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"). 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 our internet website. Chesapeake also adopted Corporate Governance Guidelines and Charters for the Audit Committee, Compensation Committee, and Governance Committee of the Board of Directors, each of which satisfies the regulatory requirements established by the Securities and Exchange Commission and the New York Stock Exchange. 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 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 47,600 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 304-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 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 expects to sell the remaining water dealership during 2004.
(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS Financial information by business segment is included in Item 7 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 under the name of Peninsula Energy Services Company ("PESCO").
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions serve an average of approximately 36,400 customers, of which approximately 36,200 are residential and commercial customers purchasing gas primarily for heating purposes. The remainder are industrial customers. For the year 2003, residential and commercial customers accounted for approximately 64% of the volume delivered by the divisions and 70% 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 11,100 residential and commercial and 90 industrial customers in Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee 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. The Company's Florida division, through PESCO, provides natural gas supply management services to 250 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' 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 2004; 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 852 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 2014; (f) firm storage service, providing a peak day entitlement of 635 Dt and a total capacity of 57,139 Dt, which expires in 2017; (g) firm storage service providing a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires in 2018; and (h) firm storage service providing a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires in 2019. 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 2004, provides firm transportation capacity of 868 Dt per day for the period November through March and 798 Dt per day for the period April through October.
The Delaware division's contracts with Eastern Shore include: (a) firm transportation capacity of 34,587 Dt per day for the period December through February, 33,365 Dt per day for the months of November, March and April, and 24,289 Dt per day for the period May through October, with various expiration dates ranging from 2004 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; and (e) firm storage capacity providing a peak day entitlement of 230 Dt and a total capacity of 11,700 Dt, which expires in 2004. The Delaware division's firm transportation contracts with Eastern Shore also include Eastern Shore's provision of swing transportation service. 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.
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 21,700 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.
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 2014; and (e) firm storage service providing a peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which expires in 2017. 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 2004, 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 13,678 Dt per day for the period December through February, 12,954 Dt per day for the months of November, March and April, and 8,393 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. 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.
The Maryland division currently has contracts for the purchase of firm natural gas supply with several suppliers. These supply contracts provide the availability of a maximum firm daily entitlement of 7,600 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 also has firm storage service and firm storage transportation capacity under contract with Columbia. These contracts, which expire in 2004, provide for 1,073 Mcf of firm peak day entitlement and total storage capacity of 53,738 Mcf.
Eastern Shore has retained the firm transportation capacity and firm storage services described above in order to provide swing transportation service and storage service to those customers that requested such service.
COMPETITION See discussion on competition in Item 7 under the heading "Management's Discussion and Analysis - Competition."
RATES AND REGULATION General. Chesapeake's natural gas distribution divisions are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions with respect to various aspects of the Company's business, including the rates for sales to all customers in each respective jurisdiction. All of Chesapeake's firm distribution 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 Delaware. On August 2, 2001, the Delaware division filed a general rate increase application. Interim rates, subject to refund went into effect on October 1, 2001. The Delaware Public Service Commission approved a settlement agreement for Phase I of the Rate Increase Application in April 2002. Phase I resulted in an increase in rates of approximately $380,000 per year. The Delaware Public Service Commission approved a settlement agreement among the Company, the Commission staff and the Division of the Public Advocate for Phase II of the Rate Increase Application in November 2002. Phase II resulted in an additional increase in rates of approximately $90,000 per year. Phase II also reduced the Company's sensitivity to warmer than normal weather by changing the minimum customer charge and the margin sharing arrangement for interruptible sales, off system sales and capacity release income.
Florida. On November 19, 2001, the Florida division filed a petition with the Florida Public Service Commission for approval of certain transportation cost recovery rates. The Florida Public Service Commission approved the rates on January 24, 2002, which provide for the recovery, over a two-year period, of the Florida division's actual and projected non-recurring expenses incurred in the implementation of the transportation provisions of the tariff as approved in a November 2000 rate case. The Florida division filed a petition on February 4, 2004, to dispose of a minor under-recovery of the actual expenses incurred to implement the tariff provisions.
On November 5, 2002, the Florida Public Service Commission authorized a pilot program under which the Florida division converted all remaining sales customers to transportation service and exited the gas merchant function. Implementation of Phase One of the Transitional Transportation Service ("TTS") program was completed in November 2002, and the Florida division is now actively providing the administrative services as approved by the FPSC.
On July 15, 2003, the FPSC approved a rate restructuring proposed by the Florida Division. The restructuring created three new low volume rate classes, with customer charge levels that ensure that all customers receive benefits from the TTS program
On January 4, 2004, the Florida Public Service Commission authorized the Florida division to refund the remaining balance in its over-recovered purchased gas costs account, totaling $246,000, as a final step in its exit of the gas merchant function.
Eastern Shore. On October 31, 2001, Eastern Shore filed a rate change with the FERC pursuant to the requirements of the Stipulation and Agreement dated August 1, 1997. Following settlement conferences held in May 2002, the parties reached a settlement in principle on or about May 23, 2002, to resolve all issues related to its rate case.The Offer of Settlement and the Stipulation and Agreement were finalized and filed with the FERC on August 2, 2002. The agreement provided for a reduction in rates of approximately $456,000 on an annual basis. On October 10, 2002, the FERC issued an Order approving the Offer of Settlement and the Stipulation and Agreement. Settlement rates went into effect on December 1, 2002.
On January 25, 2002, Eastern Shore filed an application before the FERC requesting authorization for the following: (1) Segment 1 - construction and operation of 1.5 miles of 16-inch mainline looping in Pennsylvania on Eastern Shore's existing right-of-way; and (2) Segment 2 - construction and operation of 1.0 mile of 16-inch mainline looping in Maryland and Delaware on, or adjacent to, Eastern Shore's existing right-of-way. The purpose of the construction was to enable Eastern Shore to provide 4,500 Dt of additional daily firm capacity on Eastern Shore's system. The expansion was completed and placed into service during the fourth quarter of 2002.
On April 1, 2003, Eastern Shore filed an application before the FERC requesting authorization for the following: (1) Phase I - upgrade of Parkesburg M & R Station; (2) Phase II - construct and operate 2.7 miles of 16-inch mainline looping in Pennsylvania; and (3) Phase III - construct and operate 3.0 miles of 16-inch mainline looping and a pressure control station in Delaware. The purpose of this construction is to enable Eastern Shore to provide additional daily firm transportation capacity of 15,100 Dt on Eastern Shore's system. Such increased capacity is to be phased in over a three-year period commencing November 1, 2003. Phase I of this expansion was completed and placed into service on November 1, 2003.
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 would not review Eastern Shore's filing, because the FERC wished to settle a related matter with another transmission company first. The other transmission company submitted a filing on December 5, 2003. The FERC has not yet acted on the filing. Eastern Shore will resubmit its transition cost recovery filing immediately upon learning of the FERC's approval.
On December 16, 2003, Eastern Shore filed with the FERC revised tariff sheets to implement revisions to its Fuel Retention and Cash Out provisions. These will be effective January 15, 2004. 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 on January 15, 2004, subject to certain revisions to clarify the tariff sheets. On January 30, 2004, Eastern Shore submitted the revised tariff sheets.
(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 Company, Inc. ("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.
The Company's propane distribution operations served approximately 34,900 propane customers on the Delmarva Peninsula and in Florida and delivered approximately 24 million retail and wholesale gallons of propane during 2003.
In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeron markets propane to large independent and petrochemical companies, resellers and southeastern retail propane companies in the United States. Additional information on Xeron's trading and wholesale marketing activities, market risks and the controls that limit and monitor the risks are included in Item 7 under the heading "Management's Discussion and Analysis - Market Risk."
The propane distribution business is affected by many factors such as seasonality, the absence of price regulation and competition among local providers. The propane wholesale marketing business is affected by wholesale price volatility and the supply and demand for propane at a wholesale level.
ADEQUACY OF RESOURCES The Company's propane distribution operations purchase propane primarily from suppliers, including major domestic oil companies and independent producers of gas liquids and oil. Supplies of propane from these and other sources are readily available for purchase by the Company. Supply contracts generally include minimum (not subject to take-or-pay premiums) and maximum purchase provisions.
The Company's propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to 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 buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is a Delaware affiliated investment company.
Chesapeake conducted its water conditioning and treatment and bottled water services business through separate subsidiaries. The assets of all of the water businesses except for Sharp Water of Florida, Inc were sold in 2003 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 is included in Item 7 under the heading "Management Discussion and Analysis - Liquidity and Capital Resources."
(IV) EMPLOYEES As of December 31, 2003, Chesapeake had 452 employees, including 197 in natural gas, 140 in propane, 71 in advanced information services and 13 in water services. The remaining 31 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 56) Mr. Schimkaitis has served as the Chief Executive Officer of Chesapeake since 1999, and as President since 1997. Mr. Schimkaitis has been employed by Chesapeake since 1984. His positions with the Company prior to 1997 included Executive Vice President and Chief Operating Officer, Senior Vice President and Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer and Assistant Secretary of Chesapeake. He has been a director since 1996.
Michael P. McMasters (age 45) Mr. McMasters has served as Vice President and Chief Financial Officer of Chesapeake since 1996. Mr. McMasters resumed his employment with Chesapeake in 1994. He previously served as Treasurer, Vice President of Eastern Shore, Director of Accounting and Rates and Controller. Prior to rejoining Chesapeake, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company.
Stephen C. Thompson (age 43) Mr. Thompson has served as Vice President of the Natural Gas Operations as well as Vice President of Chesapeake Utilities Corporation since 1997. Mr. Thompson has been employed by Chesapeake since 1983. His positions with the Company prior to 1997 included President, Vice President, Director of Gas Supply and Marketing, Superintendent of Eastern Shore and Regional Manager for the Florida Distribution Operations.
William C. Boyles (age 46) Mr. Boyles has served as Vice President of Chesapeake since 1997 and as Corporate Secretary of Chesapeake since 1998. Mr. Boyles has been employed by Chesapeake since 1988. He previously served as Director of Administrative Services, Director of Accounting and Finance, Treasurer, Assistant Treasurer and Treasury Department Manager. 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 has served as President of Sharp Energy since he began his employment with Chesapeake in 2002. Prior to joining Chesapeake, he was employed as a Northeast Regional Manager for Synergy Gas, now Cornerstone MLP in Pennsylvania.
ITEM 2.
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, Lecanto and Stuart, Florida; Chincoteague and Belle Haven, Virginia; Easton, and Salisbury, Maryland; 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 754 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas and 547 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. Portions of the properties constituting Chesapeake's distribution system are encumbered pursuant to Chesapeake's First Mortgage Bonds.
(C) NATURAL GAS TRANSMISSION Eastern Shore owns and operates approximately 304 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 2.2 million gallons at 40 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 that is currently being rented to another party. The Company intends to sell the facility during 2004.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS (F) 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.
(G) ENVIRONMENTAL The Company has participated in the investigation, assessment and remediation of three former gas manufacturing plant sites located in different jurisdictions. The Company has accrued liabilities for each of 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 a fourth site in Cambridge, Maryland.
DOVER GAS LIGHT SITE On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency ("EPA") regarding the Dover Gas Light site. This concluded the remedial action obligation that Chesapeake had related to this site. The Dover Gas Light Site is a former manufactured gas plant site located in Dover, Delaware. In May 2001, the Company, General Public Utilities Corporation, Inc. (now FirstEnergy Corporation), the State of Delaware, the United States Environmental Protection Agency ("USEPA") and the United States Department of Justice ("DOJ") signed a settlement term sheet to settle complaints brought by the Company and the United States in 1996 and 1997, respectively, with respect to the Dover Site. In October 2002, the final Consent Decrees were signed and delivered to the DOJ. The Consent Decrees were lodged simultaneously with the United States District Court for the District of Delaware and a notice soliciting public comment for a 30-day period was published in the Federal Register. The public comment period ended April 30, 2003 with no public comments. The DOJ filed an Unopposed Motion for Entry of Consent Decrees on June 26, 2003.
By Order dated July 18, 2003, the U.S. District Court for the District of Delaware entered final judgment approving and entering the Consent Decrees resolving this litigation. The entry of the Consent Decrees triggered the parties' obligations to make the payments required by the settlement agreement within thirty days. Chesapeake received from other parties, net settlement payments of $1.15 million. These proceeds will be passed on to the Company's firm customers, in accordance with the environmental rate rider. Under the Consent Decrees, Chesapeake received a release from liability and covenant not to sue from the EPA and the State of Delaware. This 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 related to the former manufactured gas plant is not sufficiently protective. These contingencies are standard, and are required by the United States in all liability settlements.
At December 31, 2003, 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, 2003, the Company has incurred approximately $9.6 million in costs relating to environmental testing and remedial action studies at the site. Approximately $9.4 million has been recovered through December 2003 from other parties or through rates.
SALISBURY TOWN GAS LIGHT SITE In cooperation with the MDE, the Company completed an assessment of the Salisbury manufactured gas plant site, which determined that there was localized ground-water contamination. During 1996, the Company completed construction and began Air Sparging and Soil-Vapor Extraction 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 air-sparging/soil-vapor extraction 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, a letter was submitted to the MDE requesting No Further Action ("NFA"). In December 2002, the MDE recommended that the Company submit work plans to MDE and place deed restrictions on the property as conditions prior to receiving an NFA. Once these items are completed, it is expected that MDE will issue an NFA. The Company has completed the MDE recommended work plans and has executed the deed restrictions. During the third quarter of 2003 the Company submitted a revised request for the NFA. The MDE has not yet responded to the request.
The Company has adjusted the liability with respect to the Salisbury Town Gas Light site to $8,000 at December 31, 2003. 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, 2003, 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 and has established a regulatory asset for those costs.
WINTER HAVEN COAL GAS SITE Chesapeake has been working with the Florida Department of Environmental Protection ("FDEP") in assessing a coal gas site in Winter Haven, Florida. In May 1996, the Company filed an Air Sparging and Soil Vapor Extraction Pilot Study Work Plan for the Winter Haven site with the FDEP. The Work Plan described the Company's proposal to undertake an Air Sparging and Soil Vapor Extraction ("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 Company has accrued a liability of $544,000 as of December 31, 2003 for the Florida site. Through December 31, 2003, the Company has incurred approximately $1.3 million of environmental costs associated with the Florida site. At December 31, 2003 the Company had collected through rates $179,000 in excess of costs incurred. A regulatory asset of approximately $335,000, representing the uncollected portion of the estimated clean-up costs, has also been recorded.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS (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 2003 and 2002 were as follows:
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, 2003, the amount available for future dividends under this covenant is $11.6 million.
At December 31, 2003, there were approximately 2,069 shareholders of record of the Common Stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
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.
LIQUIDITY AND CAPITAL RESOURCES Chesapeake's capital requirements reflect the capital-intensive nature of its business and are principally attributable to the construction program 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 2003, net cash provided by operating activities was $22.0 million, cash used by investing activities was $5.9 million and cash used by financing activities was $15.5 million. Cash provided by operating activities declined by $2.4 million from 2002 to 2003, as higher income in 2003 was more than offset by changes in working capital items. Cash provided by operating activities increased by $8.9 million from 2001 to 2002, as increases in current liabilities and non-cash charges related to goodwill impairment more than offset a decline in income.
The Company completed a private placement of $30.0 million of long-term debt on October 31, 2002. The debt has a fixed interest rate of 6.64 percent and is due October 31, 2017. The funds were used to repay short-term borrowing.
As of December 31, 2003, 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, 2003, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $65.0 million, for short-term cash needs to meet seasonal working capital requirements and temporarily to 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. Prior to the issuance of the $30.0 million long-term debt on October 31, 2002, the Board had authorized the Company to borrow up to $55.0 million of short-term debt. The outstanding balances of short-term borrowing at December 31, 2003 and 2002 were $3.5 million and $10.9 million, respectively. In 2003 and 2002, Chesapeake used funds provided by operations to fund net investing and financing activities.
During 2003, 2002 and 2001, net cash used for investing activities totaled approximately $5.9, $14.1 and $29.2 million, respectively. Cash used by investing activities was down in 2003 compared to 2002, due to the combination of reduced capital expenditures and cash provided by the sales of the water businesses and recoveries of environmental costs. 2003 additions to property, plant and equipment 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). The property, plant and equipment expenditures for 2002 were primarily for natural gas distribution ($8.1 million) and natural gas transmission ($4.0 million). In both 2003 and 2002, natural gas distribution utilized funds to improve facilities and expand facilities to serve new customers. Natural gas transmission spending related primarily to expanding its system. Capital expenditures in 2001 were high primarily as a result of Eastern Shore Natural Gas expenditures, totaling $16.0 million, related to a system expansion. Natural gas distribution also spent approximately $7.2 million in 2001 for expansion of facilities to serve new customers and for improvements of facilities. The increase in intangibles shown on the cash flow statement was related to acquisitions of water companies.
Chesapeake has budgeted $20.9 million for capital expenditures during 2004. This amount includes $15.8 million for natural gas distribution and transmission, $4.1 million for propane distribution and marketing, $285,000 for advanced information services and $614,000 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 general plant, computer software and hardware. Financing for the 2004 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 $170,000 in 2004 and $250,000 in 2005 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, 2003, common equity represented 51.2 percent of total capitalization, compared to 47.8 percent in 2002. Including short-term borrowing and the current portion of long-term debt, the equity component of the Company's capitalization would have been 48.8 percent and 43.3 percent, respectively. Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company's regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as to the Company's investors.
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.
In May 2001, Chesapeake issued a note payable of $300,000 at 8.5 percent, due April 6, 2006, in conjunction with a real estate purchase. This note was repaid in full on January 6, 2003.
Chesapeake issued common stock in connection with its Automatic Dividend Reinvestment and Stock Purchase Plan in the amounts of 51,125 shares in 2003, 49,782 shares in 2002 and 43,101 shares in 2001. Chesapeake also issued shares of common stock totaling 43,245, 52,740 and 54,921 in 2003, 2002 and 2001, respectively, for matching contributions for the Retirement Savings Plan.
Chesapeake repaid approximately $4.3 million and $3.8 million of long-term debt in 2003 and 2002, respectively.
CONTRACTUAL OBLIGATIONS We have the following contractual obligations and other commercial commitments as of December 31, 2003:
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 guarantees at December 31, 2003, totaled $4.5 million and expire on various dates in 2004.
The Company has issued a letter of credit to its main insurance company for $694,000, which expires June 1, 2004.
RESULTS OF OPERATIONS Net income from continuing operations for 2003 was $10.1 million compared to restated net income of $7.5 million for 2002 and $7.3 million for 2001. Net income for 2003 was $9.3 million or $1.66 per share compared to restated net income of $3.7 million and $6.7 million in 2002 and 2001, respectively, and restated earnings per share of $0.68 and $1.25 in 2002 and 2001, respectively. During 2003, Chesapeake decided to exit the water services business and, at December 31, 2003, had sold the assets of six of seven dealerships. The results of water services have been reclassified to discontinued operations. Discontinued operations experienced losses of $0.14, $0.34 and $0.12 per share for 2003, 2002 and 2001, respectively. Chesapeake adopted Statement of Financial Accounting Standards 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.
The Company has restated its 2002 and 2001 financial statements in order to reflect the results of its Delaware and Maryland natural gas divisions on the "accrual" rather than the "as billed" revenue recognition method. This change had an insignificant effect on the Company's annual results for the last three years. Under the "as billed" method, revenues from customer sales are not recognized until the meter is read and the amount of gas actually used is billed. Under the "accrual" method, at the end of each period, the amount of gas used is estimated and is recognized as revenue. The Company's Florida division has historically used the "accrual" method in accordance with Florida Public Service Commission ("PSC") requirements. The Delaware and Maryland divisions have historically used the "as billed" method to recognize revenues consistent with the rate-setting processes in those states. In order to consistently apply the "accrual" method, the Company met separately with the staffs of the Delaware and Maryland Public Service Commissions to determine the regulatory impact of the change. Having determined that there is little to no impact, the Company has conformed the revenue recognition method used in its Delaware and Maryland divisions to the method used by its Florida division. In order to provide comparable information, the Company has restated its 2002 and 2001 financial statements to reflect the "accrual" revenue recognition method. As a result of the restatement, retained earnings of the Company as of January 1, 2001 has increased by $697,000 compared to previously reported amounts. The change had no impact on basic earnings per share. There is no impact on fully diluted earnings per share in 2002 and a $0.01 decrease in 2001. See Note A to the Consolidated Financial Statements for further information on this change.
Improvement in Chesapeake's overall results is primarily related to strong customer growth and colder weather, which led to increased contributions from the Company's Delmarva natural gas and propane distribution 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 Florida natural gas operations, propane wholesale marketing operation and the advanced information services segment also improved operating income compared to 2002. However, decreases in operating income for the natural gas transmission operation and the Florida propane distribution operation partially offset those improvements.
During 2002, operating income increased over 2001 levels for the natural gas and propane segments, despite temperatures in the Delmarva region that were 5 percent warmer than both the 10-year average and 2001. Those increases were partially offset by declines in the advanced information services and other segments. The advanced information services segment was adversely affected by a slowdown in the information technology services sector.
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 for advanced information services. This should not be considered an alternative to operating income or net income, which are determined in accordance with generally accepted accounting principles ("GAAP"). Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors because it provides them with valuable 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, as another criteria in making investment decisions. Chesapeake's management uses gross margin in measuring certain performance goals 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 $16.7 million for 2003 compared to restated operating income of $15.0 million for the corresponding period last year, an increase of $1.7 million.
Revenue and cost of gas increased in 2003 compared to 2002 and decreased in 2002 compared to 2001, due primarily to changes in natural gas commodity costs. 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 no impact on the Company's profitability. Revenue and cost of gas were also affected by the unbundling of services that took effect in 2001 for all nonresidential 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.
Gross margins for the Delaware and Maryland distribution divisions increased $2.7 million in 2003 over 2002. Temperatures in 2003 were 13 percent colder than 2002 (554 heating degree-days) and 7 percent colder than the 10-year average (306 heating degree-days). The Company estimates that, on an annual basis, for each heating degree-day variance from the 10-year average, gross margins change by $1,680. An increase in the average number of customers also contributed to the increase. Delaware and Maryland experienced an increase of 1,923 in the average number of residential customers, or 6.4 percent, in 2003 compared to the same period in 2002. The Company estimates that each residential customer added contributes $360 annually to gross margin and requires an additional cost of $100 for operations and maintenance expenses. Also contributing to the increased margins were rate increases in Delaware that were 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 margins.
Margins for the transmission operation increased by $219,000 in 2003 compared to 2002. An increase in interruptible transportation margins and volume added through a system expansion completed in November 2002 were partially offset by a rate reduction that was effective December 2002. The rate agreement is more fully discussed in the section below captioned "Regulatory Matters."
The natural gas margin increases were partially offset by higher operating expenses, primarily operations and maintenance expenses and other taxes that relate to the increased volumes and earnings and pension and employee costs.
The natural gas distribution and transmission segment increased operating income to $15.0 million for 2002 compared to restated operating income of $14.4 million for 2001, an increase of $568,000. Restated gross margin increased $3.5 million over the same period in 2001 due to increases in the margins for the transmission operation and the Delaware and Florida distribution operations. Transmission margins were up due to the completion of a major system expansion in November of 2001. This system expansion increased margins by approximately $2.2 million per year. Margins in Delaware and Maryland were adversely impacted by temperatures that were 4.7 percent warmer (207 heating degree-days) than 2001 and 5.2 percent (232 heating degree-days) warmer than the 10-year average. This decline was more than offset by residential customer growth of 1,838, or 6.5 percent, and a rate increase in Delaware. The margin increases were partially offset by higher operating expenses, primarily administrative and general and depreciation. The increase in depreciation reflects completion of recent capital projects that increased the transmission capacity and various expansion projects in Florida.
PROPANE The propane segment experienced an increase in operating income of $2.8 million, or 268 percent over 2002. Gross margin increased $3.1 million, with an increase of only $230,000 in operating expenses.
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 costs of propane. Commodity costs changes are generally passed on to the customer, subject to competitive market conditions. The 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 (554 heating degree-days) and 7 percent colder than the 10-year average (306 heating degree-days). The Company estimates that on an annual basis, for each heating degree-day variance from the 10-year average, margins change by $1,670. Additionally, the margin per retail gallon improved by $0.0374 in 2003 compared to 2002. The 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 margins of $102,000 in 2003; however, the margins included $192,000 related to a non-recurring service project.
The Company's propane wholesale marketing operation experienced an increase in margins of $51,000 and a decrease of $148,000 in operating expenses, leading to an improvement of $199,000 in operating income. 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. Cost savings, primarily reduced taxes on propane inventory, have also helped to improve operating income for the period.
Operating income for the propane segment increased from $913,000 in 2001 to $1.1 million in 2002. Reductions in operating expenses of $262,000 more than offset a decrease of $123,000 in gross margin. Propane revenues and costs were lower by $7.6 million and $7.5 million, respectively, due to a drop in propane commodity prices and volume decreases. Both increases and decreases in commodity costs, are generally passed on to the distribution customers subject to competitive market conditions.
Propane wholesale marketing margins declined by $1.1 million in 2002 compared to 2001 and were partially offset by a reduction of $258,000 in operating expenses. The 2001 results reflected increased opportunities due to the extreme price volatility in the propane wholesale market. The same level of price fluctuations was not experienced in 2002. Additionally, there was a decrease in the number of suitable trading partners due to a decision by some companies to exit energy trading activities and the decreased credit-worthiness of other parties. The 2002 results reflected increased margins of approximately $650,000 that resulted from a bankrupt vendor defaulting on supply contracts during the first quarter of 2002. The supply was replaced by purchasing from different vendors at a lower cost than the original contract.
The Delmarva distribution operations experienced an increase of $624,000 in gross margin in 2002. Although volumes sold were down 8 percent, higher margins per gallon and stable wholesale propane prices resulted in increased margin dollars. Volumes were negatively impacted by temperatures that were 4.7 percent warmer than 2001 (207 heating degree-days) and 5.2 percent warmer than the 10-year average (232 heating degree-days), increased competition and lower volume sales to the poultry industry. Operating expenses decreased by $249,000 resulting from cost containment efforts that began in April 2001 and remain in effect. These efforts have reduced customer accounting, sales and marketing costs. Other costs, such as delivery expenses, decreased due to the lower volumes sold. The operating income of the Florida propane operation increased by $195,000 in 2002. Margins increased $441,000, but were partially offset by an increase of $246,000 in operating expenses.
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 earned operating income of $692,000 in 2003 compared to $343,000 in 2002.
Revenues continued to decline in 2003; however, at a rate that was less than 2002. The revenue decline was more than offset by reduced operating costs, primarily payroll and benefits. A non-recurring sale of software contributed $302,000 to operating income in 2003.
During 2002, this segment was adversely affected by the nation's economic slowdown as discretionary consulting projects were postponed or cancelled. Lower revenues in 2002 were partially offset by reductions in the cost of sales and in operating expenses, principally sales and marketing.
OTHER OPERATIONS AND ELIMINATIONS The other operations segment consists of subsidiaries that own real estate leased to other Chesapeake subsidiaries. Eliminations are entries required to eliminate activities between business segments from the consolidated results.
DISCONTINUED OPERATIONS In 2003, Chesapeake decided to exit the water services business. Six of seven water dealerships were sold during 2003. A net gain of $12,000, after-tax, was recorded in 2003 for the sale of the assets. The Company expects to dispose of the remaining operation of during 2004. Accordingly, the assets were recorded at their fair value. 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. Losses from discontinued operations were $800,000, $1.9 million and $649,000 for 2003, 2002 and 2001, respectively. The 2002 loss included a non-cash impairment charge of $973,000 (after-tax) related to goodwill.
INCOME TAXES Operating income taxes increased in 2003 compared to 2002, due to increased income. The effective federal income tax rate for both years was 34 percent. Operating income taxes were lower in 2002 compared to 2001, due to the decrease in operating income and a lowering of the effective federal income tax rate from 35 percent to 34 percent in 2002. During both 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 $238,000, $495,000 and $694,000 for the years 2003, 2002 and 2001, respectively. This includes interest income, earned primarily on regulatory assets, and gains from the sale of plant assets.
INTEREST EXPENSE In 2002, approximately $103,000 of interest expense was associated with discontinued operations and has therefore been reclassified on the income statement. 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 7.24 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 increased slightly from 2.35 percent for 2002 to 2.40 percent for 2003.
In the years 2002 and 2001, interest expense associated with discontinued operations was approximately $103,000 and $269,000, respectively. Those amounts have been reclassified to discontinued operations on the income statement. Total interest expense for 2002 decreased approximately $222,000, or 4 percent, over the same period in 2001. The decrease was due primarily to a reduction in the average interest rate for short-term borrowing from 4.43 percent on an average balance of $26.9 million in 2001 to 2.35 percent on an average balance of $29.4 million for the same period in 2002. Interest on long-term debt partially offset the short-term savings, due to an increase in the average balance outstanding from $52.4 million in 2001 to $54.6 million in 2002. However, the average long-term interest rate declined from 7.64 percent to 7.52 percent, offsetting a portion of the increase related to higher balances.
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. However, 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, in many cases, 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 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, 2003, Chesapeake had recorded regulatory assets of $3.1 million, including $661,000 for underrecovered purchased gas costs and $717,000 for environmental costs. The Company has recorded regulatory liabilities for accrued asset removal cost and self-insurance of $13.5 million and $1.3 million, respectively, at December 31, 2003. 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.
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 and 2003. 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, no goodwill remained related to the water companies. Goodwill is tested annually and when events change.
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, 2003, Chesapeake had recorded environmental regulatory assets of $717,000 and a liability for environmental costs of $562,000.
PROPANE WHOLESALE MARKETING CONTRACTS Chesapeake's propane wholesale marketing operation enters into forward and futures contracts that are considered derivatives under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." In accordance with the pronouncement, open positions are marked to market prices at the end of each reporting period and unrealized gains or losses are recorded in the Consolidated Statement of Income. 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, 2003 and 2002, these contracts had net unrealized gains of $172,000 and $630,000, respectively.
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 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 operations can negotiate rates above or below the FERC approved tariff rates.
Chesapeake's 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 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.
In 2003 Chesapeake changed the revenue recognition method for its Delaware and Maryland natural gas distribution divisions to conform to its Florida division. See Note A to the Consolidated Financial Statements for further information.
The propane 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.
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.
On August 2, 2001, the Delaware division filed a general rate increase application with the Delaware Public Service Commission ("PSC"). Interim rates, subject to refund, went into effect on October 1, 2001. The PSC approved a settlement agreement for Phase I of the Rate Increase Application in April 2002. Phase I resulted in an increase in rates of approximately $380,000 per year. Phase II of the filing was approved by the Delaware PSC in November 2002. It resulted in an additional increase in rates of approximately $90,000. Phase II also reduces the Company's sensitivity to weather by changing the minimum customer charge and the margin sharing arrangement for interruptible sales, off system sales and capacity release income.
On October 31, 2001, Eastern Shore filed a rate change with the FERC pursuant to the requirements of the Stipulation and Agreement dated August 1, 1997. Following settlement conferences held in May 2002, the parties reached a settlement in principle on or about May 23, 2002, to resolve all issues related to its rate case.
The Offer of Settlement and the Stipulation and Agreement were finalized and filed with the FERC on August 2, 2002. The agreement provided for a reduction in rates of approximately $456,000 on an annual basis. On October 10, 2002, the FERC issued an Order approving the Offer of Settlement and the Stipulation and Agreement. 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 would not review Eastern Shore's filing, because the FERC wished to settle a related matter with another transmission company first. The other transmission company submitted a filing on December 5, 2003. The FERC has not yet acted on the filing. Eastern Shore will resubmit its transition cost recovery filing immediately upon learning of FERC's approval.
On December 16, 2003, Eastern Shore filed revised tariff sheets to implement revisions to its Fuel Retention and Cash Out provisions. These became effective January 15, 2004. 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 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 March 29, 2002, the Florida division filed tariff revisions with the Florida PSC to complete the unbundling process by requiring all customers, including residential, to migrate to transportation service and authorized the Florida division to exit the merchant function. Transportation services were already available to all nonresidential 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 unrecovered gas cost balances, the implementation of the operational balancing account and the level of base rates. 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 ensure that all customers receive benefits from the unbundling. On January 4, 2004, the Florida PSC authorized the refund of the remaining balance in the PGA account, totaling $246,000.
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.
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 $73.1 million at December 31, 2003, as compared to a fair value of $80.9 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 is exposed to changes in interest rates as a result of financing through its issuance of fixed-rate long-term debt. 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, 2003, the propane distribution operation had entered into contracts to hedge 2.6 million gallons of propane inventory.
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 marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL to the Company or the counter party or booking out the transaction (booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy). The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment of a net amount equal to the difference between the current market price of the futures contract and the original contract price.
The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing operation is subject to commodity price risk on its open positions to the extent that market prices for NGL deviate from fixed contract settlement amounts. Market risk associated with the trading of futures and forward contracts are monitored daily for compliance with Chesapeake's Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed by oversight officials on a daily basis. Additionally, the Risk Management Committee reviews periodic reports on market and credit risk, approves any exceptions to the Risk Management Policy (within the limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on the forward and futures contracts at December 31, 2003 and 2002 is shown in the following chart.
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 are considered "normal purchases and sales" under SFAS No. 133 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, this business has shifted from providing competitive sales service to providing transportation and contract storage services.
The Company's natural gas distribution operations located in Delaware, Maryland and Florida offer transportation services to certain industrial customers. In 2001, the Florida operation extended transportation service to commercial customers and, in 2002, 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'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 The Financial Accounting Standards Board ("FASB") adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" in June 2002, which requires that a liability for a cost associated with an exit or disposal activity be recognized when a liability is incurred. Under previous guidelines, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. This statement was effective for exit or disposal activities initiated on January 1, 2003 or thereafter and had no effect on the Company during 2003.
FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," was adopted in November 2002. The Company has adopted FIN No. 45. There was no impact on the financial statements; however, the disclosures in the Commitments and Contingencies footnote (Note O) were expanded to include additional disclosures required by the pronouncement.
In December 2003, the FASB issued FIN No. 46R, "Consolidation of Variable Interest Entities," which replaced FIN No. 46, "Consolidation of Variable Interest Entities," issued in January 2003. FIN No. 46R was issued to replace FIN No. 46 and to clarify the required accounting for interests in variable interest entities. A variable interest entity is an entity that does not have sufficient equity investment at risk, or the holders of the equity instruments lack the essential characteristics of a controlling financial interest. A variable interest entity is to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity's activities, or is entitled to receive a majority of the entity's residual returns, or both. As of December 31, 2003, the Company did not have any variable interests in a variable interest entity.
Chesapeake adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," in 2003. See Note B for additional information on the impact.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." This had no impact on the Company's financial position or results of operations. The Company continues to apply the intrinsic value method in accounting for stock-based employee compensation permitted by Accounting Principles Board Opinion No. 25 and SFAS No. 123. For each of the periods presented in the consolidated statement of income, no stock-based compensation expense was recorded as no new stock options were issued during those periods.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" by requiring that contracts with comparable characteristics be accounted for similarly. The adoption of SFAS No. 149 did not have a material impact on Chesapeake's financial position or results of operations.
On August 13, 2003, the FASB ratified the Emerging Issues Task Force ("EITF") Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not 'Held for Trading Purposes' as Defined in EITF Issue No. 02 - 3." This did not have any effect on the Company's financial position or results of operations.
On January 12, 2004, the FASB released FASB Staff Position No. FAS 106-1 "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The Company has elected to defer the accounting for the Act, as allowed under Staff Position No. 106-1. See Note L for required disclosures.
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 margins, capital expenditures, environmental remediation costs, regulatory approvals, market risks associated with the Company's propane marketing operation, competition 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 of natural gas and propane 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 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.
ITEM 7A.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
REPORT OF INDEPENDENT ACCOUNTANTS ________
To the Board of Directors and Stockholders of Chesapeake Utilities Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 64 present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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) on page 64 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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note A to the consolidated financial statements, the Company has restated its December 31, 2002 and 2001 financial statements with respect to utility unbilled revenue accounting matters.
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.
/S/PRICEWATERHOUSECOOPERS LLP - ----------------------------- PricewaterhouseCoopers LLP Philadelphia, Pennsylvania February 19, 2004
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
CONSOLIDATED STATEMENTS OF INCOME TAXES
A. SUMMARY OF ACCOUNTING POLICIES RESTATEMENT The Company has restated its 2002 and 2001 financial statements in order to reflect the results of its Delaware and Maryland natural gas divisions on the "accrual" revenue recognition method rather than the "as billed" revenue recognition method. This change had an insignificant effect on the Company's annual results for the last three years. Under the "as billed" method, revenues from customer sales are not recognized until the meter is read and the amount of gas used is billed. Whereas, under the "accrual" method, at the end of each period, the amount of gas used is estimated and is recognized as revenue. The Company's Florida division has historically used the "accrual" method in accordance with Florida Public Service Commission ("PSC") requirements. The Delaware and Maryland divisions have historically used the "as billed" method to recognize revenues consistent with the rate-setting processes in those states. In order to consistently apply the "accrual" method, the Company met separately with the staffs of the Delaware and Maryland Public Service Commissions to determine the regulatory impact of the change. Having determined that there is little to no impact, the Company has conformed the revenue recognition method used in its Delaware and Maryland divisions to the method used by its Florida division. In order to provide comparable information, the Company has restated its 2002 and 2001 financial statements to reflect the "accrual" revenue recognition method. As a result of the restatement, retained earnings of the Company as of January 1, 2001 increased by $697,000 compared to previously reported amounts. As indicated below, the change has no impact on basic earnings per share. There is no impact on fully diluted earnings per share in 2002 and a $0.01 decrease in 2001.
NATURE OF BUSINESS Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is engaged in natural gas distribution to approximately 47,600 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, Florida and Virginia, and markets propane to a number of 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 PSCs 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. 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 and advanced information services 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 Utilities adopted SFAS No. 143. 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. In 2003, the costs were 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, 14 percent for advanced information services and 8 percent for general plant.
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 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 are adjusted to market values.
ENVIRONMENTAL REGULATORY ASSETS, LIABILITIES AND EXPENDITURES Environmental regulatory assets represent amounts related to environmental liabilities for which cash expenditures have not yet been made. As expenditures are incurred, the environmental liability is reduced along with the environmental regulatory asset. These amounts awaiting ratemaking treatment are recorded to either environmental expenditures as an asset or accumulated depreciation as cost of removal. Environmental expenditures are amortized and/or recovered through a rider to base rates in accordance with the ratemaking treatment granted in each jurisdiction.
GOODWILL AND OTHER INTANGIBLE ASSETS Goodwill and other intangible assets are associated with the acquisition of non-utility companies. In accordance with Statement of Financial Accounting Standards ("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.
OTHER DEFERRED CHARGES Other deferred charges include discount, premium and issuance costs associated with long-term debt and rate case expenses. Debt costs are deferred, then amortized over the original lives of the respective debt issuances. Rate case expenses are deferred, then amortized over periods approved by the applicable regulatory authorities.
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 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, the Company's propane 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 gains of $172,000 and $630,000 at December 31, 2003 and 2002, 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 are considered "normal purchases and sales" under SFAS No. 133 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, 2003, propane distribution had entered into contracts to hedge 2.6 million gallons of propane inventory.
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 would have been anti-dilutive; therefore, it was not included in the calculation. Additionally, in both 2002 and 2001, the effect of exercising the outstanding stock options would have been anti-dilutive; therefore, it was not included in the calculations.
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 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 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.
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 would result in a charge to earnings, net of applicable income taxes, which could be material.
FASB STATEMENTS AND OTHER AUTHORITATIVE PRONOUNCEMENTS The Financial Accounting Standards Board ("FASB") adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" in June 2002, which requires that a liability for a cost associated with an exit or disposal activity be recognized when a liability is incurred. Under previous guidelines, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. This statement was effective for exit or disposal activities initiated on January 1, 2003 or thereafter and had no effect on the Company during 2003.
FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," was adopted in November 2002. The Company has adopted FIN No. 45. There was no impact on the financial statements; however, the disclosures in the Commitments and Contingencies footnote (Note O) were expanded to include additional disclosures required by the pronouncement.
In December 2003, the FASB issued FIN No. 46R, "Consolidation of Variable Interest Entities," which replaced FIN No. 46, "Consolidation of Variable Interest Entities," issued in January 2003. FIN No. 46R was issued to replace FIN No. 46 and to clarify the required accounting for interests in variable interest entities. A variable interest entity is an entity that does not have sufficient equity investment at risk, or the holders of the equity instruments lack the essential characteristics of a controlling financial interest. A variable interest entity is to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity's activities, or is entitled to receive a majority of the entity's residual returns, or both. As of December 31, 2003, the Company did not have any variable interests in a variable interest entity.
Chesapeake adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," in 2003. See Note B for additional information on the impact.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." This had no impact on the Company's financial position or results of operations. The Company continues to apply the intrinsic value method in accounting for stock-based employee compensation permitted by Accounting Principles Board Opinion No. 25 and SFAS No. 123. For each of the periods presented in the consolidated statement of income, no stock-based compensation expense was recorded as no new stock options were issued during those periods.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" by requiring that contracts with comparable characteristics be accounted for similarly. The adoption of SFAS No. 149 did not have a material impact on Chesapeake's financial position or results of operations.
On August 13, 2003, the FASB ratified the Emerging Issues Task Force ("EITF") Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not 'Held for Trading Purposes' as Defined in EITF Issue No. 02-3." This did not have any effect on the Company's financial position or results of operations.
On January 12, 2004, the FASB released FASB Staff Position No. FAS 106-1 "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The Company has elected to defer the accounting for the Act, as allowed under Staff Position No. 106-1. See Note L for required disclosures.
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 periods presented have been reclassified in order to make the statements comparable. Accrued asset removal cost was $13.5 million and $12.1 million at December 31, 2003 and 2002, respectively.
Please refer to Note G for information on the adoption of SFAS No. 142.
C. BUSINESS DISPOSITIONS, DISCONTINUED OPERATIONS AND ACQUISITIONS During 2001, Chesapeake acquired Absolute Water Care, Inc., and selected assets of Aquarius Systems, Inc., EcoWater Systems of Rochester and Intermountain Water, Inc. These companies provided water treatment, water conditioning and bottled water to customers in various geographic regions. These acquisitions were all accounted for as purchases and the Company's financial results included the results of operations beginning on the date of acquisition. Previously, Chesapeake had acquired three other water service companies.
During 2003, Chesapeake decided to exit the water services business and sold six of the operations. Chesapeake expects to dispose of the remaining operation during 2004. As of December 31, 2003, the results for all water service businesses have been reclassified to discontinued operations for all periods presented. A gain of $12,000, net of tax, was recorded in 2003 on the sale of the water operations.
Operating revenues for discontinued operations were $9.8 million, $11.7 million and $10.0 million for 2003, 2002 and 2001, respectively. Operating losses for discontinued operations were $917,000, $2.8 million and $725,000 for 2003, 2002 and 2001, respectively. The following table represents amounts for discontinued operations that are included in the balance sheets at December 31, 2003 and 2002.
D. SEGMENT INFORMATION The following table presents information about the Company's reportable segments. Results exclude discontinued operations.
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.
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, 2003 and 2002 had net unrealized gains in fair value of $172,000 and $630,000, respectively, 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, 2003, including current maturities, had an estimated fair value of $80.9 million as compared to a carrying value of $73.1 million. At December 31, 2002, the estimated fair value was approximately $88.0 million as compared to a carrying value of $77.3 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, 2003 and 2002, consisted primarily of 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 previous test for impairment of goodwill, prescribed under SFAS No. 121, looked at undiscounted cash flows. 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.
In accordance with SFAS No. 142, the Company did not record any amortization of goodwill in 2003 or 2002. In 2001, amortization of goodwill, net of associated taxes, decreased income by $154,000 ($0.03 per share).
The change in the carrying value of goodwill for the two years ended December 31, 2003, is as follows:
Intangible assets subject to amortization are as follows:
The decrease from 2002 to 2003 reflects the sale of the assets of the water businesses, including intangible assets. Amortization of intangible assets was $168,000 and $241,000 for the years ended December 31, 2003 and 2002, respectively. For the year ended December 31, 2001, amortization of intangibles, excluding goodwill, was $132,000. The estimated annual amortization of intangibles for the next five years is: $15,000 for 2004; $14,000 for 2005; $14,000 for 2006; $14,000 for 2007; and $14,000 for 2008.
H. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL 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 Company 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. The Company recognized expenses of $47,500 related to the warrants. No warrants have been exercised.
I. LONG-TERM DEBT The outstanding long-term debt, net of current maturities, is as shown below.
The Company completed the private placement of $30.0 million of long-term debt due October 31, 2017, and drew down the funds on October 31, 2002. The debt has a fixed interest rate of 6.64 percent. The funds were used to repay short-term borrowing.
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 2003 and 2002, debentures totaling $320,000 and $77,000, 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 2003 and 2002 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. The Company is in compliance with all of its debt covenants.
Portions of the Company's natural gas distribution plant assets are subject to a lien under the mortgage pursuant to which the Company's first mortgage sinking fund bonds are issued.
J. SHORT-TERM BORROWING As of December 31, 2003, the Board of Directors had authorized the Company to borrow up to $35.0 million from various banks and trust companies under short-term lines of credit. Prior to the issuance of the $30.0 million long-term debt on October 31, 2002, the Company had authorization to borrow up to $55.0 million. As of December 31, 2003, 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 $3.5 million and $10.9 million at December 31, 2003 and 2002, respectively. The annual weighted average interest rates were 2.40 percent for 2003 and 2.35 percent for 2002. 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 several operating lease arrangements for office space at various locations, equipment and pipeline facilities. Rent expense related to these leases was $1.1 million, $1.2 million and $952,000 for 2003, 2002 and 2001, respectively. Future minimum payments under the Company's current lease agreements are $871,000, $669,000, $554,000, $222,000 and $165,000 for the years of 2004 through 2008, respectively; and $199,000 thereafter, totaling $2.7 million.
L. EMPLOYEE BENEFIT PLANS RETIREMENT PLANS Prior to January 1,1999, the Company offered both a defined benefit plan and defined contribution plan to qualified employees. On January 1, 1999, the Company restructured its employee benefit plans to be competitive with those in similar industries. Chesapeake offered participants of the defined benefit plan the option to remain in the plan or receive a one-time payout and enroll in an enhanced retirement savings plan. Chesapeake closed the defined benefit plan to new participants, effective December 31, 1998.
DEFINED BENEFIT PLAN Benefits under the plan are based on each participant's years of service and highest average compensation. 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 2004.
The following schedule summarizes the assets of the pension plan, by investment type, at December 31, 2003 and 2002:
The investment policy of the Plan calls for an allocation of assets between equity and debt instruments with equity being 60 percent and debt at 40 percent, but allowing for a variance of 20 percent in either direction. Additionally, as changes are made to holdings, cash, money market funds or United States Treasury Bills may be held temporarily by the fund. Investments in the following are prohibited: options, guaranteed investment contracts, real estate, venture capital, private placements, futures, commodities, limited partnerships and Chesapeake stock. Additionally, short selling and margin transactions are prohibited.
The following schedule sets forth the funded status of the pension plan at December 31, 2003 and 2002:
The expected return on plan assets was calculated using an expected long-term rate of return of 9.5 percent for equity investments and 6.0 percent for debt investments, weighted by their respective proportionate share of the fund balance.
Net periodic pension costs for the defined benefit pension plan for 2003, 2002 and 2001 include the components as shown below:
The Company also sponsors an unfunded executive excess benefit plan. The accrued benefit obligation and accrued pension costs were $1.4 million and $1.0 million, respectively, as of December 31, 2003, and $1.2 million and $840,000, respectively, at December 31, 2002.
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.
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.
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 $1,444,000, $1,488,000 and $1,352,000 for the years ended December 31, 2003, 2002 and 2001, respectively. As of December 31, 2003, there are 181,149 shares reserved to fund future contributions to the Retirement Savings Plan.
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 2003, 2002 and 2001 include the following components:
The following schedule sets forth the status of the post-retirement health care and life insurance plan:
The health care inflation rate for 2003 is assumed to be 10 percent for medical and 14 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 $193,000 as of January 1, 2004, and would increase the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2004 by approximately $14,000. 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 $159,000 as of January 1, 2004, and would decrease the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2004 by approximately $11,000.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") was signed into law on December 8, 2003. The Company has elected to defer FASB Staff Position No. FAS 106-1 "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," due to the uncertainties that exist related to the Act and its impact, if any, on the Company's post-retirement health benefits. The measures of accumulated benefit obligation and net periodic benefit cost in the financial statements and accompanying notes do not reflect the effects, if any, of the Act on the Company's plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information.
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 now uses performance shares exclusively; however, stock options granted in prior years remained outstanding at December 31, 2003. Additionally, stock appreciation rights ("SARs") were granted previously. None remained outstanding at 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 $726,000, $165,000 and $123,000 associated with these performance shares in 2003, 2002 and 2001, 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 2003, 2002 or 2001. The weighted average exercise price of outstanding options was $20.50 for all years presented. The options outstanding at December 31, 2003, expire on December 31, 2005.
Changes in outstanding options are shown on the chart below:
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, 2003, there were 326,515 shares reserved for issuance under the terms of the Company's Performance Incentive Plan.
N. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES The Company has participated in the investigation, assessment and remediation of three former gas manufacturing plant sites located in different jurisdictions. The Company has accrued liabilities for 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 a fourth site in Cambridge, Maryland.
DOVER GAS LIGHT SITE On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency ("EPA") regarding the Dover Gas Light site. This concluded the remedial action obligation that Chesapeake had related to this site. The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. In May 2001, the Company, General Public Utilities Corporation, Inc. (now FirstEnergy Corporation), the State of Delaware, the United States Environmental Protection Agency ("USEPA") and the United States Department of Justice signed a settlement term sheet to settle complaints brought by the Company and the United States in 1996 and 1997, respectively, with respect to the Dover site. In October 2002, the final Consent Decrees were signed and delivered to the United States Department of Justice ("DOJ"). The Consent Decrees were lodged simultaneously with the United States District Court for the District of Delaware and a notice soliciting public comment for a 30-day period was published in the Federal Register. The public comment period ended April 30, 2003 with no public comments. The DOJ filed an Unopposed Motion for Entry of Consent Decrees on June 26, 2003.
By Order dated July 18, 2003, the U.S. District Court for the District of Delaware entered final judgment approving and entering the Consent Decrees resolving this litigation. The entry of the Consent Decrees triggered the parties' obligations to make the payments required by the settlement agreement within thirty days. Chesapeake received from other parties, net settlement payments of $1.15 million. These proceeds will be passed on to the Company's firm customers, in accordance with the environmental rate rider. Additionally, Chesapeake received a release from liability and covenant not to sue from the EPA and the State of Delaware. This will relieve 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 related to the former manufactured gas plant is not sufficiently protective. These contingencies are standard, and are required by the United States in all liability settlements.
At December 31, 2003, the Company had accrued $10,000 for costs associated with the Dover site and had recorded an associated regulatory asset for the same amount. Through December 31, 2003, the Company has incurred approximately $9.7 million in costs relating to environmental testing and remedial action studies at the Dover site. Approximately $9.4 million has been recovered through December 2003 from other parties or through rates.
SALISBURY TOWN GAS LIGHT SITE The Salisbury Town Gas Light site is a former manufactured gas plant site located in Salisbury, Maryland. In cooperation with the MDE, the Company performed the following remedial steps: (1) operation of an air sparging/soil vapor extraction ("AS/SVE") remedial system; (2) monitoring and recovery of product from recovery wells; and (3) monitoring of ground-water quality. In March 2002, with MDE's permission, the Company permanently decommissioned the AS/SVE system and discontinued nearly all on-site and off-site monitoring wells. In November 2002, the Company submitted a request for a No Further Action ("NFA") for the site. In December 2002, the MDE recommended that the Company submit work plans to MDE and place deed restrictions on the property as conditions prior to receiving an NFA. The Company has completed the MDE recommended work plans and has executed the deed restrictions. During the third quarter of 2003 the Company submitted a revised request for the NFA. The MDE has not yet responded to the request.
The Company has adjusted the liability with respect to the Salisbury Town Gas Light site to $8,000 at December 31, 2003. 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, 2003, 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 ratemaking treatment. The Company expects to recover the remaining costs through rates and has established a regulatory asset for those costs.
WINTER HAVEN COAL GAS SITE The Winter Haven Coal Gas site is located in Winter Haven, Florida. In May 2001, the Florida Department of Environmental Protection ("FDEP") approved a remedial action plan that includes the utilization of the AS/SVE technologies to address ground-water impacts throughout a majority of the site. The AS/SVE construction was completed in the fourth quarter of 2002 and is now fully operational. The Company is currently negotiating with FDEP on the extent of additional investigation and remediation work required to address surface soil, ground-water and sediment impacts that will not be remediated by the AS/SVE system. The current estimate of costs to complete the remediation activities at the site is approximately $544,000 (present value). Accordingly, at December 31, 2003 the Company has accrued a liability of $544,000. Through December 31, 2003 the Company has incurred approximately $1.3 million of environmental costs associated with this site. At December 31, 2003 the Company had collected through rates $179,000 in excess of costs incurred. A regulatory asset of approximately $335,000 representing the uncollected portion of the estimated cleanup costs has also been recorded.
It is management's opinion that any unrecovered current costs and any other future costs associated with any of the three sites incurred will be recoverable through future rates or sharing arrangements with other responsible parties.
In August 2002, the Company along with two other parties met with MDE to discuss alleged manufactured gas plant contamination at a property located in Cambridge, Maryland. At that meeting, one of the other parties agreed to perform a remedial investigation of the site. The possible exposure of the Company at this site cannot be determined at this time.
O. OTHER COMMITMENTS AND CONTINGENCIES NATURAL GAS AND PROPANE SUPPLY The Company's natural gas and propane distribution operations have entered into contractual commitments for gas from various suppliers. The contracts have various expiration dates. In November 2003, the Company entered into a one-year contract with an energy marketing and risk management company to manage a portion of the Company's natural gas transportation and storage capacity.
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 case of the subsidiary's default. The guarantees at December 31, 2003, totaled $4.5 million and expire on various dates in 2004.
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.
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. Due to the restatement and the reclassification of the water businesses to discontinued operations, which required changes to prior periods, the amounts presented below may not agree to amounts reported in prior Form 10-Q reports. Dollars are shown in thousands, except per share amounts.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None
ITEM 9A.
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-14(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2003. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective.
CHANGES IN INTERNAL CONTROLS During the fiscal quarter of the Company ended December 31, 2003, 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.
PART III
ITEM 10.
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," "Committees of the Board - Audit Committee" and Section 16(a) Beneficial Ownership Reporting Compliance" to be filed not later than April 29, 2004 in connection with the Company's Annual Meeting to be held on May 6, 2004.
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.
The following table sets forth information as of December 31, 2003, with respect to compensation plans of Chesapeake and its subsidiaries under which shares of Chesapeake common stock are authorized for issuance:
ITEM 11.
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, 2004, in connection with the Company's Annual Meeting to be held on May 6, 2004.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 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, 2004 in connection with the Company's Annual Meeting to be held on May 6, 2004.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None
ITEM 14.
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, 2004, in connection with the Company's Annual Meeting to be held on May 6, 2004.
PART IV
ITEM 15.
ITEM 15. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K (A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:
1. Financial Statements: o Auditors' Report dated February 19, 2004 of PricewaterhouseCoopers LLP, Independent Auditors o Consolidated Statements of Income for each of the three years ended December 31, 2003, 2002 and 2001 o Consolidated Balance Sheets at December 31, 2003 and December 31, 2002 o Consolidated Statements of Cash Flows for each of the three years ended December 31, 2003, 2002 and 2001 o Consolidated Statements of Common Stockholders' Equity for each of the three years ended December 31, 2003, 2002 and 2001 o Consolidated Statements of Income Taxes for each of the three years ended December 31, 2003, 2002 and 2001 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 4, 2003 (Items 7 and 12)
(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 November 14, 2003, are incorporated herein by reference to Exhibit 3 of the Company's Form 10-Q for the quarter ended September 30,2003, File No. 001-11590, filed November 14, 2003.
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) First Mortgage Sinking Fund Bonds dates December 15, 1989 between the Company and The Prudential Insurance Company of America, with respect to $8.2 million of 9.37% Series I Mortgage Bonds due December 15, 2004, 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 Commission upon request.
Exhibit 4(c) 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(d) 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 Commission upon request.
Exhibit 4(e) 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 Commission upon request.
Exhibit 4(f) 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 Commission upon request.
Exhibit 4(g) 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 filed herewith.
*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, filed herewith.
*Exhibit 10(c) Form of Executive Employment Agreement dated August 1, 2002, by and between Sharp Energy, Inc. and S. Robert Zola, filed herewith.
*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, 1998, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Ralph J. Adkins 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, 1997, File No. 001-11590.
*Exhibit 10(f) Form of Performance Share Agreement dated January 1, 2002, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Ralph J. Adkins, John R. Schimkaitis, 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, 2001, File No. 001-11590.
*Exhibit 10(g) 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(h) 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, filed herewith.
*Exhibit 10(i) 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, Michael P. McMasters, filed herewith.
*Exhibit 10(j) Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 1992, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-593.
*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.
*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.
*Exhibit 10(m) Form of Stock Appreciation Rights Agreement dated January 1, 2001, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Philip S. Barefoot, William C. Boyles, Thomas A. Geoffroy, James R. Schneider and William P. Schneider 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 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.
*Exhibit 10(o) 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 Accountants, filed herewith.
Exhibit 31.1 Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 15, 2004, filed herewith.
Exhibit 31.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 15, 2004, filed herewith.
Exhibit 32.1 Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 15, 2004, filed herewith.
Exhibit 32.2 Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 15, 2004, filed herewith.
* Management contract or compensatory plan or agreement.
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 15, 2004
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 John R. Schimkaitis, President, the Board and Director Chief Executive Officer and Director Date: March 9, 2004 Date: March 9, 2004
/s/ Michael P. McMasters /s/ Richard Bernstein - --------------------------- ----------------------- Michael P. McMasters, Richard Bernstein, Director Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) Date: March 9, 2004 Date: March 9, 2004
/s/ Thomas J. Bresnan /s/ Walter J. Coleman - ------------------------ ------------------------ Thomas J. Bresnan, Director Walter J. Coleman, Director Date: March 9, 2004 Date: March 9, 2004
/s/ J. Peter Martin /s/ Joseph E. Moore, Esq. - ---------------------- ----------------------------- J. Peter Martin, Director Joseph E. Moore, Esq., Director Date: March 9, 2004 Date: March 9, 2004
/s/ Calvert A. Morgan, Jr. /s/ Rudolph M. Peins, Jr. - ------------------------------ ----------------------------- Calvert A. Morgan, Jr., Director Rudolph M. Peins, Jr., Director Date: March 9, 2004 Date: March 9, 2004
/s/ Robert F. Rider - ---------------------- Robert F. Rider, Director Date: March 9, 2004
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES EXHIBIT 12 RATIO OF EARNINGS TO FIXED CHARGES
CHESAPEAKE UTILITIES CORPORATION EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT
SUBSIDIARIES STATE INCORPORATED ------------ ------------------- Aquality Company, Inc. Delaware Eastern Shore Natural Gas Company Delaware Sharp Energy, Inc. Delaware Chesapeake Service Company Delaware Xeron, Inc. Mississippi Sam Shannahan Well Company, Inc. Maryland Sharp Water, Inc. Delaware
SUBSIDIARIES OF SHARP ENERGY, INC. STATE INCORPORATED -------------------------------------- ------------------- Sharpgas, Inc. Delaware Sharp Living, Inc. Delaware Tri-County Gas Co., Incorporated Maryland
SUBSIDIARIES OF CHESAPEAKE SERVICE COMPANY STATE INCORPORATED ---------------------------------------------- ------------------- Skipjack, Inc. Delaware BravePoint, Inc. Georgia Chesapeake Investment Company Delaware Eastern Shore Real Estate, Inc. Maryland
SUBSIDIARIES OF SHARP WATER, INC. STATE INCORPORATED ------------------------------------- ------------------- Aquality Solutions of Michigan, Inc. Michigan Carroll Water Systems, Inc. Maryland Absolute Water Care, Inc. Florida Sharp Water of Florida, Inc. Delaware Sharp Water of Idaho, Inc. Delaware Sharp Water of Minnesota, Inc. Delaware
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS ________
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (Nos. 33-28391 and 33-64671) and Form S-8 (Nos. 333-01175 and 333-94159) of Chesapeake Utilities Corporation of our report dated February 19, 2004 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
/S/PRICEWATERHOUSECOOPERS LLP - ----------------------------- PricewaterhouseCoopers LLP Philadelphia, Pennsylvania March 15, 2004
EXHIBIT 31.1
CERTIFICATE PURSUANT TO RULE 13A-14(A) UNDER THE SECURITIES EXCHANGE ACT OF 1934
I, John R. Schimkaitis, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Utilities Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluations; c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 15, 2004
/s/ John R. Schimkaitis - -------------------------- John R. Schimkaitis President and Chief Executive Officer
EXHIBIT 31.2
CERTIFICATE PURSUANT TO RULE 13A-14(A) UNDER THE SECURITIES EXCHANGE ACT OF 1934
I, Michael P. McMasters, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Utilities Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluations; c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 15, 2004
/s/ Michael P. McMasters - --------------------------- Michael P. McMasters Vice President and Chief Financial Officer
EXHIBIT 32.1
CERTIFICATE OF CHIEF EXECUTIVE OFFICER
OF
CHESAPEAKE UTILITIES CORPORATION
(PURSUANT TO 18 U.S.C. SECTION 1350)
I, John R. Schimkaitis, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation ("Chesapeake") for the year ended December 31, 2003, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.
/s/ John R. Schimkaitis -------------------------- John R. Schimkaitis March 15, 2004
A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 32.2
CERTIFICATE OF CHIEF FINANCIAL OFFICER
OF
CHESAPEAKE UTILITIES CORPORATION
(PURSUANT TO 18 U.S.C. SECTION 1350)
I, Michael P. McMasters, Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation ("Chesapeake") for the year ended December 31, 2003, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.
/s/ Michael P. McMasters --------------------------- Michael P. McMasters March 15, 2004
A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
Upon written request, Chesapeake will provide, free of charge, a copy of any exhibit to the 2003 Annual Report on Form 10-K not included in this document.