CHESAPEAKE UTILITIES CORP - 10-K Annual Report

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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, 2004 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 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. [ ]

Indicate by checkmark whether the registrant is an accelerated filer (as defined by Exchange Act Rule 12b-2). Yes [X].

No [ ].

As of March 11, 2005, 5,757,146 shares of common stock were outstanding. The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2004, 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 $124 million.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2005 Annual Meeting of Stockholders are incorporated by reference in Part III.

Chesapeake Utilities Corporation

Form 10-K

YEAR ENDED DECEMBER 31, 2004

TABLE OF CONTENTS

	Page
Part I	3
Item 1. Business	3
Item 2. Proprties	10
Item 3. Legal Proceedings	11
Item 4. Submission of Matters to a Vote of Security Holders	11
Part II	11
Item 5. Market for the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	11
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	35
Item 8. Financial Statements and Supplemental Data	35
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	66
Item 9A. Controls and Procedures	66
Item 9B. Other Information	66
Part III	66
Item 10. Directors and Executive Officers of the Registrant	66
Item 11. Executive Compensation	67
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	67
Item 13. Certain Relationships and Related Transactions	67
Item 14. Principal Accounting Fees and Services	68
Part IV	68
Item 15. Exhibits, Financial Statement Schedules	68
Signatures	72

Part I

Item 1. Business

Chesapeake Utilities Corporation (“Chesapeake” or “the Company”) 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 margins, capital expenditures, environmental remediation costs, regulatory approvals, market risks associated with the Company’s 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. See Item 7 under the heading “Management’s Discussion and Analysis — Cautionary Statement.”

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 SEC 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.

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. The Board of Directors has also adopted “Corporate Governance Guidelines on Director Independence,” which conform to the New York Stock Exchange (“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.

(a)

General Development of Business

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

Chesapeake’s three natural gas distribution divisions serve approximately 50,900 residential, commercial and industrial customers in central and southern Delaware, Maryland’s Eastern Shore and parts of Florida. The Company’s natural gas transmission subsidiary, Eastern Shore Natural Gas Company (“Eastern Shore”), operates a 307-mile interstate pipeline system that transports gas from various points in Pennsylvania to the Company’s Delaware and Maryland distribution divisions, as well as to other utilities and industrial customers in southern Pennsylvania, Delaware and on the Eastern Shore of Maryland. The Company’s propane distribution operation serves approximately 34,900 customers in central and southern Delaware, the Eastern Shore of both Maryland and Virginia and parts of Florida. The advanced information

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services segment provides domestic and international clients with information technology related business services and solutions for both enterprise and e-business applications.

During 2003, Chesapeake decided to exit the water services business and sold the assets of six of the seven dealerships. Chesapeake sold the remaining water dealership during 2004.

(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 D.”

(c)

Narrative Description of Business

The Company 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 (“PESCO”).

Delaware and Maryland. Chesapeake’s Delaware and Maryland utility divisions serve approximately 38,900 customers, of which approximately 38,700 are residential and commercial customers purchasing gas primarily for heating purposes. The remainder are industrial customers. For the year 2004, residential and commercial customers accounted for approximately 65% of the volume delivered by the divisions and 71% of the divisions’ revenue. The divisions’ industrial customers purchase gas, primarily on an interruptible basis, for a variety of manufacturing, agricultural and other uses. Most of Chesapeake’s customer growth in these divisions comes from new residential construction using gas-heating equipment.

Florida. The Florida division distributes natural gas to approximately 12,300 residential and commercial and 90 industrial customers in Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee, Liberty and Citrus Counties. Currently the 90 industrial customers, which purchase and transport gas on a firm basis, account for approximately 97% of the volume delivered by the Florida division and 64% 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 320 customers.

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”). 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’

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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, which expires in 2005; (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 2005 and (d) 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.

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

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

The Delaware division’s contracts with Eastern Shore include: (a) firm transportation capacity of 39,987 Dt per day for the period December through February, 38,765 Dt per day for the months of November, March and April, and 29,689 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’s firm transportation contracts with Eastern Shore also include Eastern Shore’s provision of swing transportation service that expires March 31, 2005. This service includes: (a) firm transportation capacity of 1,846 Dt per day on Transco’s pipeline system, retained by Eastern Shore, in addition to the Delaware division’s Transco capacity referenced earlier and (b) an interruptible storage service that supports a swing supply service provided by Transco. Upon expiration of this Eastern shore contract, the associated transportation and storage entitlements will become Delaware division entitlements.

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 27,500 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore 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, which expires in 2005; (b) firm transportation capacity of 155 Dt per day for December through February, expiring in 2006; and (c) 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.

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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 14,918 Dt per day for the period December through February, 14,254 Dt per day for the months of November, March and April and 9,693 Dt per day for the period May through October, with various expiration dates ranging from 2004 to 2013; (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. The Maryland division’s firm transportation contracts with Eastern Shore also include Eastern Shore’s provision of swing transportation service that expires March 31, 2005. This service includes: (a) firm transportation capacity of 969 Dt per day on Transco’s pipeline system, retained by Eastern Shore, in addition to the Maryland division’s Transco capacity referenced earlier and (b) an interruptible storage service that supports a swing supply service provided by Transco. Upon expiration of this Eastern Shore contract, the associated transportation and storage entitlements will become Maryland division entitlements.

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 9,000 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore 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; 21,200 Dt in May through September, and 27,416 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.

Eastern Shore. Eastern Shore has 2,888 thousand cubic feet (“Mcf”) of firm transportation capacity under contract with Transco, which expires in 2005. 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.

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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 Company’s 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 purchased gas adjustment clauses, which match revenues with gas costs and normally allow eventual full recovery of gas costs. Adjustments under these clauses require periodic filings and hearings with the relevant regulatory authority, but do not require a general rate proceeding.

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. In addition, the FERC regulates the rates Eastern Shore is charged for transportation and transmission line capacity and services provided by Transco and Columbia.

Management monitors the achieved rate of return in each jurisdiction in order to ensure the timely filing of rate adjustment applications.

Regulatory Proceedings

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

(i) (b) Propane Distribution and Wholesale Marketing

General

Chesapeake’s propane distribution group consists of (1) Sharp Energy, Inc. (“Sharp Energy”), a wholly owned subsidiary of Chesapeake, (2) Sharpgas, Inc. (“Sharpgas”), a wholly owned subsidiary of Sharp Energy, and (3) Tri-County Gas Co., Incorporated (“Tri-County”), a wholly owned subsidiary of Chesapeake. 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 pipelines. 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 2004, the Company’s propane distribution operations served approximately 34,900 propane customers on the Delmarva Peninsula, southeastern Pennsylvania and in Florida and delivered approximately 25 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.”

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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 the Company’s 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.”

Rates and Regulation

The Company’s 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. The Company changed its name from United Systems, Inc. in 2001 to reflect a change in service offerings.

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

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buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is a Delaware affiliated investment company. During 2004, Chesapeake formed a new company, OnSight Energy, LLC (“OnSight”), to provide distributed energy solutions to customers requiring reliable, uninterrupted energy sources and/or those wishing to reduce energy costs. OnSight signed its first contract in January 2005.

Chesapeake conducted its water conditioning and treatment and bottled water services business through separate subsidiaries. The assets of all of the water businesses were sold in 2003 and 2004 and the subsidiaries are now inactive.

(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, 2004, Chesapeake had 426 employees, including 187 in natural gas, 138 in propane and 71 in advanced information services. The remaining 30 employees are considered general and administrative and include officers of the Company, treasury, accounting, information technology, human resources and other administrative personnel.

(v) Executive Officers of the Registrant

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

John R. Schimkaitis (age 57) Mr. Schimkaitis is President and Chief Executive Office 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 48) Mr. Barbas is 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 position within G.E. Capital.

Michael P. McMasters (age 46) 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 44) 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

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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.

William C. Boyles (age 47) Mr. Boyles is Vice President and Corporate Secretary of Chesapeake Utilities Corporation. Mr. Boyles has served as Corporate Secretary since 1998 and Vice President since 1997. He previously served as Director of Accounting and Finance, Treasurer, Assistant Treasurer, Treasury Department Manager and Assistant Secretary. Prior to joining Chesapeake, he was employed as a Manager of Financial Analysis at Equitable Bank of Delaware and Group Controller at Irving Trust Company of New York.

S. Robert Zola (age 52) 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 24-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.

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, 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 800 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas and 678 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. During 2004, portions of the properties constituting Chesapeake’s distribution system were encumbered by the lien of the Mortgage securing Chesapeake’s First Mortgage Bonds. In December 2004, the outstanding First Mortgage Bonds were repaid in full.

(c)

Natural Gas Transmission

Eastern Shore owns and operates approximately 307 miles of transmission pipelines extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania and Hockessin, Delaware to approximately seventy-five delivery points in southeastern Pennsylvania, Delaware and the eastern shore of Maryland. Eastern Shore also owns compressor stations located in Daleville, Pennsylvania, Delaware City, Delaware and Bridgeville, Delaware. The compressor stations are used to increase pressures as necessary to meet system demands.

(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 38 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.

(e)

Water Services

The Company owns a facility in Salisbury, Maryland, formerly used in connection with its water business, which is listed for sale.

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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 the consolidated financial position of the Company.

(b)

Environmental

See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to Consolidated Financial Statements — Note N.”

Item 4. Submission of Matters to a Vote of Security Holders

None

Part II

Item 5. Market for the Registrant’s Common Equity, Related Shareholder 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 2004 and 2003 were as follows:

					Dividends
					Declared
	Quarter Ended	High	Low	Close	Per Share
2004
	March 31	$26.51	$24.30	$25.62	$0.275
	June 30	26.20	20.42	22.70	0.275
	September 30	25.40	22.10	25.10	0.280
	December 31	27.55	24.50	26.70	0.280
2003
	March 31	$19.84	$18.40	$18.80	$0.275
	June 30	23.84	18.45	22.60	0.275
	September 30	24.45	20.49	22.92	0.275
	December 31	26.70	23.02	26.05	0.275

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 times interest earned ratio must be at least 2.5. Additionally, under the terms of the Company’s Note Agreement for the 6.64 percent Senior Notes, the Company cannot, until the retirement of the Senior Note, pay any dividends after October 31, 2002 which exceed the sum of $10 million plus consolidated net income recognized after January 1, 2003. As of December 31, 2004, the amount available for future dividends under this covenant is $14.6 million.

At December 31, 2004, there were approximately 2,026 shareholders of record of the Common Stock.

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(b)

Changes in Securities, Use of Proceeds and Issues Purchases of Equity Securities

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, 2004.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽¹⁾		Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs ⁽¹⁾
October 1, 2004 through October 31, 2004 ⁽²⁾		417	$	25.59		-		-
November 1, 2004 through November 30, 2004		-	$	0.00		-		-
December 1, 2004 through December 31, 2004		-	$	0.00		-		-
Total		417	$	25.59		-		-

⁽¹⁾ Chesapeake has no publicly announced plans or programs to repurchase its shares.
⁽²⁾ The Company maintains a Rabbi Trust ("the Trust") that holds Chesapeake Utilities Corporation common stock, pursuant to a deferred compensation plan. The stock in the Trust is recorded as treasury stock. The Trustee reinvests cash dividends in Company stock. The stock is purchased on the open market.

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Page 13

Item 6. Selected Financial Data

For the Years Ended December 31,	2004			2003			2002			2001			2000

Operating (in thousands of dollars)⁽²⁾
Revenues
Natural gas distribution & transmission	$	124,246		$	110,247		$	93,588		$	107,418		$	101,138
Propane		41,500			41,029			29,238			35,742			31,780
Advanced informations systems		12,427			12,578			12,764			14,104			12,390
Other & eliminations		(218	)		(286	)		(334	)		(113	)		(131	)
Total revenues	$	177,955		$	163,568		$	135,256		$	157,151		$	145,177

Operating income
Natural gas distribution & transmission	$	17,091		$	16,653		$	14,973		$	14,405		$	12,798
Propane		2,364			3,875			1,052			913			2,135
Advanced informations systems		387			692			343			517			336
Other & eliminations		128			359			237			386			816
Total operating income	$	19,970		$	21,579		$	16,605		$	16,221		$	16,085

Net income from continuing operations	$	9,550		$	10,079		$	7,535		$	7,341		$	7,665


Assets (in thousands of dollars)
Gross property, plant and equipment	$	250,267		$	234,919		$	229,128		$	216,903		$	192,925
Net property, plant and equipment ⁽³⁾	$	177,053		$	167,872		$	166,846		$	161,014		$	131,466
Total assets ⁽³⁾	$	241,938		$	222,058		$	223,721		$	222,229		$	211,764
Capital expenditures ⁽²⁾	$	17,852		$	11,822		$	13,836		$	26,293		$	22,057


Capitalization (in thousands of dollars)
Stockholders' equity	$	77,962		$	72,939		$	67,350		$	67,517		$	64,669
Long-term debt, net of current maturities		66,190			69,416			73,408			48,409			50,921
Total capitalization	$	144,152		$	142,355		$	140,758		$	115,926		$	115,590

Current portion of long-term debt	$	2,909		$	3,665		$	3,938		$	2,686		$	2,665
Short-term debt		4,700			3,515			10,900			42,100			25,400
Total capitalization and short-term financing	$	151,761		$	149,535		$	155,596		$	160,712		$	143,655


⁽¹⁾ The years 1998, 1997, 1996 and 1995 have not been restated to reflect the "accrual" revenue recognition method due to the immateriality of the impact on the Company's financial results.
⁽²⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations.
⁽³⁾ The years 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS No. 143.

Page 14

Item 6. Selected Financial Data

For the Years Ended December 31,	1999			1998⁽¹⁾			1997⁽¹⁾			1996⁽¹⁾			1995⁽¹⁾

Operating (in thousands of dollars)⁽²⁾
Revenues
Natural gas distribution & transmission	$	75,637		$	68,770		$	88,108		$	90,044		$	79,110
Propane		25,199			23,377			28,614			36,727			26,806
Advanced informations systems		13,531			10,331			7,786			7,230			8,862
Other & eliminations		(14	)		(15	)		(182	)		(243	)		(1,661	)
Total revenues	$	114,353		$	102,463		$	124,326		$	133,758		$	113,117

Operating income
Natural gas distribution & transmission	$	10,388		$	8,820		$	9,240		$	9,627		$	10,812
Propane		2,622			965			1,137			2,668			2,128
Advanced informations systems		1,470			1,316			1,046			1,056			1,061
Other & eliminations		495			485			558			560			(34	)
Total operating income	$	14,975		$	11,586		$	11,981		$	13,911		$	13,967

Net income from continuing operations	$	8,372		$	5,329		$	5,812		$	7,764		$	7,681


Assets (in thousands of dollars)
Gross property, plant and equipment	$	172,068		$	152,991		$	144,251		$	134,001		$	120,746
Net property, plant and equipment ⁽³⁾	$	117,663		$	104,266		$	99,879		$	94,014		$	85,055
Total assets ⁽³⁾	$	166,958		$	145,029		$	145,719		$	155,786		$	130,998
Capital expenditures ⁽²⁾	$	21,365		$	12,516		$	13,471		$	15,399		$	12,887


Capitalization (in thousands of dollars)
Stockholders' equity	$	60,714		$	56,356		$	53,656		$	50,700		$	45,587
Long-term debt, net of current maturities		33,777			37,597			38,226			28,984			31,619
Total capitalization	$	94,491		$	93,953		$	91,882		$	79,684		$	77,206

Current portion of long-term debt	$	2,665		$	520		$	1,051		$	3,526		$	1,787
Short-term debt		23,000			11,600			7,600			12,735			5,400
Total capitalization and short-term financing	$	120,156		$	106,073		$	100,533		$	95,945		$	84,393


⁽¹⁾ The years 1998, 1997, 1996 and 1995 have not been restated to reflect the "accrual" revenue recognition method due to the immateriality of the impact on the Company's financial results.
⁽²⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations.
⁽³⁾ The years 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS No. 143.

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Item 6. Selected Financial Data

For the Years Ended December 31,	2004			2003			2002			2001			2000

Common Stock Data and Ratios
Basic earnings per share from continuing operations ⁽²⁾	$	1.66		$	1.80		$	1.37		$	1.37		$	1.46

Return on average equity from continuing operations ⁽²⁾		12.7	%		14.4	%		11.2	%		11.1	%		12.2	%

Common equity / total capitalization		54.1	%		51.2	%		47.8	%		58.2	%		55.9	%
Common equity / total capitalization and short-term financing		51.4	%		48.8	%		43.3	%		42.0	%		45.0	%

Book value per share	$	13.49		$	12.89		$	12.16		$	12.45		$	12.21


Market price:
High	$	27.550		$	26.700		$	21.990		$	19.900		$	18.875
Low	$	20.420		$	18.400		$	16.500		$	17.375		$	16.250
Close	$	26.700		$	26.050		$	18.300		$	19.800		$	18.625


Average number of shares outstanding		5,735,405			5,610,592			5,489,424			5,367,433			5,249,439
Shares outstanding at year-end		5,730,913			5,612,935			5,500,357			5,394,516			5,290,001
Registered common shareholders		2,026			2,069			2,130			2,171			2,166

Cash dividends declared per share	$	1.12		$	1.10		$	1.10		$	1.10		$	1.07
Dividend yield (annualized)		4.2	%		4.2	%		6.0	%		5.6	%		5.8	%
Payout ratio from continuing operations ⁽²⁾		67.5	%		61.1	%		80.3	%		80.3	%		73.3	%


Additional Data
Customers
Natural gas distribution and transmission		50,878			47,649			45,133			42,741			40,854
Propane distribution		34,888			34,894			34,566			35,530			35,563


Volumes
Natural gas deliveries (in MMCF)		31,430			29,375			27,935			27,264			30,830
Propane distribution (in thousands of gallons)		24,979			25,147			21,185			23,080			28,469


Heating degree-days (Delmarva Peninsula)		4,539			4,715			4,161			4,368			4,730

Propane bulk storage capacity (in thousands of gallons)		2,045			2,195			2,151			1,958			1,928

Total employees ⁽²⁾		426			439			455			458			471



⁽¹⁾ The years 1998, 1997, 1996 and 1995 have not been restated to reflect the "accrual" revenue recognition method due to the immateriality of the impact on the Company's financial results.
⁽²⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations.

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Item 6. Selected Financial Data

For the Years Ended December 31,	1999			1998⁽¹⁾			1997⁽¹⁾			1996⁽¹⁾			1995⁽¹⁾

Common Stock Data and Ratios
Basic earnings per share from continuing operations ⁽²⁾	$	1.63		$	1.05		$	1.17		$	1.58		$	1.59

Return on average equity from continuing operations ⁽²⁾		14.3	%		9.7	%		11.1	%		16.1	%		18.6	%

Common equity / total capitalization		64.3	%		60.0	%		58.4	%		63.6	%		59.0	%
Common equity / total capitalization and short-term financing		50.5	%		53.1	%		53.4	%		52.8	%		54.0	%

Book value per share	$	11.71		$	11.06		$	10.72		$	10.26		$	9.38


Market price:
High	$	19.813		$	20.500		$	21.750		$	18.000		$	15.500
Low	$	14.875		$	16.500		$	16.250		$	15.125		$	12.250
Close	$	18.375		$	18.313		$	20.500		$	16.875		$	14.625


Average number of shares outstanding		5,144,449			5,060,328			4,972,086			4,912,136			4,836,430
Shares outstanding at year-end		5,186,546			5,093,788			5,004,078			4,939,515			4,860,588
Registered common shareholders		2,212			2,271			2,178			2,213			2,098

Cash dividends declared per share	$	1.03		$	1.00		$	0.97		$	0.93		$	0.90
Dividend yield (annualized)		5.7	%		5.5	%		4.7	%		5.5	%		6.2	%
Payout ratio from continuing operations ⁽²⁾		63.2	%		95.2	%		82.9	%		58.9	%		56.6	%


Additional Data
Customers
Natural gas distribution and transmission		39,029			37,128			35,797			34,713			33,530
Propane distribution		35,267			34,113			33,123			31,961			31,115


Volumes
Natural gas deliveries (in MMCF)		27,383			21,400			23,297			24,835			29,260
Propane distribution (in thousands of gallons)		27,788			25,979			26,682			29,975			26,184


Heating degree-days (Delmarva Peninsula)		4,082			3,704			4,430			4,717			4,594

Propane bulk storage capacity (in thousands of gallons)		1,926			1,890			1,866			1,860			1,818

Total employees ⁽²⁾		466			431			397			338			335



⁽¹⁾ The years 1998, 1997, 1996 and 1995 have not been restated to reflect the "accrual" revenue recognition method due to the immateriality of the impact on the Company's financial results.
⁽²⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations.

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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 and transmission, 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 the Audit Committee of Chesapeake.

Regulatory Assets and Liabilities

Chesapeake records certain assets and liabilities in accordance with 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, 2004, Chesapeake had recorded regulatory assets of $4.0 million, including $1.5 million for under-recovered purchased gas costs, $737,000 for Florida flex rates and $712,000 for tax-related regulatory assets. The Company has recorded regulatory liabilities totaling $17.2 million, including $15.0 million for accrued asset removal cost and $1.3 million for self-insurance at December 31, 2004. 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 N 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, 2004, Chesapeake had recorded environmental regulatory assets of $279,000 and a liability for environmental costs of $462,000.

Propane Wholesale Marketing Contracts

Chesapeake’s propane wholesale marketing operation enters into forward and futures contracts that are considered derivatives under Statement of Financial Accounting Standards (“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 and Hattiesburg, Mississippi. Management estimates the market valuation based on reference to exchange-traded futures prices, historical differentials and actual trading activity at the end of the reporting period. At December 31, 2004, these contracts had net unrealized losses of $182,000 that were recorded in the financial statements. At December 31, 2003, these contracts had net unrealized gains of $172,000 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 the Company operates. 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 net, on a mark-to-market basis, 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. The initial test was performed upon adoption of SFAS No. 142 on January 1, 2002, and again at the end of 2002, 2003 and 2004. These tests were based on subjective measurements, including discounted cash flows of expected future operating results and market valuations of similar businesses. Those tests indicated that the goodwill associated with the water business was impaired and charges totaling $4.7 million (pre-tax) were recorded in 2002. At December 31, 2003 and 2004, no goodwill remained related to the water companies. The propane unit had $674,000 in goodwill at both December 31, 2003 and 2004. Testing has not indicated that any impairment is necessary. Goodwill is tested annually and when events change.

Results of Operations

The Company’s net income from continuing operations was $9.6 million, or $1.64 per share (diluted), for 2004, a decline of $530,000 compared to net income from continuing operations of $10.1 million, or $1.76 per share (diluted), for 2003. The decrease principally reflects a decline in operating income caused by warmer temperatures on the Delmarva Peninsula and cost increases associated with documenting and auditing internal control and compliance efforts in accordance with Section 404 of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”).

Page 19

Net income from continuing operations for 2003 was $10.1 million compared to $7.5 million for 2002. Net income for 2003 was $9.3 million, or $1.63 per share (diluted), compared to net income of $3.7 million in 2002, or $0.68 per share (diluted). 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 all periods. Discontinued operations experienced losses of $0.02, $0.13 and $0.34 per share (diluted) for 2004, 2003 and 2002, respectively. Chesapeake adopted SFAS No. 142 “Goodwill and Other Intangible Assets” in 2002. This resulted in a non-cash charge of $0.35 per share for goodwill impairment recorded as the cumulative effect of a change in accounting principle.

Net Income & Diluted Earnings Per Share Summary
								Increase									Increase
For the Years Ended December 31,		2004			2003			(decrease	)		2003			2002			(decrease	)
Net Income *
Continuing operations	$	9,550		$	10,080			($530	)	$	10,080		$	7,535		$	2,545
Discontinued operations		(121	)		(788	)		667			(788	)		(1,898	)		1,110
Change in accounting principle		-			-			-			-			(1,916	)		1,916
Total Net Income	$	9,429		$	9,292		$	137		$	9,292		$	3,721		$	5,571

Diluted Earnings Per Share
Continuing operations	$	1.64		$	1.76			($0.12	)	$	1.76		$	1.37		$	0.39
Discontinued operations		(0.02	)		(0.13	)		0.11			(0.13	)		(0.34	)		0.21
Change in accounting principle		-			-			-			-			(0.35	)		0.35
Total Earnings Per Share	$	1.62		$	1.63			($0.01	)	$	1.63		$	0.68		$	0.95

* Dollars in thousands.

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 $614,000. 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.

Improvement in Chesapeake’s 2003 overall results compared to 2002 was primarily related to strong customer growth and colder weather, which led to increased contributions from the Company’s natural gas and propane operations. The Delmarva natural gas operations experienced an increase of 6.4 percent in residential customers. Weather, measured in heating degree-days, was 13 percent colder than 2002. The propane wholesale marketing operation and the advanced information services segment also improved operating income compared to 2002.

Operating Income Summary (in thousands)
						Increase							Increase
For the Years Ended December 31,		2004		2003		(decrease	)		2003		2002		(decrease	)
Business Segment:
Natural gas distribution & transmission	$	17,091	$	16,653	$	438		$	16,653	$	14,973	$	1,680
Propane		2,364		3,875		(1,511	)		3,875		1,052		2,823
Advanced information services		387		692		(305	)		692		343		349
Other & eliminations		128		359		(231	)		359		237		122
Total Operating Income	$	19,970	$	21,579		($1,609	)	$	21,579	$	16,605	$	4,974

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

Page 20

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 $17.1 million for 2004, $16.7 million for 2003, and $15.0 million for 2002, resulting in an increase of $438,000 for 2004 and an increase of $1.7 million for 2003.

Natural Gas Distribution and Transmission (in thousands)
						Increase							Increase
For the Years Ended December 31,		2004		2003		(decrease	)		2003		2002		(decrease	)
Revenue	$	124,246	$	110,247	$	13,999		$	110,247	$	93,588	$	16,659
Cost of gas		77,456		65,495		11,961			65,495		52,737		12,758
Gross margin		46,790		44,752		2,038			44,752		40,851		3,901

Operations & maintenance		21,129		19,893		1,236			19,893		18,045		1,848
Depreciation & amortization		5,418		5,188		230			5,188		5,050		138
Other taxes		3,152		3,018		134			3,018		2,783		235
Other operating expenses		29,699		28,099		1,600			28,099		25,878		2,221

Total Operating Income	$	17,091	$	16,653	$	438		$	16,653	$	14,973	$	1,680

Natural Gas Heating Degree-Day (HDD) and Customer Analysis
					Increase						Increase
For the Years Ended December 31,		2004		2003	(decrease	)		2003		2002	(decrease	)
Heating degree-days — Delmarva
Actual		4,539		4,715	(176	)		4,715		4,161	554
10-year average		4,383		4,409	(26	)		4,409		4,393	16

Average number of residential customers
Delmarva		34,352		31,996	2,356			31,996		30,073	1,923
Florida		10,910		10,189	721			10,189		9,755	434
Total		45,262		42,185	3,077			42,185		39,828	2,357

Estimated gross margin per HDD	$	1,800	$	1,680			$	1,680	$	1,730
Per Delmarva residential customer added:
Estimated gross margin	$	372	$	360			$	360	$	360
Estimated other operating expenses	$	104	$	100			$	100	$	100

2004 Compared to 2003

Revenue and cost of gas increased in 2004 compared to 2003, primarily due to changes in natural gas commodity prices and customer growth. 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 bad debt expense.

Gross margin grew by $2.0 million in 2004 compared to 2003. The Company estimates that warmer weather reduced gross margin by $317,000. 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

Page 21

growth was net of lower consumption per customer, that 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.

Higher other operating expenses partially offset the gross margin increase. Included in the 2004 expenses were $382,000 related to Sarbanes-Oxley Section 404 compliance implementation. Excluding the Sarbanes-Oxley costs, expenses would have increased $1.2 million, or 4.3 percent. The higher other operating expenses reflect the costs to support customer growth.

2003 Compared to 2002

Revenue and cost of gas increased in 2003 compared to 2002, primarily due to changes in natural gas commodity prices. Revenue and cost of gas were also affected by the unbundling of services that took effect in 2001 for all non-residential customers of the Florida division and in November 2002 for residential customers. As a result, all Florida customers have switched from sales service, where they purchased both the commodity and transportation service from the Company, to purchasing transportation service only. Therefore, there are no longer revenues or costs associated with the commodities.

Gross margin for the Delaware and Maryland distribution divisions increased $2.7 million in 2003 over 2002. Temperatures in 2003 were 13 percent colder than the prior year. The Company estimates that the colder weather in 2003 generated an additional $931,000 of gross margin compared to 2002. Additionally, the increase of 1,923 residential customers, or 6.4 percent, contributed an estimated $692,000 to gross margin. The growth also required an estimated additional cost of $192,000 for operations and maintenance expenses. Also contributing to the increased gross margin were rate increases in Delaware that became effective in December 2002 and volumetric increases for existing customers.

Gross margin for the Florida distribution operations increased $1.2 million, due to the implementation of transportation services for residential customers and customer additions. Residential customer growth reached 4.4 percent in Florida, an increase of 434 customers. Agreements with two new industrial customers also helped increase gross margin.

Gross margin for the transmission operation increased by $219,000 in 2003 compared to 2002. An increase in interruptible transportation gross margin and volume added through a system expansion completed in November 2002 were partially offset by a rate reduction that became effective December 2002. The rate agreement is more fully discussed in the section below captioned “Regulatory Activities.”

The natural gas gross margin increases in 2003 were partially offset by higher operating expenses, primarily operations and maintenance expenses and other taxes that relate to the increased volumes and earnings as well as pension and employee costs.

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Propane

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. During 2003, the propane segment experienced an increase in operating income of $2.8 million, or 268 percent, over 2002. In addition, gross margin increased $3.4 million, partially offset by an increase of $527,000 in operating expenses.

Propane (in thousands)
						Increase							Increase
For the Years Ended December 31,		2004		2003		(decrease	)		2003		2002		(decrease	)
Revenue	$	41,500	$	41,029	$	471		$	41,029	$	29,238	$	11,791
Cost of sales		25,155		22,762		2,393			22,762		14,321		8,441
Gross margin		16,345		18,267		(1,922	)		18,267		14,917		3,350

Operations & maintenance		11,718		12,053		(335	)		12,053		11,519		534
Depreciation & amortization		1,524		1,506		18			1,506		1,603		(97	)
Other taxes		739		833		(94	)		833		743		90
Other operating expenses		13,981		14,392		(411	)		14,392		13,865		527

Total Operating Income	$	2,364	$	3,875		($1,511	)	$	3,875	$	1,052	$	2,823

Propane Heating Degree-Day (HDD) Analysis
					Increase						Increase
For the Years Ended December 31,		2004		2003	(decrease	)		2003		2002	(decrease	)
Heating degree-days — Delmarva
Actual		4,539		4,715	(176	)		4,715		4,161	554
10-year average		4,383		4,409	(26	)		4,409		4,393	16

Estimated gross margin per HDD	$	1,691	$	1,670			$	1,670	$	1,566

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 $298,000. 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.

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Other operating expenses decreased $411,000 despite additional costs of $142,000 associated with the implementation of Sarbanes-Oxley Section 404 compliance procedures. Adjusted for Sarbanes-Oxley, operating expenses dropped $553,000. The decrease included reductions in incentive compensation, revenue-related taxes and lower delivery costs.

2003 Compared to 2002

The increases in revenues and cost of sales in 2003 compared to 2002 were caused both by increases in volumes and by increases in the commodity prices of propane. Commodity price changes are generally 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 $2.9 million for the Delmarva distribution operations. Volumes sold in 2003 increased 3.3 million gallons or 15 percent. Temperatures in 2003 were 13 percent colder than 2002 causing an estimated gross margin increase of $925,000. Additionally, the gross margin per retail gallon improved by $0.0374 in 2003 compared to 2002. The gross margin increase was partially offset by increased operating expenses, primarily related to the higher volumes, such as delivery costs, and incentive compensation costs associated with higher income. The Florida propane distribution operations experienced an increase in gross margin of $102,000 in 2003; however, the gross margin included $192,000 related to a non-recurring service project.

The Company’s propane wholesale marketing operation experienced an increase in gross margin of $51,000 and a decrease of $148,000 in operating expenses, leading to an improvement of $199,000 in operating income over 2002. Wholesale price volatility created trading opportunities during some portions of the year; however, these were partially offset by reduced trading activities particularly during the third quarter.

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 $387,000 for 2004, $692,000 for 2003, and $343,000 for 2002.

Advanced Information Services (in thousands)
					Increase							Increase
For the Years Ended December 31,		2004		2003	(decrease	)		2003		2002		(decrease	)
Revenue	$	12,427	$	12,578	($151	)	$	12,578	$	12,764		($186	)
Cost of sales		7,015		7,018	(3	)		7,018		6,700		318
Gross margin		5,412		5,560	(148	)		5,560		6,064		(504	)

Operations & maintenance		4,405		4,196	209			4,196		4,940		(744	)
Depreciation & amortization		138		191	(53	)		191		208		(17	)
Other taxes		482		481	1			481		573		(92	)
Other operating expenses		5,025		4,868	157			4,868		5,721		(853	)

Total Operating Income	$	387	$	692	($305	)	$	692	$	343	$	349

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.

Revenues declined in 2003 compared to 2002. The revenue decline was more than offset by reduced operating costs, primarily payroll and benefits. As noted above, a non-recurring sale of software contributed $302,000 to operating income in 2003.

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Other Operations and Eliminations

Other operations and eliminating entries contributed operating income of $128,000 for 2004 compared to income of $359,000 for 2003. Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries. In addition, in 2004 the Company formed OnSight Energy, LLC (“OnSight”) to provide distributed energy services. As a result of the start-up, other operating expenses increased by $207,000 over 2003 levels. OnSight entered into its first contract in the first quarter of 2005. Eliminations are entries required to eliminate activities between business segments from the consolidated results.

Other Operations & Eliminations (in thousands)
						Increase								Increase
For the Years Ended December 31,		2004		2003		(decrease	)		2003		2002			(decrease	)
Revenue	$	647	$	702		($55	)	$	702	$	717			($15	)
Cost of sales		-		-		-			-		-			-
Gross margin		647		702		(55	)		702		717			(15	)

Operations & maintenance		279		80		199			80		83			(3	)
Depreciation & amortization		210		238		(28	)		238		233			5
Other taxes		63		55		8			55		57			(2	)
Other operating expenses		552		373		179			373		373			-

Operating Income — Other	$	95	$	329		($234	)	$	329	$	344			($15	)
Operating Income — Eliminations	$	33	$	30	$	3		$	30		($107	)	$	137

Total Operating Income	$	128	$	359		($231	)	$	359	$	237		$	122

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.

Losses from discontinued operations were $788,000 and $1.9 million for 2003 and 2002, respectively. The 2002 loss included a non-cash impairment charge of $973,000 (after-tax) related to goodwill.

Income Taxes

Operating income taxes decreased in 2004 compared to 2003, due to decreased income. The effective current federal income tax rate for both years was approximately 34 percent. Operating income taxes increased in 2003 compared to 2002, due to increased income. During 2004, 2003 and 2002, the Company benefited 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 $549,000, $238,000 and $495,000 for the years 2004, 2003 and 2002, respectively. This includes interest income, earned primarily on regulatory assets, and gains from the sale of assets.

Interest Expense

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

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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.

In 2002, approximately $103,000 of interest expense was associated with discontinued operations and has been reclassified on the income statement to discontinued operations. Total interest expense for 2003 increased approximately $648,000, or 13 percent, over 2002. The increase reflects the increase in the average long-term debt balance caused by the placement of $30.0 million completed in October 2002. The average long-term debt balance during 2003 was $75.4 million with an average interest rate of 7.2 percent, compared to $54.6 million with an average interest rate of 7.52 percent in 2002. The increase in long-term debt was partially offset by a reduction in the average short-term borrowing balance, which decreased from $29.4 million in 2002 to $3.5 million in 2003. The average interest rate for short-term borrowing was essentially constant at 2.4 percent for 2002 and 2003.

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 temporarily to finance capital expenditures. During 2004, net cash provided by operating activities was $23.5 million, cash used by investing activities was $16.8 million and cash used by financing activities was $8.1 million.

During 2003, net cash provided by operating activities was $22.9 million, cash used by investing activities was $5.9 million and cash used by financing activities was $16.4 million. Cash provided by operating activities declined by $2.0 million from 2002 to 2003, as higher income in 2003 was more than offset by changes in working capital items.

As of December 31, 2004, the Board of Directors has authorized the Company to borrow up to $35.0 million of short-term debt from various banks and trust companies. On December 31, 2004, 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, 2004 and 2003 were $4.7 million and $3.5 million, respectively. In 2004 and 2003, Chesapeake used funds provided by operations to fund net investing and financing activities.

During 2004, 2003 and 2002, net cash used for investing activities totaled approximately $16.8, $5.9 and $14.1 million, respectively. Cash used by investing activities was up in 2004, due primarily to increased capital expenditures in 2004, compared to 2003, which included cash provided by the sales of the water businesses in 2003 and lower recoveries of environmental costs. Additions to property, plant and equipment in 2004 totaled $17.8 million and were primarily for natural gas distribution ($8.8 million), natural gas transmission ($5.2 million) and propane distribution ($3.4 million). The property, plant and equipment expenditures for 2003 totaled $11.8 million and were primarily for natural gas distribution ($7.5 million), propane distribution ($2.0 million) and natural gas transmission ($1.8 million). In both 2004 and 2003, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. Natural gas transmission expenditures related primarily to expanding the Company’s transmission system.

Chesapeake has budgeted $38.6 million for capital expenditures during 2005. This amount includes $15.4 million for natural gas distribution, $16.9 million for natural gas transmission, $5.1 million for propane distribution and wholesale marketing, $504,000 for advanced information services and $695,000 for other operations. The natural gas distribution and transmission expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth and for the replacement of equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other category includes

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general plant, computer software and hardware. Financing for the 2005 capital expenditure program is expected to be provided from short-term borrowing and cash provided by operating activities. 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 $245,000 in 2005 and $137,000 in 2006 for environmental-related expenditures. Additional expenditures may be required in future years (see Note N 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, 2004, common equity represented 54.1 percent of total capitalization, compared to 51.2 percent in 2003. If short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 51.4 percent and 48.8 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.

Financing Activities

On October 31, 2002, Chesapeake completed a private placement of $30.0 million of 6.64 percent Senior Notes due October 31, 2017. The Company used the proceeds to repay short-term debt.

Chesapeake issued common stock in connection with its Automatic Dividend Reinvestment and Stock Purchase Plan in the amounts of 40,993 shares in 2004, 51,125 shares in 2003 and 49,782 shares in 2002. Chesapeake also issued shares of common stock totaling 39,157, 43,245 and 52,740 in 2004, 2003 and 2002, respectively, for matching contributions for the Retirement Savings Plan.

Chesapeake liquidated approximately $4.0 million and $4.3 million of long-term debt in 2004 and 2003, respectively. These amounts include conversions to equity of convertible stock.

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Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2004:

	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⁾	$	2,909,091	$	12,545,455	$	14,272,727	$	39,371,273	$	69,098,546
Operating leases ⁽²⁾		762,063		629,256		269,333		224,850		1,885,502
Purchase obligations ⁽³⁾
Transmission capacity		8,322,842		12,966,711		12,469,841		30,738,701		64,498,095
Storage — Natural Gas		1,412,985		2,752,221		2,719,934		7,916,096		14,801,236
Commodities		12,720,923		-		-		-		12,720,923
Forward and futures contracts — Propane ⁽⁴⁾		8,301,983		-		-		-		8,301,983
Unfunded benefits ⁽⁵⁾		241,811		483,336		527,639		2,677,588		3,930,374
Funded benefits ⁽⁶⁾		48,303		96,606		96,606		144,908		386,423
Total Contractual Obligations	$	34,720,001	$	29,473,585	$	30,356,080	$	81,073,416	$	175,623,082

⁽¹⁾ Principal payments on long-term debt, see Note I, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
⁽²⁾ See Note K, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
⁽³⁾ See Note O, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information.
⁽⁴⁾ The Company has also entered into forward and futures sale contracts of $8,160,253, see "Market Risk" of the Management's Discussion and Analysis for further information.
⁽⁵⁾ The Company has recorded long-term liabilities of $650,000 at December 31, 2004 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 $1.2 million at December 31, 2004 for funded benefits. Of this total, $386,000 has been funded using a Rabbi Trust and an asset in the same amount is recorded in the Investments caption on the Balance Sheet. The other balance, $845,000, represents a liability for a defined benefit pension plan. The 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 L, "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, 2004. However, this is subject to change based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets.

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary. The corporate guarantees provide for the payment of propane purchases by the subsidiary, in the case of the subsidiary’s default. The liabilities for these purchases are included in the Company’s Consolidated Financial Statements. The guarantees at December 31, 2004, totaled $3.8 million and expire on various dates in 2005.

The Company has issued a letter of credit to its main insurance company for $694,000, which expires June 1, 2005. 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 September 1, 2004, the Delaware division filed its annual Gas Sales Service Rates (“GSR”) application that was effective for service rendered on and after November 1, 2004 with the Delaware Public Service Commission (“Delaware PSC”). On September 14, 2004, the Delaware PSC approved the GSR charges, subject to full evidentiary hearings and a final decision. Due to the most recent rise in natural gas market prices, the Delaware

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division’s under-collection balance was expected to exceed the six percent tolerance as defined in its tariff; therefore, on December 1, 2004, the Delaware division filed an “out-of-cycle” rate application with the Delaware PSC proposing to place revised GSR charges into effect on January 1, 2005, pending approval by the Delaware PSC. On December 21, 2004, the Delaware PSC granted approval of these supplemental GSR charges, subject to full evidentiary hearings and a final decision. An evidentiary hearing is currently scheduled for May 26, 2005, with a final decision by the Delaware PSC expected during the third quarter of 2005.

On November 1, 2004, 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, 2004. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 9, 2004, subject to full evidentiary hearings and a final decision. An evidentiary hearing is currently scheduled for June 2, 2005, with a final decision by the Delaware PSC expected during the third quarter of 2005.

Maryland. On December 16, 2004, 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, 2004. On January 4, 2005, 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. Since no parties involved in the case appealed or provided written exceptions to the proposed findings, the findings became a final order of the Maryland PSC on February 4, 2005.

Florida. On March 29, 2002, the Florida division filed tariff revisions with the Florida Public Service Commission (“Florida PSC”) to complete the natural gas commodity and transportation unbundling process by requiring all customers, including residential, to migrate to transportation service and authorize the Florida division to exit the commodity merchant function. Transportation services were already available to all non-residential customers. On November 5, 2002, the Florida PSC approved the Company’s request for the first phase of the unbundling process as a pilot program for a minimum two-year period. The Company has implemented the program. As a part of this pilot program, the Company submitted several filings during 2003 to address transition costs, the disposition of the over-recovered gas cost balances, the implementation of the operational balancing account and the level of base rates. The Florida PSC approved the transition cost resolution on January 4, 2004. The Florida PSC also approved the refunding of the remaining balance of $246,000 in the over-recovered purchased gas cost account. The refund was made in March 2004. Additionally, the Florida PSC approved the activation of the operational balancing account on January 4, 2004. On July 15, 2003, the Florida PSC approved a rate restructuring proposed by Chesapeake. The restructuring created three new low volume rate classes, with customer charge levels that are designed to ensure that all customers receive benefits from the unbundling.

On August 25, 2004, the Florida division filed a petition with the Florida PSC for authorization to restructure rates and establish new customer classifications. The filing is 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 vote is expected to become final in March 2005.

Eastern Shore. Pursuant to the requirements of the Stipulation and Agreement dated August 1, 1997, Eastern Shore filed a rate change with the FERC on October 31, 2001. The final agreement reached with the FERC provided for a reduction in rates of approximately $456,000 on an annual basis. Settlement rates went into effect on December 1, 2002.

During October 2002, Eastern Shore filed for recovery of gas supply realignment costs associated with the implementation of FERC Order No. 636. The costs totaled $196,000 (including interest). At that time, the FERC deferred review of the filing pending settlement of a related matter concerning another transmission company.

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Chesapeake understands that the other matter has now been resolved and Eastern Shore intends to resubmit its transition cost recovery filing during 2005.

On December 16, 2003, Eastern Shore filed revised tariff sheets to implement revisions to its Fuel Retention and Cash-Out provisions. The proposed tariff revisions permit Eastern Shore to incorporate its Deferred Gas Required for Operations amounts into the calculation of its annual Fuel Retention percentage adjustment and to implement a surcharge, effective July 1 of each year, to recover cash-out amounts. The FERC accepted Eastern Shore’s revised tariff sheets and they became effective on January 15, 2004, subject to certain revisions to clarify the tariff sheets. On January 30, 2004, Eastern Shore submitted the revised tariff sheets.

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 were completed in 2003 and 2004 with new Phase II service levels beginning November 1, 2004. Phase III is planned for construction during 2005.

On December 22, 2004, Eastern Shore filed to amend the Application, seeking FERC authorization to construct and operate new pipeline facilities necessary to provide an additional 7,450 dekatherms of daily firm transportation needs identified and requested by its customers to be available November 1, 2005. This amended filing is currently pending before the FERC. Eastern Shore has requested the FERC to expedite its decision-making process in order to construct the proposed new facilities on a timely basis. At December 31, 2004, the Company had recorded $210,000 in construction work in progress related to this project. While the Company cannot predict the final outcome of this pending amended application, the FERC has typically granted approval to construct and operate new pipeline facilities to serve its customers in a timely fashion.

Eastern Shore, on February 9, 2004, filed with the FERC a Plan and Schedule for Standards of Conduct Compliance as directed by the FERC’s Order No. 2004, issued on November 25, 2003. Such Standards of Conduct govern the relationship between transmission providers such as Eastern Shore and their energy affiliates. Order No. 2004 revises and conforms the current gas and electric standards by broadening the definition of an energy affiliate covered by such standards of conduct, and applies them uniformly to natural gas pipeline and electric transmission providers. Further, the standards are designed to assure that transmission providers cannot extend their market power over transmission to other energy markets by giving their energy affiliates unduly preferential treatment. The standards also help ensure transmission providers offer service to all customers on a non-discriminatory basis. The deadline for compliance with the Standards of Conduct was September 22, 2004. Eastern Shore performed the necessary training required by FERC and completed the posting of required information as described in Order No. 2004.

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 has completed its responsibilities related to the Dover Gas Light site and 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 N 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.

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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 I 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 $69.1 million at December 31, 2004, as compared to a fair value of $74.8 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, 2004, the propane distribution operation had entered into a put contract to protect the value of 1.1 million gallons of propane inventory from a drop in fair value. The put contract expires in January 2005.

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.

Page 31

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, 2004 and 2003 is shown in the following chart.

	Quantity	Estimated	Weighted Average
At December 31, 2004	in gallons	Market Prices	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 expire in 2005.



	Quantity	Estimated	Weighted Average
At December 31, 2003	in gallons	Market Prices	Contract Prices
Forward Contracts
Sale	11,956,000	$0.6650 — $0.6900	$0.6153
Purchase	10,876,000	$0.6650 — $0.6900	$0.6085

Futures Contracts
Sale	200,000	$0.6650 — $0.6675	$0.6675

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire in 2004.

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 its 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.

Page 32

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 now 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 in 1994 to compete for customers eligible for transportation services. The Company also provides sales service in Delaware.

The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally from local outlets of national distribution companies and local businesses, because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas serviced by natural gas pipeline or distribution systems.

The propane wholesale marketing operation competes against various marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.

The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them than does the Company. In addition, changes in the advanced information services business are occurring rapidly, which could adversely impact the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.

Inflation

Inflation affects the cost of labor, products and services required for operation, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. Fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanism in the Company’s tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for regulated operations while monitoring the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, Chesapeake adjusts its propane selling prices to the extent allowed by the market.

Recent Pronouncements

On January 12, 2004, the Financial Accounting Standards Board (“FASB”) released FASB Staff Position No. SFAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (“the Act”). On May 19, 2004, the FASB released FASB Staff Position No. SFAS 106-2, which superseded SFAS 106-1. SFAS No. 106-2 provides guidance on the accounting for the effects of the Act and requires certain disclosures regarding the effect of the federal subsidy provided by the Act. It is effective for the first interim or annual period beginning after June 15, 2004. Adoption of SFAS No. 106-2 did not have a material impact on the Company’s post-retirement benefit obligation. Chesapeake’s post-retirement health benefits require

Page 33

that Medicare be the primary insurance for all participants that qualify for Medicare coverage; therefore, there is no federal subsidy for Chesapeake’s plan.

The Emerging Issues Task Force (“EITF”) of the FASB issued EITF No. 03-6 on February 9, 2004. It requires that earnings used to calculate earnings per share be allocated between common shareholders and other securities holders based on their respective rights to receive dividends. This requirement was effective for the second quarter of 2004. It had no impact on the Company’s calculation of earnings per share.

In December 2004, the FASB released a revision (“Share-Based Payment”) to SFAS No. 123 “Accounting for Stock-Based Compensation.” It is effective for the first interim or 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 does not expect the adoption of SFAS No. 123 to have a material impact on the financial statements.

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 34

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 Controls Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal controls over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). A system of internal controls is designed to provide reasonable assurance as to the fair and reliable preparation and presentation of the consolidated financial statements, as well as to safeguard assets from unauthorized use or disposition.

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 controls 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. Although there are inherent limitations on internal controls over financial reporting, Chesapeake’s management has evaluated and concluded that Chesapeake’s internal controls over financial reporting were effective as of December 31, 2004.

Management’s assessment of the effectiveness of Chesapeake’s internal controls over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm and auditor of Chesapeake’s consolidated financial statements.

Page 35

Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and Stockholders

of Chesapeake Utilities Corporation

We have completed an integrated audit of Chesapeake Utilities Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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.

As discussed in Note G to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” in 2002. In addition, as discussed in Note B to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” in 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2004 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, 2004, 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.

Page 36

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

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

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Boston, MA

March 16, 2005

Page 37

Consolidated Statements of Income

For the Years Ended December 31,		2004			2003			2002
Operating Revenues	$	177,955,441		$	163,567,592		$	135,256,498

Operating Expenses
Cost of sales, excluding costs below		109,626,377			95,246,819			73,648,958
Operations		35,146,595			33,526,804			31,833,198
Maintenance		1,518,774			1,737,855			1,924,210
Depreciation and amortization		7,257,538			7,089,836			7,089,190
Other taxes		4,436,411			4,386,878			4,156,263
Total operating expenses		157,985,695			141,988,192			118,651,819

Operating Income		19,969,746			21,579,400			16,604,679

Other income net of other expenses		549,156			238,439			494,904

Interest charges		5,268,145			5,705,911			4,955,022

Income Before Income Taxes		15,250,757			16,111,928			12,144,561

Income taxes		5,701,090			6,032,445			4,609,552
Net Income from Continuing Operations		9,549,667			10,079,483			7,535,009

Loss from discontinued operations, net of tax benefit of $59,751, $74,997 and $964,869		(120,900	)		(787,607	)		(1,897,837	)

Cumulative effect of change in accounting principle, net of tax benefit of $1,284,000		-			-			(1,916,000	)

Net Income	$	9,428,767		$	9,291,876		$	3,721,172

Earnings Per Share of Common Stock:
Basic
From continuing operations	$	1.66		$	1.80		$	1.37
From discontinued operations		(0.02	)		(0.14	)		(0.34	)
Effect of change in accounting principle		-			-			(0.35	)
Net Income	$	1.64		$	1.66		$	0.68

Diluted
From continuing operations	$	1.64		$	1.76		$	1.37
From discontinued operations		(0.02	)		(0.13	)		(0.34	)
Effect of change in accounting principle		-			-			(0.35	)
Net Income	$	1.62		$	1.63		$	0.68

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

Page 38

Consolidated Statements of Cash Flows

For the Years Ended December 31,

2004

2003

2002

Operating Activities

Net Income

$

9,428,767

$

9,291,876

$

3,721,172

Adjustments to reconcile net income to net operating cash:

Depreciation and amortization

7,272,768

8,030,398

7,932,345

Depreciation and accretion included in other costs

2,619,069

2,467,582

2,490,799

Goodwill impairment

-

-

4,674,000

Deferred income taxes, net

4,211,481

2,397,594

263,826

Mark-to-market adjustments

353,183

457,901

(704,908

)

Employee benefits and compensation

1,729,238

2,042,093

1,200,131

Other, net

33,184

15,874

34,571

Changes in assets and liabilities:

Accounts receivable, net

(11,723,505

)

(3,565,363

)

(2,821,343

)

Inventories, storage gas and materials

(1,741,941

)

(466,411

)

311,668

Prepaid expenses and other current assets

(402,702

)

(316,425

)

(135,943

)

Other deferred charges

851,704

239,862

(347,669

)

Accounts payable, net

11,648,832

929,428

6,098,044

Income taxes receivable

118,489

25,090

182,591

Accrued interest

(51,272

)

(47,464

)

(1,058,570

)

Accrued compensation

(794,194

)

762,629

(261,114

)

Regulatory assets

(479,562

)

273,646

2,925,107

Other current liabilities

277,944

(112,356

)

262,220

Other long-term liabilities

109,533

521,870

141,358

Net cash provided by operating activities

23,461,016

22,947,824

24,908,285

Investing Activities

Property, plant and equipment expenditures, net

(17,806,950

)

(11,790,364

)

(14,705,244

)

Change in intangibles

-

-

12,426

Sale of discontinued operations

415,707

3,732,649

-

Sale of investments

178,812

-

-

Environmental recoveries, net of expenditures

364,088

2,193,318

631,750

Net cash used by investing activities

(16,848,343

)

(5,864,397

)

(14,061,068

)

Financing Activities

Common stock dividends

(5,560,535

)

(5,403,536

)

(5,322,194

)

Issuance of stock:

Dividend Reinvestment Plan optional cash net of issuance costs

268,341

347,546

266,638

Purchase of treasury stock

(192,652

)

-

-

Change in cash overdrafts due to outstanding checks

(143,720

)

(46,853

)

492,331

Net borrowing (repayment) under line of credit agreements

1,184,742

(7,384,742

)

(31,200,000

)

Proceeds from issuance of long-term debt, net

-

-

29,918,850

Repayment of long-term debt

(3,665,589

)

(3,945,617

)

(3,732,901

)

Net cash used by financing activities

(8,109,413

)

(16,433,202

)

(9,577,276

)

Net (Decrease) Increase in Cash and Cash Equivalents

(1,496,740

)

650,225

1,269,941

Cash and Cash Equivalents — Beginning of Period

3,108,501

2,458,276

1,188,335

Cash and Cash Equivalents — End of Period

$

1,611,761

$

3,108,501

$

2,458,276

Supplemental Disclosure of Cash Flow Information

Cash paid for interest

$

5,280,299

$

5,648,332

$

6,255,193

Cash paid for income taxes

$

1,977,223

$

3,767,816

$

2,160,750

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

Page 39

Consolidated Balance Sheets

Assets
At December 31,		2004			2003

Property, Plant and Equipment
Natural gas distribution and transmission	$	198,306,668		$	186,661,469
Propane		38,344,983			35,577,104
Advanced information services		1,480,779			1,396,595
Water services		332,313			762,383
Other plant		9,035,840			8,796,305
Total property, plant and equipment		247,500,583			233,193,856
Plus: Construction work in progress		2,766,209			1,724,721
Less: Accumulated depreciation and amortization		(73,213,605	)		(67,046,318	)
Net property, plant and equipment		177,053,187			167,872,259

Investments		386,422			386,710


Current Assets
Cash and cash equivalents		1,611,761			3,108,501
Accounts receivable (less allowance for uncollectibles
of $610,819 and $682,002, respectively)		36,938,688			26,191,845
Accrued revenue		5,229,955			4,497,752
Propane inventory		4,654,119			3,387,535
Other inventory		1,056,530			1,096,601
Regulatory assets		2,435,284			2,211,599
Storage gas prepayments		5,085,382			4,622,601
Income taxes receivable		719,078			489,841
Prepaid expenses		1,759,643			1,696,333
Other current assets		459,908			484,468
Total current assets		59,950,348			47,787,076

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		219,964			305,213
Long-term receivables		1,209,034			1,637,998
Other regulatory assets		1,542,741			2,632,900
Other deferred charges		902,281			760,911
Total deferred charges and other assets		4,548,471			6,011,473






Total Assets	$	241,938,428		$	222,057,518





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

Page 40

Consolidated Balance Sheets

Capitalization and Liabilities
At December 31,		2004			2003

Capitalization
Stockholders' equity
Common Stock, par value $.4867 per share;
(authorized 12,000,000 shares) ⁽¹⁾	$	2,812,538		$	2,754,748
Additional paid-in capital		36,854,717			34,176,361
Retained earnings		39,015,087			36,008,246
Accumulated other comprehensive income		(527,246	)		0
Deferred compensation obligation		816,044			913,689
Treasury stock, at cost		(1,008,696	)		(913,689	)
Total stockholders' equity		77,962,444			72,939,355

Long-term debt, net of current maturities		66,189,454			69,415,545
Total capitalization		144,151,898			142,354,900

Current Liabilities
Current portion of long-term debt		2,909,091			3,665,091
Short-term borrowing		4,700,000			3,515,258
Accounts payable		33,502,526			21,997,413
Customer deposits and refunds		2,415,721			2,214,961
Accrued interest		601,095			652,367
Dividends payable		1,617,245			1,556,631
Deferred income taxes payable		571,876			119,814
Accrued compensation		2,680,370			3,266,072
Regulatory liabilities		571,111			826,988
Other accrued liabilities		1,800,541			1,723,389
Total current liabilities		51,369,576			39,537,984

Deferred Credits and Other Liabilities
Deferred income taxes payable		23,350,414			19,590,995
Deferred investment tax credits		437,909			492,725
Other regulatory liabilities		1,578,374			1,481,464
Environmental liabilities		461,656			562,194
Accrued pension costs		3,007,949			2,015,128
Accrued asset removal cost		15,024,849			13,536,209
Other liabilities		2,555,803			2,485,919
Total deferred credits and other liabilities		46,416,954			40,164,634

Commitments and Contingencies *(Notes N and O)*



Total Capitalization and Liabilities	$	241,938,428		$	222,057,518

⁽¹⁾ Shares issued were 5,778,976 and 5,660,594 for 2004 and 2003, respectively. Shares outstanding were 5,730,913 and 5,612,935 for 2004 and 2003, respectively. 2004 included 9,306 purchased treasury stock shares.

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

Page 41

Consolidated Statements of Stockholders' Equity

For the Years Ended December 31,

2004

2003

2002

Common Stock

Balance — beginning of year

$

2,754,748

$

2,694,935

$

2,640,060

Dividend Reinvestment Plan

20,125

24,888

24,229

Retirement Savings Plan

19,058

21,047

25,669

Conversion of debentures

9,060

9,144

2,199

Performance shares and options exercised

9,547

4,734

2,778

Balance — end of year

2,812,538

2,754,748

2,694,935

Additional Paid-in Capital

Balance — beginning of year

34,176,361

31,756,983

29,653,992

Dividend Reinvestment Plan

996,715

1,066,386

936,268

Retirement Savings Plan

946,319

899,475

985,846

Conversion of debentures

307,940

310,293

74,632

Performance shares and options exercised

427,382

143,224

106,245

Balance — end of year

36,854,717

34,176,361

31,756,983

Retained Earnings

Balance — beginning of year

36,008,246

32,898,283

35,223,313

Net income

9,428,767

9,291,876

3,721,172

Cash dividends ⁽¹⁾

(6,403,450

)

(6,181,913

)

(6,046,202

)

Loss on issuance of treasury stock

(18,476

)

-

-

Balance — end of year

39,015,087

36,008,246

32,898,283

Accumulated Other Comprehensive Income

Balance — beginning of year

-

-

-

Minimum pension liability adjustment, net of tax

(527,246

)

-

-

Balance — end of year

(527,246

)

0

0

Deferred Compensation Obligation

Balance — beginning of year

913,689

711,109

576,342

New deferrals

296,790

202,580

134,767

Payout of deferred compensation

(394,435

)

-

-

Balance — end of year

816,044

913,689

711,109

Treasury Stock, at cost

Balance — beginning of year

(913,689

)

(711,109

)

(576,342

)

New deferrals related to corporate obligation

(296,790

)

(202,580

)

(134,767

)

Purchase of treasury stock

(344,753

)

-

-

Sale and distribution of treasury stock

546,536

-

-

Balance — end of year

(1,008,696

)

(913,689

)

(711,109

)

Total Stockholders’ Equity

$

77,962,444

$

72,939,355

$

67,350,201

⁽¹⁾ Cash dividends declared per share for 2004, 2003 and 2002 were $1.12, $1.10 and $1.10, respectively.

Consolidated Statements of Comprehensive Income

Net income

$

9,428,767

$

9,291,876

$

3,721,172

Minimum pension liability adjustment, net of tax of $347,726

(527,246

)

-

-

Comprehensive Income

$

8,901,521

$

9,291,876

$

3,721,172

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

Page 42

Consolidated Statements of Income Taxes

For the Years Ended December 31,		2004			2003			2002

Current Income Tax Expense
Federal	$	990,369		$	2,732,101		$	1,624,698
State		617,848			943,993			571,540
Investment tax credit adjustments, net		(54,816	)		(54,816	)		(54,816	)
Total current income tax expense		1,553,401			3,621,278			2,141,422

Deferred Income Tax Expense ⁽¹⁾
Property, plant and equipment		4,279,752			1,855,131			3,742,415
Deferred gas costs		283,547			105,846			(1,701,273	)
Pensions and other employee benefits		(49,620	)		(203,229	)		(139,861	)
Impairment of intangibles		125,165			1,463,995			(1,785,160	)
Environmental expenditures		(150,864	)		(866,206	)		(404,659	)
Other		(399,862	)		(19,367	)		507,799
Total deferred income tax expense		4,088,118			2,336,170			219,261
Total Income Tax Expense	$	5,641,519		$	5,957,448		$	2,360,683

Reconciliation of Effective Income Tax Rates
Continuing operations
Federal income tax expense ⁽²⁾	$	5,185,257		$	5,478,056		$	4,129,150
State income taxes, net of federal benefit		736,176			737,367			582,681
Other		(220,343	)		(182,978	)		(102,279	)
Total continuing operations		5,701,090			6,032,445			4,609,552
Discontinued operations		(59,571	)		(74,997	)		(2,248,869	)
Total Income Tax Expense	$	5,641,519		$	5,957,448		$	2,360,683

Effective income tax rate		37.4	%		39.1	%		38.8	%

At December 31,		2004			2003

Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	25,736,718		$	21,186,978
Environmental costs		-			67,354
Deferred gas costs		599,945			277,438
Other		749,259			910,705
Total deferred income tax liabilities		27,085,922			22,442,475

Deferred income tax assets:
Pension and other employee benefits		2,158,424			1,500,539
Impairment of intangibles		-			125,165
Self insurance		535,755			585,524
Environmental costs		83,510			-
Other		385,944			520,438
Total deferred income tax assets		3,163,633			2,731,666
Deferred Income Taxes Per Consolidated Balance Sheet	$	23,922,289		$	19,710,809

⁽¹⁾ Includes $386,000, $113,000 and $131,000 of deferred state income taxes for the years 2004, 2003 and 2002, respectively.
⁽²⁾ Federal income taxes for all years were recorded at 34%.

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

Page 43

A. Summary of Accounting Policies

Nature of Business

Chesapeake Utilities Corporation (“Chesapeake” or “the Company”) is engaged in natural gas distribution to approximately 50,900 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas transmission subsidiary operates a 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 34,900 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”). The Company’s 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. As of January 1, 2003, Chesapeake adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” See Note B for a summary of the impact on the financial statements. Prior to the adoption of SFAS No. 143, upon retirement or disposition of utility property, the recorded cost of removal, net of salvage value, was charged to accumulated depreciation. After adoption of SFAS No. 143, the costs are being charged against accrued asset removal cost. 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. Average rates for the past three years were 3 percent for natural gas distribution and transmission, 5 percent for propane, 12 percent for advanced information services and 7 percent for general plant.

Page 44

At December 31,	2004			2003			Useful Life ⁽¹⁾
Plant in service
Mains	$	99,154,938		$	93,015,109			24-37 years
Services — utility		25,733,797			22,982,547			14-28 years
Compressor station equipment		23,766,105			22,700,233			28 years
Liquefied petroleum gas equipment		21,483,969			21,005,616			30-39 years
Meters and meter installations		13,656,918			12,634,487			Propane 10-15 years, Natural gas 17-49 years
Measuring and regulating station equipment		10,142,531			9,948,881			17-37 years
Office furniture and equipment		10,171,180			9,719,520			Non-regulated 3-10 years, Regulated 3-20 years
Transportation equipment		9,425,605			9,266,324			2-11 years
Structures and improvements		9,177,011			9,046,759			5-44 years⁽²⁾
Land and land rights		4,703,683			4,489,721			Not depreciable, except certain regulated assets
Propane bulk plants and tanks		5,024,462			4,206,094			15 - 40 years
Various		15,060,384			14,178,565			Various
Total plant in service		247,500,583			233,193,856
Plus construction work in progress		2,766,209			1,724,721
Less accumulated depreciation		(73,213,605	)		(67,046,318	)
Net property, plant and equipment	$	177,053,187		$	167,872,259


⁽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 record costs as expense (or 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, 2004 and 2003, 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 45

At December 31,		2004		2003
Regulatory Assets
Current
Underrecovered purchased gas costs	$	1,479,358	$	1,180,010
Cash-in/cash-out and gas required for operations		32,707		262,631
Conservation cost recovery		186,234		-
Flex rate asset		736,985		768,958
Total current regulatory assets		2,435,284		2,211,599

Non-Current
Income tax related amounts due from customers		711,961		728,473
Deferred regulatory and other expenses		200,746		383,857
Deferred gas supply		15,201		7
Deferred gas required for operations		141,082		581,064
Deferred post retirement benefits		194,529		222,319
Environmental regulatory assets and expenditures		279,222		717,180
Total other regulatory assets		1,542,741		2,632,900

Total Regulatory Assets	$	3,978,025	$	4,844,499

Regulatory Liabilities
Current
Self insurance — current	$	127,000	$	111,923
Overrecovered purchased gas costs		-		519,409
Shared interruptible margins		135,098		84,843
Operational flow order penalties		130,338		-
Swing transportation imbalances		178,675		110,813
Total current regulatory liabilities		571,111		826,988

Non-Current
Self insurance — long-term		1,221,101		1,138,966
Conservation cost recovery		-		1,017
Income tax related amounts due to customers		324,974		341,481
Environmental overcollections		32,299		-
Total other regulatory liabilities		1,578,374		1,481,464

Accrued asset removal cost		15,024,849		13,536,209

Total Regulatory Liabilities	$	17,174,334	$	15,844,661

Included in the regulatory assets listed above are $2.4 million of which are accruing interest. Of the remaining regulatory assets, $275,000 will be collected in approximately one to two years, $661,000 will be collected within approximately 5 years, $469,000 will be collected within approximately 10 to 15 years and $206,000 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 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 46

Other Deferred Charges

Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred, then amortized over the original lives of the respective debt issuances. State income tax loss carryforwards are reduced to the extent taxable income is available. 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, and 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 losses of $182,000 and unrealized gains of $172,000 at December 31, 2004 and 2003, 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, 2004, propane distribution had entered into a put contract to protect 1.1 million gallons of propane inventory from a drop in value below the strike price of the put. The put expired in January 2005.

Page 47

Earnings Per Share

The calculations of both basic and diluted earnings per share from continuing operations are presented in the following chart. In 2002, the impact of converting the debentures and the effect of exercising the outstanding stock options would have been anti-dilutive; therefore, they were not included in the calculations.

For the Years Ended December 31,		2004		2003		2002
Calculation of Basic Earnings Per Share from Continuing Operations:
Net income from continuing operations	$	9,549,667	$	10,079,483	$	7,535,009
Weighted average shares outstanding		5,735,405		5,610,592		5,489,424

Basic Earnings Per Share from Continuing Operations	$	1.66	$	1.80	$	1.37

Calculation of Diluted Earnings Per Share from Continuing Operations:
Reconciliation of Numerator:
Net income from continuing operations — Basic	$	9,549,667	$	10,079,483	$	7,535,009
Effect of 8.25% Convertible debentures		139,097		157,557		-
Adjusted numerator — Diluted	$	9,688,764	$	10,237,040	$	7,535,009

Reconciliation of Denominator:
Weighted shares outstanding — Basic		5,735,405		5,610,592		5,489,424
Effect of dilutive securities
Stock options		1,784		1,361		-
Warrants		7,900		5,481		1,649
8.25% Convertible debentures		162,466		184,532		-
Adjusted denominator — Diluted		5,907,555		5,801,966		5,491,073

Diluted Earnings Per Share fron Continuing Operations	$	1.64	$	1.76	$	1.37

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 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 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 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.

Page 48

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 N and O to the Consolidated Financial Statements for significant estimates). These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond the control of the Company; therefore, actual results could differ from those estimates.

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

FASB Statements and Other Authoritative Pronouncements

Reclassification of Prior Years’ Amounts

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

B. Adoption of Accounting Principles

Chesapeake adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” during 2003. The Company’s regulated operations are allowed by the regulatory bodies to recover the costs of retiring their long-lived assets through approved depreciation rates. Under the pronouncement, the Company was required to record the portion of depreciation that represents asset removal cost as a regulatory liability on its financial statements. Previously, asset removal costs were included in accumulated depreciation. Additionally, the portion of the depreciation rates approved by the regulators that represents asset removal costs are now recorded in operations expense. In the past, they were recorded in depreciation expense. These changes had no impact on the net earnings of the Company. All

Page 49

periods presented have been reclassified in order to make the statements comparable. Accrued asset removal cost was $15.0 million and $13.5 million at December 31, 2004 and 2003, respectively.

Please refer to Note G for information on the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets.”

C. 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, 2004, Chesapeake owned one piece of property that was formerly used by a water subsidiary. That property is listed for sale. 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, was recorded for 2004 and 2003, respectively, on the sale of the water operations.

Operating revenues for discontinued operations were $1.1 million, $9.8 million and $11.7 million for 2004, 2003 and 2002, respectively. Operating losses for discontinued operations were $94,000, $917,000 and $2.8 million for 2004, 2003 and 2002, respectively. The following table represents amounts for discontinued operations that are included in the balance sheets at December 31, 2004 and 2003.

Chesapeake Utilities Corporation — Discontinued Operations

Balance Sheets

Assets
At December 31,		2004			2003
Net Property, Plant and Equipment	$	183,765		$	435,591

Current Assets
Cash		4,830			1,437,821
Other current assets		62,719			504,539
Total current assets		67,549			1,942,360

Deferred Charges and Other Assets		-			220,865

Total Assets	$	251,314		$	2,598,816


Stockholders' Equity and Liabilities
Stockholders' Equity
Common stock	$	51,010		$	51,010
Additional paid-in capital		3,914,783			3,914,783
Retained deficits		(6,492,065	)		(5,271,164	)
Total stockholders' equity		(2,526,272	)		(1,305,371	)

Current Liabilities
Due to affiliated companies		2,733,072			3,558,434
Other current liabilities		44,514			345,753
Total current liabilities		2,777,586			3,904,187

Total Capitalization and Liabilities	$	251,314		$	2,598,816

Page 50

D. Segment Information

The following table presents information about the Company’s reportable segments. The table excludes discontinued operations. The identifiable assets for discontinued operations are shown in Note C to the Consolidated Financial Statements.

For the Years Ended December 31,		2004		2003			2002
Operating Revenues, Unaffiliated Customers
Natural gas distribution and transmission	$	124,073,939	$	110,071,054		$	93,497,345
Propane		41,499,687		41,029,121			29,238,061
Advanced information services		12,381,815		12,476,746			12,523,856
Other		0		(9,329	)		(2,764	)
Total operating revenues, unaffiliated customers	$	177,955,441	$	163,567,592		$	135,256,498

Intersegment Revenues ⁽¹⁾
Natural gas distribution and transmission	$	172,427	$	175,757		$	90,730
Advanced information services		45,266		100,804			239,767
Other		647,378		711,159			720,221
Total intersegment revenues	$	865,071	$	987,720		$	1,050,718

Operating Income
Natural gas distribution and transmission	$	17,091,360	$	16,653,111		$	14,973,405
Propane		2,363,884		3,875,351			1,051,888
Advanced information services		387,193		691,909			343,296
Other and eliminations		127,309		359,029			236,090
Total operating income	$	19,969,746	$	21,579,400		$	16,604,679

Depreciation and Amortization
Natural gas distribution and transmission	$	5,418,007	$	5,188,273		$	5,049,546
Propane		1,524,016		1,506,201			1,602,655
Advanced information services		138,007		190,548			208,430
Other and eliminations		177,508		204,814			228,559
Total depreciation and amortization	$	7,257,538	$	7,089,836		$	7,089,190

Capital Expenditures
Natural gas distribution and transmission	$	13,945,214	$	9,078,043		$	12,116,993
Propane		3,417,900		2,244,583			1,231,199
Advanced information services		84,185		76,924			99,290
Other		404,941		422,789			388,051
Total capital expenditures	$	17,852,240	$	11,822,339		$	13,835,533

⁽¹⁾ All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues..


At December 31,		2004		2003			2002
Identifiable Assets
Natural gas distribution and transmission	$	184,412,301	$	170,758,784		$	166,478,223
Propane		47,531,106		38,359,251			37,939,683
Advanced information services		2,387,440		2,912,733			2,680,304
Other		7,379,794		7,791,796			9,460,267
Total identifiable assets	$	241,710,641	$	219,822,564		$	216,558,477

Page 51

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.

E. 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 F to the Consolidated Financial Statements for disclosure of fair value of investments). The Company’s open forward and futures contracts at December 31, 2004 had a loss in fair value of $182,000 and at December 31, 2003 had a gain in fair value of $172,000 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, 2004, including current maturities, had an estimated fair value of $74.8 million as compared to a carrying value of $69.1 million. At December 31, 2003, the estimated fair value was approximately $80.9 million as compared to a carrying value of $73.1 million. These estimates are based on published corporate borrowing rates for debt instruments with similar terms and average maturities.

F. Investments

The investment balances at December 31, 2004 and 2003, represent a Rabbi Trust (“the trust”) associated with the acquisition of Xeron, Inc. The Company has classified the underlying investments held by the trust as trading securities, which require all gains and losses to be recorded into other income. The trust was established during the acquisition as a retention bonus for an executive of Xeron. The Company has an associated liability recorded which is adjusted, along with other expense, for the gains and losses incurred by the trust.

G. Goodwill and Other Intangible Assets

The Company adopted SFAS No. 142 in the first quarter of 2002. The Company performed a test as of January 1, 2002, for goodwill impairment using the two-step process prescribed in SFAS No. 142. The first step was a screen for potential impairment, using January 1, 2002 as the measurement date. The second step was a measurement of the amount of the goodwill determined to be impaired. The results of the tests indicated that the goodwill associated with the Company’s water business was impaired and that the amount of the impairment was $3.2 million. This was recorded as the cumulative effect of a change in accounting principle. The fair value of the water business was determined using several methods, including discounted cash flow projections and market valuations for recent purchases and sales of similar businesses. These were weighted based on their expected probability. The determination that the goodwill associated with the Company’s water business was impaired was the result of the more stringent tests required by the new pronouncement. SFAS No. 142 requires that impairment tests be performed annually. At December 31, 2002, the test indicated an additional impairment charge of $1.5 million was necessary. The unprofitable performance of the Company’s water services business was the primary cause of the impairment.

Page 52

The change in the carrying value of goodwill for the two years ended December 31, 2004, is as follows:

		Water Businesses			Propane		Total
Balance at January 1, 2003	$	195,068		$	674,451	$	869,519
Sale of discontinued operations		(195,068	)		-		(195,068	)
Balance at December 31, 2003		-			674,451		674,451
No change		-			-		-
Balance at December 31, 2004	$	0		$	674,451	$	674,451

Intangible assets subject to amortization are as follows:

		December 31, 2004				December 31, 2003
		Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	115,333	$	60,155	$	276,616	$	142,780
Acquisition costs		263,659		98,873		263,659		92,282
Total	$	378,992	$	159,028	$	540,275	$	235,062

The decrease from 2003 to 2004 in the customer list balance reflects the sale of the assets of a water services operation. Amortization of intangible assets was $15,000 and $168,000 for the years ended December 31, 2004 and 2003, respectively. The estimated annual amortization of intangibles for the next five years is: $14,000 for 2005; $14,000 for 2006; $14,000 for 2007; $14,000 for 2008, and $14,000 for 2009.

H. Stockholders’ Equity

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

For the Years Ended December 31,	2004		2003		2002

Common Stock shares issued and outstanding ⁽¹⁾
Shares issued — beginning of year balance	5,660,594		5,537,710		5,424,962
Dividend Reinvestment Plan ⁽²⁾	40,993		51,125		49,782
Sale of stock to the Company's Retirement Savings Plan	39,157		43,245		52,740
Conversion of debentures	18,616		18,788		4,518
Performance shares and options exercised	19,616		9,726		5,708
Shares issued — end of year balance ⁽³⁾	5,778,976		5,660,594		5,537,710
Treasury Stock	(48,063	)	(47,659	)	(37,353	)
Total Shares Outstanding	5,730,913		5,612,935		5,500,357

⁽¹⁾ 12,000,000 shares are authorized at a par value of $0.4867 per share.
⁽²⁾ Includes dividends reinvested and optional cash payments.
⁽³⁾ The Company had 48,063, 47,659, and 37,353 shares held in Rabbi Trusts at December 31, 2004, 2003 and 2002, respectively.

The Company had outstanding warrants for 30,000 shares of stock at an average exercise price of $18.25 per share. The warrants expire in 2008.

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I. Long-term Debt

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

At December 31,		2004		2003
Uncollateralized senior notes:
7.97% note, due February 1, 2008	$	3,000,000	$	4,000,000
6.91% note, due October 1, 2010		4,545,454		5,454,545
6.85% note, due January 1, 2012		6,000,000		7,000,000
7.83% note, due January 1, 2015		20,000,000		20,000,000
6.64% note, due October 31, 2017		30,000,000		30,000,000
Convertible debentures:
8.25% due March 1, 2014		2,644,000		2,961,000
Total Long-Term Debt	$	66,189,454	$	69,415,545

Annual maturities of consolidated long-term debt for the next five years are as follows: $2,909,091 for 2005; $4,909,091 for 2006; $7,636,364 for 2007; $7,636,364 for 2008; and $6,636,364 for 2009.

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 2004 and 2003, debentures totaling $317,000 and $320,000, 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 2004 and 2003, no debentures were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.

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 times interest earned ratio must be at least 2.5. In addition, under the terms of the Company’s Note Agreement for the 6.64 percent Senior Notes, the Company cannot, until the retirement of the Senior Note, pay any dividends after October 31, 2002 which exceed the sum of $10 million plus consolidated net income recognized after January 1, 2003. As of December 31, 2004, the amount available for future dividends under this covenant is $14.6 million. The Company’s Series I First Mortgage Sinking Fund Bonds were secured by a lien against substantially all the natural gas distribution real, personal and mixed property. The Bonds were fully repaid at December 31, 2004. The outstanding balance at December 31, 2003 was $756,000. The Company is in compliance with all of its debt covenants.

J. Short-term Borrowing

As of December 31, 2004, the Board of Directors (“Board”) had authorized the Company to borrow up to $35.0 million from various banks and trust companies under short-term lines of credit. As of December 31, 2004, 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 $4.7 million and $3.5 million at December 31, 2004 and 2003, respectively. The annual weighted average interest rates were 3.72 percent for 2004 and 2.40 percent for 2003. 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.

K. 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 $928,000, $1.1 million and $1.2 million for 2004, 2003 and 2002, respectively. Future minimum payments under the Company’s current lease agreements are

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$762,000, $363,000, $267,000, $156,000 and $114,000 for the years of 2005 through 2009, respectively; and $225,000 thereafter, totaling $1.9 million.

L. 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 2005. The measurement dates for the Pension Plan were December 31, 2004 and 2003, respectively.

The following schedule summarizes the assets of the Pension Plan, by investment type, at December 31, 2004 and 2003:

At December 31,	2004		2003
Asset Category
Equity securities	72.64	%	73.69	%
Debt securities	12.91	%	14.95	%
U.S. Treasury Bills	11.45	%	8.29	%
Money market and other	3.00	%	3.07	%
Total	100.00	%	100.00	%

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

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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, 2004 and 2003:

At December 31,		2004			2003
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,948,755		$	10,781,990
Service cost		338,352			325,366
Interest cost		690,620			684,239
Change in discount rate		573,639			772,254
Actuarial loss (gain)		220,842			(212,528	)
Amendments		883,753			-
Effect of curtailment/settlement		(2,171,289	)		-
Benefits paid		(431,609	)		(402,566	)
Benefit obligation — end of year		12,053,063			11,948,755

Change in plan assets:
Fair value of plan assets — beginning of year		11,301,548			9,438,725
Actual return on plan assets		1,227,309			2,265,389
Benefits paid		(431,609	)		(402,566	)
Fair value of plan assets — end of year		12,097,248			11,301,548

Funded status		44,185			(647,207	)
Unrecognized transition obligation		-			(35,851	)
Unrecognized prior service cost		(38,958	)		(43,657	)
Unrecognized net gain		(850,224	)		(261,665	)
Accrued pension cost		($844,997	)		($988,380	)

Assumptions:
Discount rate		5.50	%		6.00	%
Rate of compensation increase		4.00	%		4.00	%
Expected return on plan assets		7.88	%		8.50	%

The assumptions used for the discount rate of the plan was reviewed by the Company and lowered from 6 percent to 5.5 percent, reflecting a reduction in the interest rates of high quality bonds and a reduction in the expected life of the plan, due to the lump sum payment option. Additionally, the expected return on plan assets for the qualified plan was lowered from 8.5 percent to 6 percent, due to the adoption of a change in the investment policy, made on September 30, 2004, that allows for a higher level of investment in bonds and a lower level of equity investments. The average return on plan assets for the year was 7.88 percent. There was no change in the assumed pay rate increases. The accumulated benefit obligation was $12.1 million and $9.8 million at December 31, 2004 and 2003, respectively.

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Net periodic pension costs for the defined benefit Pension Plan for 2004, 2003 and 2002 include the components as shown below:

For the Years Ended December 31,		2004			2003			2002
Components of net periodic pension cost:
Service cost	$	338,352		$	325,366		$	319,230
Interest cost		690,620			684,239			672,392
Expected return on assets		(869,336	)		(784,476	)		(980,915	)
Amortization of:
Transition assets		(11,328	)		(15,104	)		(15,104	)
Prior service cost		(4,699	)		(4,699	)		(4,699	)
Actuarial gain		-			-			(115,570	)
Net periodic pension cost (benefit)	$	143,609		$	205,326			($124,666	)

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 $2.2 million and $1.3 million at December 31, 2004 and 2003, respectively. Accrued pension costs at December 31, 2004 include $875,000 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 2004, 2003 and 2002 include the components as shown below:

For the Years Ended December 31,		2004		2003		2002
Components of net periodic pension cost:
Service cost	$	105,913	$	107,877	$	90,419
Interest cost		87,568		80,039		70,510
Amortization of:
Prior service cost		2,090		2,787		2,787
Actuarial loss		21,699		18,677		14,039
Net periodic pension cost	$	217,270	$	209,380	$	177,755

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

At December 31,	2004			2003
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,406,190		$	1,189,155
Service cost		105,913			107,877
Interest cost		87,568			80,039
Actuarial loss		713,225			52,127
Amendments		60,000			-
Effect of curtailment/settlement		(184,844	)		-
Benefits paid		(25,100	)		(23,008	)
Benefit obligation — end of year		2,162,952			1,406,190

Change in plan assets:
Fair value of plan assets — beginning of year		-			-
Employer contributions		25,100			23,008
Benefits paid		(25,100	)		(23,008	)
Fair value of plan assets — end of year		-			-

Funded status		(2,162,952	)		(1,406,190	)
Unrecognized prior service cost		-			11,152
Unrecognized net loss		874,972			368,290
Accrued pension cost		($1,287,980	)		($1,026,748	)

Assumptions:
Discount rate		5.50	%		6.00	%
Rate of compensation increase		4.00	%		4.00	%

The assumptions used for the discount rate of the plan was reviewed by the Company and lowered from 6 percent to 5.5 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, 2004 and 2003, 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 2004, 2003 and 2002 include the following components:

For the Years Ended December 31,	2004		2003		2002
Components of net periodic post-retirement cost:
Service cost	$	5,354	$	5,138	$	2,739
Interest cost		86,883		85,319		68,437
Amortization of:
Transition obligation		27,859		27,859		27,859
Actuarial loss		78,900		66,271		12,109
Total post-retirement cost	$	198,996	$	184,587	$	111,144

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

At December 31,		2004			2003
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,471,664		$	1,053,950
Retirees		91,747			(24,779	)
Fully-eligible active employees		22,071			356,027
Other active		13,798			86,466
Benefit obligation — end of year	$	1,599,280		$	1,471,664

Funded status		($1,599,280	)		($1,471,664	)
Unrecognized transition obligation		50,141			78,000
Unrecognized net loss		899,228			655,585
Accrued post-retirement cost		($649,911	)		($738,079	)

Assumptions:
Discount rate		5.50	%		6.00	%

The health care inflation rate for 2004 is assumed to be 9 percent for medical and 12 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 $198,000 as of January 1, 2005, and would increase the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2005 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 $164,000 as of January 1, 2005, and would decrease the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2005 by approximately $11,000. The measurement dates were December 31, 2004 and 2003, respectively.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law on December 8, 2003. The Company’s post-retirement health benefit requires that Medicare be the primary insurance for all participants that are eligible for Medicare. Therefore, the prescription drug benefit offered by the Company’s plan is not “actuarially equivalent” to the prescription drug benefits provided under Medicare and the Company does not expect to receive subsidy payments from the government. The actuarial evaluation of the post-retirement health benefit did factor in a reduction of 20 percent for prescription costs for retirees on Medicare beginning in 2006, due to the coverage expected to be provided by Medicare.

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Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the years 2005 through 2009 and the aggregate of the next five years for each of the plans previously described.

		Defined Benefit Pension Plan ⁽¹⁾		Executive Excess Pension Plan⁽²⁾		Other Post-Retirement Benefits⁽²⁾
2005	$	620,073	$	89,204	$	128,451
2006		418,294		88,490		123,435
2007		759,686		87,782		135,317
2008		814,588		87,080		151,091
2009		377,974		86,384		154,772
Years 2010 through 2014		3,968,275		597,496		905,606

⁽¹⁾ The pension plan is funded; therefore, benefit payments are expected tobe 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. For participants still covered by the defined benefit pension plan, the Company makes a contribution matching 60 percent or 100 percent of each participant’s pre-tax contributions based on the participant’s years of service, not to exceed six percent of the participant’s eligible compensation for the plan year. These participants will be eligible for the enhanced matching described below effective January 1, 2005.

Effective January 1, 1999, the Company began offering an enhanced 401(k) plan to all new employees, as well as existing employees that elected to no longer participate in the defined benefit plan. The Company makes matching contributions on a basis of up to six percent of each employee's pre-tax compensation for the year. 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. This plan is not funded externally.

The Company’s contributions to the 401(k) plans totaled $1,497,000, $1,444,000 and $1,488,000 for the years ended December 31, 2004, 2003 and 2002, respectively. As of December 31, 2004, there are 141,992 shares reserved to fund future contributions to the Retirement Savings Plan.

M. 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

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now uses performance shares exclusively; however, stock options granted in prior years remained outstanding at December 31, 2004. Additionally, stock appreciation rights (“SARs”) were granted previously. All 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 $490,000, $726,000 and $165,000 associated with these performance shares in 2004, 2003 and 2002, 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 2004, 2003 or 2002. The weighted average exercise price of outstanding options was $20.50 for all years presented. The options outstanding at December 31, 2004, expire on December 31, 2005.

Changes in outstanding options are shown on the chart below:

	2004				2003				2002
	Number of shares			Option Price	Number of shares			Option Price	Number of shares		Option Price
Balance — beginning of year	29,490		$	20.50	41,948		$	20.50	41,948	$	20.50
Options exercised	(11,834	)	$	20.50	(12,458	)	$	20.50
Options forfeited	(119	)	$	20.50
Balance — end of year	17,537		$	20.50	29,490		$	20.50	41,948	$	20.50

Exercisable	17,537		$	20.50	29,490		$	20.50	41,948	$	20.50

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, 2004, there were 306,899 shares reserved for issuance under the terms of the Company’s Performance Incentive Plan.

N. Environmental Commitments and Contingencies

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.

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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.

At December 31, 2004, the Company had accrued $10,000 for costs associated with the Dover Gas Light site and had recorded an associated regulatory asset for the same amount. Through December 31, 2004, the Company has incurred approximately $9.7 million in costs relating to environmental testing and remedial action studies at the site. Approximately $9.7 million has been recovered through December 2004 from other parties or through 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.

The Company has adjusted the liability with respect to the Salisbury Town Gas Light site to $5,000 at December 31, 2004. 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, 2004, 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

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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 $446,000 as of December 31, 2004 for the Winter Haven site. Through December 31, 2004, the Company has incurred approximately $1.3 million of environmental costs associated with the Winter Haven site. At December 31, 2004 the Company had collected through rates $182,000 in excess of costs incurred. A regulatory asset of approximately $264,000, 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.

O. Other Commitments and Contingencies

Possible Application of Florida Gross Receipts Tax

The Company has an unregulated natural gas supply and management services operation that sells natural gas to commercial and industrial customers located in Florida. Under Florida law, the Company is required to collect and remit to the Florida Department of Revenue a gross receipts tax on its sales of natural gas when title to the gas passes to customers in Florida. Substantially all of the natural gas purchased by the customers of the Company’s unregulated operation is sold to the customers at a delivery point located outside the State of Florida. Because title passes outside Florida, the Company has not been collecting gross receipts taxes from its customers on such sales. The Company understands that the Florida Department of Revenue has questioned the failure of other companies in the natural gas marketing industry to collect the gross receipts tax under similar circumstances. Due to the current uncertainty as to application of the tax, legislation currently is pending in Florida that would specifically provide amnesty from collection of gross receipts taxes for companies whose gross receipts are derived from sales where a written sales agreement provides for transfer of title outside of Florida. However, the Company cannot predict whether the proposed legislation will pass.

The Company has not been contacted by the Florida Department of Revenue regarding this matter. The Company believes that it has acted in good faith in not collecting Florida gross receipts tax when the title passes outside the State of Florida and should not be held responsible for the collection of the tax. However, if it were to be determined that the Company was required to collect the gross receipts tax on prior sales, the Company could be held responsible to the State of Florida for the taxes not collected. In these circumstances, the Company would incur additional expenses to the extent the Company could not collect the tax from the purchasers of the gas. The amount of such expense would depend on the Company’s revenues from those sales to which the tax is deemed to apply and on the willingness or ability to pay of the Company’s customers against which recovery could be sought. At this time, the Company does not believe that it is probable that it will be held responsible for collection of the gross receipts tax on past sales where title passed outside the State of Florida.

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

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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. The corporate guarantees provide for the payment of propane purchases by the subsidiary, in the event of the subsidiary’s default. The aggregate amount guaranteed at December 31, 2004 totaled $3.8 million, with the guarantees expiring on various dates in 2005. All payables of the subsidiary 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, 2005. 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.

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P. 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
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

2003
Operating Revenue	$	63,294,950		$	31,003,302		$	23,671,955		$	45,597,385
Operating Income		12,311,179			2,861,517			152,635			6,254,069

Net Income (Loss)
From continuing operations	$	6,637,104		$	934,536			($709,793	)	$	3,217,636
From discontinued operations		(162,329	)		(387	)		(150,131	)		(474,760	)
Net Income (Loss)	$	6,474,775		$	934,149			($859,924	)	$	2,742,876

Earnings per share:
Basic
From continuing operations	$	1.19		$	0.17			($0.13	)	$	0.57
From discontinued operations		(0.03	)		-			(0.02	)		(0.08	)
Net Income (Loss)	$	1.16		$	0.17			($0.15	)	$	0.49

Diluted
From continuing operations	$	1.16		$	0.17			($0.13	)	$	0.56
From discontinued operations		(0.03	)		-			(0.02	)		(0.08	)
Net Income (Loss)	$	1.13		$	0.17			($0.15	)	$	0.48

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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, 2004. 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, 2004.

Changes in Internal Controls

During the fiscal quarter of the Company ended December 31, 2004, 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 controls over financial reporting.

Management’s Report on Internal Controls Over Financial Reporting

See Management’s Report on Internal Controls 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 January 19, 2005, discussing the Compensation Committee’s (the “Committee”) actions on November 9, 2004, including their approval of the compensation arrangements relating to the executive officers for 2005. The filing of the Current Report on Form 8-K on January 19, 2005 with the Securities and Exchange Commission was not made within the prescribed reporting timeframe and was, therefore, late.

On November 9, 2004, 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 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 depending on the extent to which pre-established performance goals are achieved during the year ended December 31, 2005. The Compensation Committee also reaffirmed the 2005 awards under the Performance Incentive Plan made 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, 2005. Under the Company’s Cash Bonus Incentive Plan, the Committee approved target cash bonus awards, measured as a percentage of base salary, and the performance targets, for each of Messrs. Schimkaitis, Barbas, McMasters, Thompson and Zola, also for 2005.

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 April 29, 2005 in connection with the Company’s Annual Meeting to be held on May 5, 2005.

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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 April 29, 2005, in connection with the Company’s Annual Meeting to be held on May 5, 2005.

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 April 29, 2005 in connection with the Company’s Annual Meeting to be held on May 5, 2005.

The following table sets forth information as of December 31, 2004, 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		17,537	(1)	$	20.500	306,899	(2)
Equity compensation plans not approved by security holders		30,000	(3)	$	18.125	0

Total		47,537		$	19.001	306,899

(1) Consists of options to purchase 17,537 shares under the 1992 Performance Incentive Plan, as amended.
(2) Includes 306,899 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 candidates. 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

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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 April 29, 2005, in connection with the Company’s Annual Meeting to be held on May 5, 2005.

Part IV

Item 15. Exhibits, Financial Statement Schedules

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

1. Financial Statements:

o	Auditors’ Report dated March 16, 2005 of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm

o	Consolidated Statements of Income for each of the three years ended December 31, 2004, 2003 and 2002

o	Consolidated Balance Sheets at December 31, 2004 and December 31, 2003

o	Consolidated Statements of Cash Flows for each of the three years ended December 31, 2004, 2003 and 2002

o	Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2004, 2003 and 2002

o	Consolidated Statements of Income Taxes for each of the three years ended December 31, 2004, 2003 and 2002

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:

Earnings press release dated November 5, 2004 (Items 2.02 and 9.01)

(c) Exhibits:

Exhibit 3(a) Amended Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590.

Exhibit 3(b) Amended Bylaws of Chesapeake Utilities Corporation, effective February 24, 2005, is filed herewith.

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.

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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.

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 10(a) Executive Employment Agreement dated March 26, 2002, by and between Chesapeake Utilities Corporation and John R. Schimkaitis is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

*Exhibit 10(b) Form of Executive Employment Agreement dated March 26, 2003, by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, William C. Boyles and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-11590.

*Exhibit 10(c) Form of Executive Employment Agreement dated August 1, 2002, by and between Sharp Energy, Inc. and S. Robert Zola, is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-11590.

*Exhibit 10(d) Executive Employment Agreement dated January 1, 2003, by and between Chesapeake Utilities Corporation and Ralph J. Adkins is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-11590.

*Exhibit 10(e) Form of Performance Share Agreement dated January 1, 2003, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Michael P. McMasters, Stephen C. Thompson and William C. Boyles is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-11590.

*Exhibit 10(f) Form of Performance Share Agreement dated January 1, 2003, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-11590.

*Exhibit 10(g) Form of Performance Share Agreement dated December 4, 2003, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis and Michael P. McMasters, is incorporated herein by reference to Exhibit 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-11590.

*Exhibit 10(h) 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 filed herewith.

*Exhibit 10(i) Executive Employment Agreement dated August 4, 2003, by and between Chesapeake Utilities Corporation and Paul Barbas is filed herewith.

*Exhibit 10(j) Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 2005, is filed herewith.

*Exhibit 10(k) Chesapeake Utilities Corporation Performance Incentive Plan dated January 1, 1992, is incorporated herein by reference to the Company’s Proxy Statement dated April 20, 1992, in connection with the Company’s Annual Meeting held on May 19, 1992, File No. 001-11590.

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*Exhibit 10(l) Amendments to Chesapeake Utilities Corporation Performance Incentive Plan are incorporated herein by reference to the Company’s Proxy Statement dated April 1, 1998, in connection with the Company’s Annual Meeting held on May 19, 1998, File No. 001-11590.

*Exhibit 10(m) Executive Officer Compensation Arrangements, filed herewith.

*Exhibit 10(n) Directors Stock Compensation Plan adopted by Chesapeake Utilities Corporation in 1995 is incorporated herein by reference to the Company’s Proxy Statement dated April 17, 1995 in connection with the Company’s Annual Meeting held in May 1995, File No. 001-11590.

*Exhibit 10(o) Non-Employee Director Compensation Arrangements, filed herewith.

*Exhibit 10(p) United Systems, Inc. Executive Appreciation Rights Plan dated December 31, 2000 is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-11590.

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 16, 2005, filed herewith.

Exhibit 31.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 16, 2005, filed herewith.

Exhibit 32.1 Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 16, 2005, filed herewith.

Exhibit 32.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 16, 2005, filed herewith.

* Management contract or compensatory plan or agreement.

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Page 71

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 16, 2005

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: March 16, 2005	Date: March 16, 2005

/s/ Michael P. McMasters	/s/ Richard Bernstein
Michael P. McMasters, Senior Vice President	Richard Bernstein, Director
and Chief Financial Officer	Date: March 16, 2005
(Principal Financial and Accounting Officer)
Date: March 16, 2005

/s/ Thomas J. Bresnan	/s/ Walter J. Coleman
Thomas J. Bresnan, Director	Walter J. Coleman, Director
Date: March 16, 2005	Date: March 16, 2005

/s/ J. Peter Martin	/s/ Joseph E. Moore, Esq.
J. Peter Martin, Director	Joseph E. Moore, Esq., Director
Date: March 16, 2005	Date: March 16, 2005

/s/ Calvert A. Morgan, Jr.	/s/ Rudolph M. Peins, Jr.
Calvert A. Morgan, Jr., Director	Rudolph M. Peins, Jr., Director
Date: March 16, 2005	Date: March 16, 2005

/s/ Robert F. Rider
Robert F. Rider, Director
Date: March 16, 2005

Page 72

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⁾			Blanace at End Year
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
2004	$	682,002	$	505,595	$	103,020	$	(679,798	)	$	610,819
2003	$	659,628	$	660,390	$	10,093	$	(648,109	)	$	682,002
2002	$	621,516	$	677,461	$	210,735	$	(850,084	)	$	659,628

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

Page 73

Upon written request,

Chesapeake will provide, free of

charge, a copy of any exhibit to

the 2004 Annual Report on

Form 10-K not included

in this document.

Consolidated Statements of Cash Flows

For the Years Ended December 31,		2004			2003			2002

Operating Activities
Net Income	$	9,428,767		$	9,291,876		$	3,721,172
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		7,272,768			8,030,398			7,932,345
Depreciation and accretion included in other costs		2,619,069			2,467,582			2,490,799
Goodwill impairment		-			-			4,674,000
Deferred income taxes, net		4,211,481			2,397,594			263,826
Mark-to-market adjustments		353,183			457,901			(704,908	)
Employee benefits and compensation		1,729,238			2,042,093			1,200,131
Other, net		33,184			15,874			34,571
Changes in assets and liabilities:
Accounts receivable, net		(11,723,505	)		(3,565,363	)		(2,821,343	)
Inventories, storage gas and materials		(1,741,941	)		(466,411	)		311,668
Prepaid expenses and other current assets		(402,702	)		(316,425	)		(135,943	)
Other deferred charges		851,704			239,862			(347,669	)
Accounts payable, net		11,648,832			929,428			6,098,044
Income taxes receivable		118,489			25,090			182,591
Accrued interest		(51,272	)		(47,464	)		(1,058,570	)
Accrued compensation		(794,194	)		762,629			(261,114	)
Regulatory assets		(479,562	)		273,646			2,925,107
Other current liabilities		277,944			(112,356	)		262,220
Other long-term liabilities		109,533			521,870			141,358
Net cash provided by operating activities		23,461,016			22,947,824			24,908,285

Investing Activities
Property, plant and equipment expenditures, net		(17,806,950	)		(11,790,364	)		(14,705,244	)
Change in intangibles		-			-			12,426
Sale of discontinued operations		415,707			3,732,649			-
Sale of investments		178,812			-			-
Environmental recoveries, net of expenditures		364,088			2,193,318			631,750
Net cash used by investing activities		(16,848,343	)		(5,864,397	)		(14,061,068	)

Financing Activities
Common stock dividends		(5,560,535	)		(5,403,536	)		(5,322,194	)
Issuance of stock:
Dividend Reinvestment Plan optional cash net of issuance costs		268,341			347,546			266,638
Purchase of treasury stock		(192,652	)		-			-
Change in cash overdrafts due to outstanding checks		(143,720	)		(46,853	)		492,331
Net borrowing (repayment) under line of credit agreements		1,184,742			(7,384,742	)		(31,200,000	)
Proceeds from issuance of long-term debt, net		-			-			29,918,850
Repayment of long-term debt		(3,665,589	)		(3,945,617	)		(3,732,901	)
Net cash used by financing activities		(8,109,413	)		(16,433,202	)		(9,577,276	)

Net (Decrease) Increase in Cash and Cash Equivalents		(1,496,740	)		650,225			1,269,941
Cash and Cash Equivalents — Beginning of Period		3,108,501			2,458,276			1,188,335
Cash and Cash Equivalents — End of Period	$	1,611,761		$	3,108,501		$	2,458,276

Supplemental Disclosure of Cash Flow Information
Cash paid for interest	$	5,280,299		$	5,648,332		$	6,255,193
Cash paid for income taxes	$	1,977,223		$	3,767,816		$	2,160,750

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