 2006, and would decrease the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2006 by approximately $11,000. The measurement dates were December 31, 2005 and 2004, respectively.

Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the years 2006 through 2010 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)
2006	$	440,904	$	89,204	$	146,051
2007		713,051		88,490		152,321
2008		851,435		87,782		152,114
2009		1,431,421		87,080		155,098
2010		895,710		86,384		174,932
Years 2011 through 2015		4,089,216		692,464		987,030
(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.

- Page 61 -

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. 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.

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 earn interest income monthly.

The Company’s contributions to the 401(k) plans totaled $1,681,000, $1,497,000 and $1,444,000 for the years ended December 31, 2005, 2004 and 2003, respectively. As of December 31, 2005, there are 111,738 shares reserved to fund future contributions to the Retirement Savings Plan.

L. Executive Incentive Plans

A Performance Incentive Plan (“the Plan”) adopted in 1992 and amended in April 1998 allows for the granting of performance shares, stock options and stock appreciation rights to certain officers of the Company. The Company now uses performance shares exclusively. All stock options granted in prior years were exercised as of December 31, 2005 and all stock appreciation rights (“SARs”) were exercised prior to December 31, 2003.

The Plan enables participants the right to earn performance shares upon the Company’s achievement of certain performance goals, as set forth in the specific agreements, and the individual’s achievement of goals set annually for each executive. The Company recorded compensation expense of $701,000, $490,000 and $726,000 associated with these performance shares in 2005, 2004 and 2003, respectively.

In 1997, the Company executed Stock Option Agreements for a three-year performance period ending December 31, 2000, with certain executive officers. One-half of these options became exercisable over time and the other half became exercisable if certain performance targets were achieved. SFAS No. 123 requires the disclosure of pro forma net income and earnings per share as if fair value based accounting had been used to account for the stock-based compensation costs. The assumptions used in calculating the pro forma information were: dividend yield, 4.73 percent; expected volatility, 15.53 percent; risk-free interest rate, 5.89 percent; and an expected life of four years. No options have been granted since 1997; therefore, there is no pro forma impact for 2005, 2004 or 2003. The weighted average exercise price of outstanding options was $20.50 for all years presented. All outstanding options were exercised as of December 31, 2005.

Changes in outstanding options are shown on the chart below:

	2005					2004					2003
	Number of shares			Option Price		Number of shares			Option Price		Number of shares			Option Price
Balance — beginning of year		17,537		$	20.50		29,490		$	20.50		41,948		$	20.50
Options exercised		(17,537	)	$	20.50		(11,834	)	$	20.50		(12,458	)	$	20.50
Options forteited		-					(119	)	$	20.50		-
Balance — end of year		-					17,537		$	20.50		29,490		$	20.50
Exercisable		-					17,537		$	20.50		29,490		$	20.50

- Page 62 -

In 2000, the Company replaced the third year of this Stock Option Agreement with Stock Appreciation Rights. The SARs were awarded based on performance with a minimum number of SARs established for each participant. During 2001 and 2000, the Company granted 10,650 and 13,150 SARs, respectively, in conjunction with the agreement. During 2003, all SARs were exercised.

As of December 31, 2005, there were 293,481 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 remedial work at one former gas manufacturing plant site and is currently participating in the investigation, assessment or remediation of two other former gas manufacturing plant sites. These sites are located in three different jurisdictions. The Company has accrued liabilities for three sites referred to respectively as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites. The Company is currently in discussions with the Maryland Department of the Environment (“MDE”) regarding the possible responsibilities of the Company with respect to a former gas manufacturing plant site in Cambridge, Maryland.

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 expenditures for this site. Through December 31, 2005, the Company has incurred approximately $9.7 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.9 million has been recovered through December 2005 from other parties or through rates. As of December 31, 2005, a regulatory liability of approximately $298,000, 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 No Further Action (“NFA”) determination. The Company has been in discussions with the MDE regarding such request and is waiting on a determination from the MDE.

- Page 63 -

The Company has adjusted the liability with respect to the Salisbury Town Gas Light site to $2,300 at December 31, 2005. This amount is based on the estimated costs to perform limited product monitoring and recovery efforts and fulfill ongoing reporting requirements. A corresponding regulatory asset has been recorded, reflecting the Company’s belief that costs incurred will be recoverable in base rates.

Through December 31, 2005, 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. The Company expects to recover the remaining costs through rates.

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 Air Sparging and Soil Vapor Extraction 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 AS/SVE Pilot Study 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 AS/SVE Pilot Study 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 is now fully operational.

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 require remediation. Early estimates by the Company’s environmental consultant 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 vigorously 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.

The Company has accrued a liability of $350,000 as of December 31, 2005 for the Winter Haven site. Through December 31, 2005, the Company has incurred approximately $1.5 million of environmental costs associated with the Winter Haven site. At December 31, 2005 the Company had collected through rates $158,000 in excess of costs incurred. A regulatory asset of approximately $193,000, representing the uncollected portion of the estimated clean-up costs, has also been recorded. The Company expects to recover the remaining costs through rates.

Other

The Company is in discussions with the MDE regarding the possible responsibilities of the Company for remediation of a gas manufacturing plant site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time.

N. Other Commitments and Contingencies

Application of Florida Gross Receipts Tax

The Company provides natural gas supply and management services through its affiliate, Peninsula Energy Services Company, Inc. (“PESCO”), to commercial and industrial customers located in Florida. Substantially all of the natural gas purchased by PESCO’s customers is sold to the customers at delivery points located outside the State of Florida and because title to the gas typically passes outside Florida, PESCO does not collect gross receipts taxes from its customers. The Company understands that the Florida Department of Revenue has alleged that other companies in the natural gas marketing industry should have collected the gross receipts tax from the purchasers of the gas under similar circumstances. On June 8, 2005, new legislation was enacted that establishes the responsibilities of regulated utilities, including Chesapeake (d/b/a/ Central Florida Gas), as well as unregulated natural gas marketers, such as PESCO, for the collection of the gross receipts tax. The law also contains amnesty provisions relating to the failure to collect gross receipts taxes on sales made prior to January 1, 2006. While the Company does not believe that it has any liability, it has prepared the required amnesty documents to be submitted to the Department of Revenue for both Chesapeake and PESCO during the fourth quarter of 2005. The Company received a conditional approval of its amnesty documents from the Florida Department of Revenue in a letter dated October 18, 2005. This conditional approval is stated in the Company’s amnesty application and is expressly conditioned on those facts being accurate.

- Page 64 -

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, advanced information services subsidiary, and its Florida natural gas supply and management services subsidiary. The corporate guarantees provide for the payment of propane and natural gas purchases and office rent in the event of the subsidiary’s default. The aggregate amount of the obligations guaranteed at December 31, 2005 totaled $11.2 million, with the guarantees expiring on various dates in 2006. All payables of the subsidiaries are recorded in the Consolidated Financial Statements.

The Company has issued a letter of credit to its primary insurance company for $694,000, which expires June 1, 2006. The letter of credit was provided as security for claims amounts below the deductibles on the Company’s policies.

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 65 -

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
2005
Operating Revenue	$	77,845,248		$	42,220,377	$	35,155,121		$	74,408,990
Operating Income		11,504,343			2,324,945		(99,149	)		7,800,360
Net Income (Loss)
From continuing operations	$	6,232,796		$	795,924		($693,774	)	$	4,132,668
Net Income (Loss)	$	6,232,796		$	795,924		($693,774	)	$	4,132,668
Earnings per share:
Basic
From continuing operations	$	1.08		$	0.14		($0.12	)	$	0.70
Net Income (Loss)	$	1.08		$	0.14		($0.12	)	$	0.70
Diluted
From continuing operations	$	1.05		$	0.14		($0.12	)	$	0.69
Net Income (Loss)	$	1.05		$	0.14		($0.12	)	$	0.69
2004
Operating Revenue	$	63,762,360		$	34,292,972	$	26,614,699		$	53,285,410
Operating Income		10,699,307			2,162,794		282,738			6,824,907
Net Income (Loss)
From continuing operations	$	5,773,534		$	611,518		($584,171	)	$	3,748,786
From discontinued operations		(34,335	)		19,148		(72,041	)		(33,672	)
Net Income (Loss)	$	5,739,199		$	630,666		($656,212	)	$	3,715,114
Earnings per share:
Basic
From continuing operations	$	1.01		$	0.11		($0.10	)	$	0.65
From discontinued operations		-			-		(0.01	)		(0.01	)
Net Income (Loss)	$	1.01		$	0.11		($0.11	)	$	0.64
Diluted
From continuing operations	$	0.99		$	0.11		($0.10	)	$	0.64
From discontinued operations		(0.01	)		-		(0.01	)		(0.01	)
Net Income (Loss)	$	0.98		$	0.11		($0.11	)	$	0.63

- Page 66 -

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, 2005. 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, 2005.

Changes in Internal Controls

During the fiscal quarter of the Company ended December 31, 2005, 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.”

Item 9B. Other Information.

The Company filed a Current Report on Form 8-K, dated December 5, 2005, discussing the Compensation Committee's (the “Committee”) actions on November 30, 2005, including their approval of the compensation arrangements relating to the executive officers of the Company for 2006.

On November 30, 2005, the Committee approved awards under the Company’s Performance Incentive Plan to John R. Schimkaitis, President and Chief Executive Officer; Paul M. Barbas, Executive Vice President and Chief Operating 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, 2006 (the “2006 Award Year”). In addition, any Contingent Performance Shares that are not earned by the applicable executive officer during the 2006 Award Year may be earned in 2007 or 2008, if in either of those two succeeding years cumulative pre-established Performance Goals are achieved over, respectively, the three-year period ending in that year.

On November 30, 2005, 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, 2006 and ending December 31, 2006, 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 67 -

Part III

Item 10. Directors and Executive Officers of the Registrant.

The information required by this Item is incorporated herein by reference to the portions of the Proxy Statement, captioned “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, 2006 in connection with the Company’s Annual Meeting to be held on May 2, 2006.

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” and “Management Compensation” in the Proxy Statement to be filed not later than March 31, 2006, in connection with the Company’s Annual Meeting to be held on May 2, 2006.

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, 2006 in connection with the Company’s Annual Meeting to be held on May 2, 2006.

- Page 68 -

The following table sets forth information as of December 31, 2005, with respect to compensation plans of Chesapeake and its subsidiaries under which shares of Chesapeake common stock are authorized for issuance:

	(a)			(b)	(c)
	Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		0	(1)		293,481	(2)
Equity compensation plans not approved by security holders		30,000	(3)	$18.125	0
Total		30,000		$18.125	293,481
(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 1992 Performance Incentive Plan.
(3) In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying acquisition candiates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 shares of Chesapeake stock in 2001 at a price of $18.25 per share and 15,000 shares in 2000 at a price of $18.00. The warrants are exercisable during a seven-year period after the date granted.

Item 13. Certain Relationships and Related Transactions.

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, 2006, in connection with the Company’s Annual Meeting to be held on May 2, 2006.

- Page 69 -

Part IV

Item 15. Exhibits, Financial Statement Schedules.

(a)The following documents are filed as part of this report:

1.Financial Statements:

o   Report of Independent Registered Public Accounting Firm

o   Consolidated Statements of Income for each of the three years ended December 31, 2005, 2004 and 2003

o   Consolidated Balance Sheets at December 31, 2005 and December 31, 2004

o   Consolidated Statements of Cash Flows for each of the three years ended December 31, 2005, 2004 and 2003

o   Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2005, 2004 and 2003

o   Consolidated Statements of Income Taxes for each of the three years ended December 31, 2005, 2004 and 2003

o   Notes to Consolidated Financial Statements

2.Financial Statement Schedules — 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.

(b)Reports on Form 8-K:

·   Sale of LAMPS (Item 8.01)

·   Earnings press release dated November 4, 2004 (Items 2.02 and 9.01)

·   Compensation Committee approval of Compensation Arrangements (Item 1.01)

·   Approval of Paul M. Barbas to Chief Operating Officer (Item 5.02)

(c)Exhibits:

Exhibit 3(a) 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(a) 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(b) Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593.

Exhibit 4(c) 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(d) 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.

- Page 70 -

Exhibit 4(e) 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(f) 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(g) Agreement in principle between Prudential Investment Management, Inc. and Chesapeake Utilities Corporation related to the prospective purchase by Prudential of $20 million of 5.5% Senior Notes dated June 29, 2005, is incorporated herein by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2005, File No. 001-11590.

Exhibit 4(h) Note Agreement entered into by the Company on October 18, 2005, pursuant to which the Company, on or before December 28, 2006, will privately place $20 million of its 5.5% Senior Notes due 2020, is filed herewith as Exhibit 4.1.

*Exhibit 10(a) Executive Employment Agreement dated January 1, 2006, by and between Sharp Energy, Inc. and S. Robert Zola, is filed herewith as Exhibit 10.1.

*Exhibit 10(b) Form of Performance Share Agreement dated November 9, 2004, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Michael P. McMasters and Paul Barbas, is incorporated herein by reference to Exhibit 10.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.

*Exhibit 10(c) Performance Share Agreement dated December 30, 2005, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Paul M. Barbas and Michael P. McMasters, is filed herewith as Exhibit 10.2.

*Exhibit 10(d) Performance Share Agreement dated December 23, 2005, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith as Exhibit 10.3.

*Exhibit 10(e) Performance Share Agreement dated December 26, 2005, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith as Exhibit 10.4.

*Exhibit 10(f) 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(g) Executive Officer Compensation Arrangements, filed herewith as Exhibit 10.5.

*Exhibit 10(h) Chesapeake Utilities Corporation Directors Stock Compensation Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005 in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

*Exhibit 10(i) 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(j) 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(k) 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.

- Page 71 -

Exhibit 12 Computation of Ratio of Earning to Fixed Charges, filed herewith.

Exhibit 21 Subsidiaries of the Registrant, filed herewith.

Exhibit 23 Consent of Independent Registered Public Accounting Firm, filed herewith.

Exhibit 31.1 Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 6, 2006, filed herewith.

Exhibit 31.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 6, 2006, filed herewith.

Exhibit 32.1 Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 6, 2006, filed herewith.

Exhibit 32.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 6, 2006, filed herewith.

* Management contract or compensatory plan or agreement.

- Page 72 -

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 6, 2006

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 23, 2006	Date: March 6, 2006
/s/ Michael P. McMasters	/s/ Richard Bernstein
Michael P. McMasters, Senior Vice President	Richard Bernstein, Director
and Chief Financial Officer	Date: February 23, 2006
(Principal Financial and Accounting Officer)
Date: March 6, 2006
/s/ Thomas J. Bresnan	/s/ Walter J. Coleman
Thomas J. Bresnan, Director	Walter J. Coleman, Director
Date: March 6, 2006	Date: February 23, 2006
/s/ J. Peter Martin	/s/ Joseph E. Moore, Esq.
J. Peter Martin, Director	Joseph E. Moore, Esq., Director
Date: February 23, 2006	Date: February 23, 2006
/s/ Calvert A. Morgan, Jr.	/s/ Rudolph M. Peins, Jr.
Calvert A. Morgan, Jr., Director	Rudolph M. Peins, Jr., Director
Date: February 23, 2006	Date: February 23, 2006
/s/ Robert F. Rider
Robert F. Rider, Director
Date: February 23, 2006

- Page 73 -

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
2005	$	610,819	$	632,645	$	158,408	$	(540,494	)	$	861,378
2004	$	682,002	$	505,595	$	103,020	$	(679,798	)	$	610,819
2003	$	659,628	$	660,390	$	10,093	$	(648,109	)	$	682,002
(1) Recoveries.
(2) Uncollectible accounts charged off.