SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 1997 Commission File Number 001-11590 CHESAPEAKE UTILITIES CORPORATION (Exact name of registrant as specified in its charter) State of Delaware 51-0064146 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 909 Silver Lake Boulevard, Dover, Delaware 19904 (Address of principal executive offices) (Zip Code) Registrants telephone number, including area code: 302-734-6799 Securities registered pursuant to Section 12(b) of the Act: Title of each class ----------------------------------------- Common Stock - par value per share $.4867 Name of each exchange on which registered ----------------------------------------- New York Stock Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: 8.25% Convertible Debentures Due 2014 ------------------------------------- (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [X] As of March 20, 1998, 4,543,695 shares of common stock were outstanding. The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation, based on the last trade price on March 20, 1997, as reported by the New York Stock Exchange, was approximately $67 million. DOCUMENTS INCORPORATED BY REFERENCE DOCUMENTS PART OF FORM 10-K Definitive Proxy Statement Part III dated March 30, 1998 CHESAPEAKE UTILITIES CORPORATION FORM 10-K Year Ended December 31, 1997 TABLE OF CONTENTS PART I Page ---- Item 1. Business ...................................................... 1 Item 2. Properties ................................................... 11 Item 3. Legal Proceedings ............................................ 12 Item 4. Submission of Matters to a Vote of Security Holders .......... 15 Item 10.Executive Officers of the Registrant ......................... 15 PART II Item 5. Market for Registrants Common Stock and Related Security Holder Matters ...................................... 16 Item 6. Selected Financial Data ...................................... 17 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations .......................... 18 Item 8. Financial Statements and Supplementary Data .................. 25 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure ....................... 45 PART III Item 10.Directors and Executive Officers of the Registrant ........... 45 Item 11.Executive Compensation ....................................... 45 Item 12.Security Ownership of Certain Beneficial Owners and Management ........................................ 45 Item 13.Certain Relationships and Related Transactions ............... 45 PART IV Item 14.Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K ............................. 45 Signatures ........................................................... 49 PART I Item 1. Business (a) General Development of Business Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a diversified utility company engaged in natural gas distribution and transmission, propane distribution and advanced information services. Chesapeakes three natural gas distribution divisions serve approximately 35,800 residential, commercial and industrial customers in southern Delaware, Marylands Eastern Shore and Central Florida. The Companys natural gas transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"), operates a 271-mile interstate pipeline system that transports gas from various points in Pennsylvania to the Companys Delaware and Maryland distribution divisions, as well as to other utilities and industrial customers in Delaware and on the Eastern Shore of Maryland. The Companys propane segment serves approximately 34,000 customers in southern Delaware and on the Eastern Shore of Maryland and Virginia. The advanced information services segment provides software services and products to a wide variety of customers and clients. (b) Financial Information about Industry Segments Financial information by business segment is included in Item 7 under the heading Notes to Consolidated Financial Statements. (c) Narrative Description of Business The Company is engaged in four primary business activities: natural gas transmission, natural gas distribution, propane distribution and advanced information services. In addition to the four primary groups, Chesapeake has three subsidiaries engaged in other service related businesses. (i) (a) Natural Gas Transmission Eastern Shore, the Companys wholly owned transmission subsidiary, operates an interstate natural gas transportation and provides contract storage services for affiliated and non-affiliated companies through an integrated gas pipeline extending from southeastern Pennsylvania to Delaware and the Eastern Shore of Maryland. During 1997, Eastern Shore implemented open access transportation services. Eastern Shore now provides transportation services, contract storage services as well as purchasing and selling small amounts of gas for system balancing purposes ("swing gas"). Eastern Shores rates are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). Adequacy of Resources With the implementation of open access effective November 1, 1997, Eastern Shore released, through the permanent release mechanism of its upstream service providers tariffs, various levels of firm transportation capacity and contract storage service to customers. Eastern Shore retained contracts with Transcontinental Gas Pipe Line Corporation ("Transco") for 4,916 thousand cubic feet ("Mcf") firm transportation capacity, expiring in 2005, and three firm storage services providing peak day entitlements of 7,046 Mcf. Eastern Shore also retained contracts with Columbia Gas Transportation ("Columbia") for services, including: firm transportation capacity of 869 Mcf per day, which expires in 2018; storage service providing a peak day entitlement of 1,111 Mcf and total capacity of 53,738 Mcf, expiring in 2004; and firm storage service providing peak day entitlements of 563 Mcf and a total capacity of 50,686 Mcf, which expires in 2018. Eastern Shore retained the firm transportation capacity to provide swing transportation service to a limited number of customers that requested this service. Prior to open access, Eastern Shore had firm contracts with three interstate pipelines for transportation and storage services coupled with firm contracts for natural gas supply with five suppliers providing a maximum firm daily capacity of 20,469 Mcf. Competition Under this open access environment, interstate pipeline companies have unbundled the traditional components of their service -- gas gathering, transportation and storage -- from the sale of the commodity. Pipelines that choose to be merchants of gas must form separate marketing operations independent of their pipeline operations. Hence, gas marketers have developed as a viable option for many companies because they are providing expertise in gas purchasing along with collective purchasing capabilities which, when combined, may reduce end-user cost. Additional discussion on competition is included in Item 7 under the heading "Managements Discussion and Analysis of Financial Condition and Results of Operations". Rates and Regulation General. 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 and fees Eastern Shore can charge to its transportation customers. In addition, the FERC regulates the rates Eastern Shore is charged for transportation and transmission line capacity and services provided by Transco and Columbia. Regulatory Proceedings Delaware City Compressor Station Filing. In December 1995, Eastern Shore filed an application before the FERC pursuant to Sections 7(b) and (c) of the Natural Gas Act for a certificate of public convenience and necessity authorizing Eastern Shore to: (1) construct and operate a 2,170 horsepower compressor station in Delaware City, New Castle County, Delaware on a portion of its existing pipeline system known as the "Hockessin Line", such new station to be known as the "Delaware City Compressor Station"; (2) construct and operate slightly less than one mile of 16-inch pipeline in Delaware City, New Castle County, Delaware to tie the suction side of the proposed Delaware City Compressor Station into the Hockessin Line; and (3) increase the maximum allowable operating pressure from 500 psig to 590 psig on 28.7 miles of Eastern Shores pipeline from Eastern Shores existing Bridgeville Compressor Station in Bridgeville, Sussex County, Delaware to its terminus in Salisbury, Wicomico County, Maryland. In September 1996 the FERC issued its Final Order, which: (1) authorized Eastern Shore to construct and operate the facilities requested in its application; (2) authorized Eastern Shore to roll-in the cost of the facilities into its existing rates if the revenues from the increase in services exceed the cost associated with the expansion portion of the project; (3) denied Eastern Shore the authority to increase the level of sales and storage service it provides its customers until it completes its restructuring in its open access proceeding; and (4) authorized Eastern Shore to abandon the 100 Mcf per day of firm sale service, to one of its direct sale customers. The compressor facility and associated piping were needed to stabilize capacity on Eastern Shores system as a result of steadily declining inlet pressures at the Hockessin interconnect with Transcontinental Gas Pipe Line Corporation. Construction of the facilities started during the second half of 1996 and was completed during the first quarter of 1997. Rate Case Filing. In October 1996 Eastern Shore filed for a general rate increase with the FERC. The filing proposed an increase in Eastern Shores jurisdictional rates that would generate additional annual operating revenue of approximately $1.4 million. Eastern Shore also stated in the filing that it intended to use the cost-of-service submitted in the general rate increase filing to develop rates in the pending Open Access Docket. In September 1997, the FERC approved a rate increase of $1.2 million. Open Access Filing. In December 1995, Eastern Shore filed its abbreviated application for a blanket certificate of public convenience and necessity authorizing the transportation of natural gas on behalf of others. Eastern Shore proposed to unbundle the sales and storage services it had provided. Customers who had previously received firm sales and storage services on Eastern Shore (the "Converting Customers") would receive entitlements to firm transportation service on Eastern Shores pipeline in a quantity equivalent to their existing service rights. Eastern Shore proposed to retain some of its pipeline entitlements and storage capacity for operational issues and to facilitate "no-notice" (no prior notification required to receive service) transportation service on its pipeline system. Eastern Shore would release or assign to the remaining Converting Customers the firm transportation capacity, including contract storage, it held on its upstream pipelines so that the Converting Customers would be able to become direct customers of such upstream pipelines. Converting Customers who previously received bundled sales service having no-notice characteristics would have the right to elect no-notice firm transportation service. In connection with the rate increase settlement, the issues pertaining to Eastern Shore operating as an open access pipeline were also settled in September 1997, with open access implementation occurring on November 1, 1997. (i) (b) Natural Gas Distribution Chesapeake distributes natural gas to approximately 35,800 residential, commercial and industrial customers in southern Delaware, the Salisbury and Cambridge, Maryland areas on Marylands Eastern Shore, and Central Florida. These activities are conducted through three utility divisions, one division in Delaware, another in Maryland and a third division in Florida. In 1993, the Company started natural gas supply management services in the state of Florida under the name of Peninsula Energy Services Company ("PESCO"). Delaware and Maryland. The Delaware and Maryland divisions serve approximately 29,950 customers, of which approximately 26,860 are residential and commercial customers purchasing gas primarily for heating purposes. Annually, residential and commercial customers account for approximately 69% of the volume delivered by the divisions, and 79% 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 Chesapeakes customer growth in these divisions comes from new residential construction using gas heating equipment. Florida. The Florida division distributes natural gas to approximately 8,748 residential and commercial and 84 industrial customers in Polk, Osceola and Hillsborough Counties. Currently 42 of the divisions industrial customers, which purchase and transport gas on a firm and interruptible basis, account for approximately 90% of the volume delivered by the Florida division and 60% of the divisions annual natural gas and transportation revenues. These customers are primarily engaged in the citrus and phosphate industries and electric cogeneration. The Companys Florida division also provides natural gas supply management services to compete in the open access environment. Currently, twenty-one customers receive such services, which generated gross margin of $70,000 in 1997. Adequacy of Resources General. Chesapeakes Delaware and Maryland utility divisions ("Delaware", "Maryland" or "the Divisions") have firm and interruptible contracts with four (4) interstate "open access" pipelines. The Divisions are directly interconnected with Eastern Shore and services upstream of Eastern Shore are contracted with Transco, Columbia, and Columbia Gulf Transmission Company ("Gulf"). Delaware. Delawares contracts with Transco include: (a) firm transportation capacity of 8,663 dekatherms ("Dt") per day, which expires in 2005; (b) firm transportation capacity of 311 Dt per day for December through February, expiring in 2006; and (c) firm storage service, providing a total capacity of 142,830 Dt, which expires in 1998. Delawares contracts with Columbia include: (a) firm transportation capacity of 852 Dt per day, which expires in 2004; (b) firm transportation capacity of 1,132 Dt per day, which expires in 2017; (c) firm storage service, providing a peak day entitlement of 6,193 Dt and a total capacity of 298,195 Dt, which expires in 2004; and (d) firm storage service providing a peak day entitlement of 635 Dt and a total capacity of 57,139 Dt, expring in 2017. Delawares 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. Delawares 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. Delawares contracts with Eastern Shore include: (a) firm transportation capacity of 23,494 Dt per day for the period December through February, 22,272 Dt per day for the months of November, March and April, and 13,196 Dt per day for the period May through October, with various expiration dates ranging from 2004 to 2017; (b) firm storage capacity under Eastern Shores Rate Schedule GSS 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 under Eastern Shores Rate Schedule LSS providing a peak day entitlement of 580 Dt and a total capacity of 29,000 Dt, which expires in 2013; and (d) firm storage capacity under Eastern Shores Rate Schedule LGA providing a peak day entitlement of 911 Dt and a total capacity of 5,708 Dt, which expires in 2006. Delawares firm transportation contracts with Eastern Shore also include Eastern Shores provision of swing transportation service. This service includes: (a) firm transportation capacity of 1,846 Dt per day on Transcos pipeline system, retained by Eastern Shore, in addition to Delawares Transco capacity referenced earlier and (b) an interruptible storage service under Transcos Rate Schedule ESS that supports a swing supply service provided under Transcos Rate Schedule FS. Delaware currently has contracts for the purchase of firm natural gas suppy with five (5) suppliers. These contracts provide the availability of a maximum firm daily entitlement of 10,958 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore under Delawares transportation contracts. The gas purchase contracts have various expiration dates. Maryland. Marylands 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, which expires in 1998. Marylands contracts with Columbia include: (a) firm transportation capacity of 442 Dt per day, which expires in 2004; (b) firm transportation capacity of 908 Dt per day, which expires in 2017; (c) firm storage service providing a peak day entitlement of 3,142 Dt and a total capacity of 154,756 Dt, which expires in 2004; and (d) firm storage service providing a peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which expires in 2017. Marylands 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. Marylands 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. Marylands contracts with Eastern Shore include: (a) firm transportation capacity of 13,028 Dt per day for the period December through February, 12,304 Dt per day for the months of November. March and April, and 7,743 Dt per day for the period May through October; (b) firm storage capacity under Eastern Shores Rate Schedule GSS 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 under Eastern Shores Rate Schedule LSS 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 under Eastern Shores Rate Schedule LGA providing a peak day entitlement of 569 Dt and a total capacity of 3,560 Dt, which expires in 2006. Marylands firm transportation contracts with Eastern Shore also include Eastern Shores provision of swing transportation service. This service includes: (a) firm transportation capacity of 969 Dt per day on Transcos pipeline system, retained by Eastern Shore, in addition to Marylands Transco capacity referenced earlier and (b) an interruptible storage service under Transcos Rate Schedule ESS that supports a swing supply service provided under Transcos Rate Schedule FS. Maryland currently has contracts for the purchase of firm natural gas supply with five (5) suppliers. These contracts provide the availability of a maximum firm daily entitlement of 6,243 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore under Marylands transportation contracts. The gas purchase contracts have various expiration dates. The Divisions use their firm supply sources to meet a significant percentage of their projected demand requirements. In order to meet the difference between firm supply and firm demand, Delaware and Maryland obtain gas supply on the "spot market" from various other suppliers that is transported by the upstream pipelines and delivered to the Divisions interconnects with Eastern Shore as needed. The Company believes that Delaware and Marylands available firm and "spot market" supply is ample to meet the anticipated needs of their customers. 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 20,523 Dt in May through September, 27,105 Dt in October, and 26,919 Dt in November through April under FGTs firm transportation service (FTS-1) rate schedule; (b) daily firm transportation capacity of 5,100 Dt in May through October, and 8,100 Dt in November through April under FGTs firm transportation service (FTS-2) rate schedule; and (c) daily interruptible transportation capacity of 20,000 Dt under FGTs interruptible transportation services (ITS-1) rate schedule. The firm transportation contract (FTS-1) expires on August 1, 2000 with the Company retaining a unilateral right to extend the term for an additional ten years. After the expiration of the primary or secondary term, Chesapeake has the right to first refuse to match the terms of any competing bids for the capacity. The firm transportation contract (FTS-2) expires on March 1, 2015. The interruptible transportation contract is effective until August 1, 2010 and month to month thereafter unless canceled by either party with thirty days notice. The Florida division currently receives its gas supply from various suppliers. If needed, some supply is bought on the spot market; however, the majority is bought under the terms of two firm supply contacts with Natural Gas Clearinghouse and LG&E Energy Marketing. Availability of gas supply to the Florida division is also expected to be adequate under existing arrangements. Competition Competition with Alternative Fuels. Historically, the Companys natural gas distribution divisions have successfully competed with other forms of energy such as electricity, oil and propane. The principal consideration in the competition between the Company and suppliers of other sources of energy is price and, to a lesser extent, accessibility. All of the Companys divisions have the capability of adjusting their interruptible rates to compete with alternative fuels. The divisions 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 remain depressed relative to the price of natural gas. However, oil prices as well as the prices of other fuels are subject to change at any time for a variety of reasons; therefore, there is always uncertainty in the continuing competition among natural gas and other fuels. In order to address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales side of its business to maximize sales volumes. To a lesser extent than price, availability of equipment and operational efficiency are also factors in competition among fuels, primarily in residential and commercial settings. Heating, water heating and other domestic or commercial equipment is generally designed for a particular energy source, and especially with respect to heating equipment, the cost of conversion is a disincentive for individuals and businesses to change their energy source. Competition within the Natural Gas Industry. FERC Order 636 enables all natural gas suppliers to compete for customers on an equal footing. Under this open access environment, interstate pipeline companies have unbundled the traditional components of their service - gas gathering, transportation and storage from the sale of the commodity. If they choose to be a merchant of gas, they must form a separate marketing operation independent of their pipeline operations. Hence, gas marketers have developed as a viable option for many companies because they are providing expertise in gas purchasing along with collective purchasing capabilities which, when combined, may reduce end-user cost. Also resulting from an open access environment, the distribution division can be in competition with the interstate transmission company if the distribution customer is located close to the transmission companys pipeline. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the distribution division. In certain situations the distribution divisions may adjust rates and serves for these customers to retain their business. Rates and Regulation General. Chesapeakes natural gas distribution divisions are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions with respect to various aspects of the Companys business, including the rates for sales to all of their customers in each jurisdiction. All of Chesapeakes 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. Rates on interruptible sales by the Florida division are also subject to purchased gas adjustment clauses. Management monitors the rate of return in each jurisdiction in order to ensure the timely filing of rate adjustment applications. Regulatory Proceedings Maryland. In July 1995, Chesapeakes Maryland division filed an application with the Maryland Public Service Commission ("MPSC") requesting a rate increase of $1,426,711 or 17.09%. The two largest components of the increase were attributable to environmental costs and a new customer information system, implemented in 1995. On November 30, 1995, the MPSC issued an order approving a settlement proposal of a $975,000 increase in annual base rates effective for gas provided on or after December 1, 1995. As required in the settlement of the rate case, the Company filed a cost of service study with the MPSC in June 1996. The purpose of a cost of service study was to allocate revenue among customer or rate classifications. The filing, which included proposals for restructuring sales services that more closely reflect the cost of serving commercial and industrial customers, the unbundling of gas costs from distribution system costs, revisions to sharing of interruptible margins between firm ratepayers and the Company and new services that would allow customers using more than 30,000 Ccf of gas per year to purchase gas from suppliers other than the Company. After negotiations with MPSC staff and other interested parties, a settlement was reached on most sales service issues and the Commission approved a proposed order in March 1997. The settlement includes: (1) class revenue requirements and restructured sales services which provide for separate firm commercial and industrial rate schedules for general service, medium volume, large volume and high load factor customer groups; (2) unbundling of gas costs from distribution charges; (3) a new gas cost recovery mechanism, which utilizes a projected period under which the fixed cost portion of the gas rate will be forecasted on an annual basis and the commodity cost portion of the gas rate will be estimated quarterly, based on projected market prices; and (4) interruptible margins will continue to be shared, 90% to customers and 10% to the Company, but distribution costs incurred for incremental load additions can be recovered with carrying charges utilizing 100% of the incremental margin if the payback period is within three years. At the request of MPSC staff, consideration of the new transportation services were postponed until Eastern Shores open access filing was settled with the FERC. Delaware. In April 1995, Chesapeakes Delaware division filed an application with the Delaware Public Service Commission ("DPSC") requesting a rate increase of $2,751,000 or 14% over current rates. The largest component, one-third of the total requested increase, was attributable to projected costs associated with the remediation proposed by the Environmental Protection Agency ("EPA") of the site of a former coal gas manufacturing plant operated in Dover, Delaware. The Company and the DPSC agreed to separate the environmental recovery from the rate increase so each could be addressed individually. In December 1995, the DPSC approved an order authorizing a $900,000 increase to base rates effective January 1,1996. In December 1995, the DPSC approved a recovery of environmental costs associated with the Dover Gas Light Site by means of a rider (supplement) to base rates. The DPSC approved a rider effective January 1, 1996 to recover over five years all unrecovered environmental costs through September 30, 1995 offset by the deferred tax benefit of these costs. The deferred tax benefit equals the projected cashflow savings realized by the Company in connection with a reduced income tax liability due to the possibility of accelerated deduction allowed on certain environmental costs when incurred. Each year, the rider rate will be calculated based on the amortization of expenses for previous years. The advantage of the environmental rider is that it is not necessary to file a rate case every year to recover expenses. In December 1995, Chesapeakes Delaware division filed its rate design proposal with the DPSC to initiate Phase II of this proceeding. The principal objective of the filing was to prepare the Company for an increasingly competitive environment anticipated when Eastern Shore becomes an open access pipeline. This initial filing proposed new rate schedules for commercial and industrial sales service, individual pricing for interruptible negotiated contract rates, a modified purchased gas cost recovery mechanism and a natural gas vehicle tariff. In May 1996, Delaware division filed its proposal relating to transportation and balancing services with the DPSC, which proposed that transportation of customer-owned gas be available to all commercial and industrial customers with annual consumption over 3,000 Mcf per year. In February 1997, the DPSC approved an order authorizing new service offerings and rate design for services rendered on and after March 1, 1997. The approved changes include: (1) restructured sales services which provide commercial and industrial customers with various service classifications such as general service, medium volume, large volume and high load factor services; (2) a modified purchased gas cost recovery mechanism which takes into consideration the unbundling of gas costs from distribution charges as well as charging certain firm service classifications different gas cost rates based on the service classifications load factor; (3) the implementation of a mechanism for sharing interruptible, capacity release and off-system sales margins between firm sales customers and the Company, with changing margin sharing percentages based on the level of total margin; and (4) a provision for transportation and balancing services for commercial and industrial customers with annual consumption over 30,000 Ccf per year to transport customer-owned gas on the Companys distribution system. Florida. On November 26, 1997, the Florida Division filed a request with the Florida Public Service Commission (FPSC) in Docket No. 971559-GU, for a Limited Proceeding to Restructure Rates and for Approval of Gas Transportation Agreements. The Florida Division has entered into Gas Transportation Contracts with its two largest customers which resulted in retaining these two customers on the Companys distribution system at rates lower than previously achieved. As a result of this reduction in revenue, the Company has proposed in its application to restructure rates for its remaining customers to more closely reflect the cost of service for each rate class and to recover the level of revenues previously generated by the two Contract customers. The Companys restructuring proposal is revenue neutral. Approval of this request would not result in additional revenues to the Company; however, FPSC approval would enable the Company to retain its two largest customers while providing the Company with the opportunity to achieve its FPSC authorized rate of return. FPSC Staff issued their recommendation in this docket on March 12, 1998. The Commission voted to approve the Companys restructuring proposal on March 24, 1998. A Commission Order in this docket is expected April 14, 1998. (i) (c) Propane Distribution Chesapeakes propane distribution group consists of Sharp Energy, Inc. ("Sharp Energy"), a wholly owned subsidiary of Chesapeake, its wholly owned subsidiary, Sharpgas, Inc. ("Sharpgas") and Tri-County Gas Company, Inc. ("Tri-County") a wholly owned subsidiary of Chesapeake. On March 6, 1997, Chesapeake acquired all of the outstanding shares of Tri-County a family-owned and operated propane distribution business located in Salisbury and Pocomoke, Maryland. The combined operations of the Company and Tri-County served approximately 34,000 propane customers on the Delmarva Peninsula and delivered approximately 27 million retail and wholesale gallons of propane during 1997. The propane distribution business is affected by many factors such as seasonality, the absence of price regulation and competition among local providers. 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 gaseous at normal pressures, 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 significantly affected by seasonal variations, particularly the relative severity of winter temperatures, because of its use in residential and commercial heating. Adequacy of Resources Sharp Energy and Tri-County 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 a take-or-pay premiums) and maximum purchase provisions. Sharp Energy and Tri-County use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to the Companys bulk storage facilities. From these facilities, propane is delivered in portable cylinders or by "bobtail" trucks, owned and operated by the Companies, to tanks located at the customers premises. Competition Sharp Energy and Tri-County 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 local because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with both fuel oil and electricity as an energy source. Propane competes with fuel oil based on its cleanliness and environmental advantages. Propane is also typically less expensive than both fuel oil and electricity, based on equivalent BTU value. 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 Companys propane distribution 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 Companys 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 $35,000,000 per occurrence, but there is no assurance that such insurance will be adequate. (i) (d) Advanced Information Services Chesapeakes advanced information services segment is comprised of United Systems, Inc. ("USI") and Capital Data Systems, Inc. ("CDS"), both wholly owned subsidiaries of the Company. CDS provided programming support for application software, until the first quarter of 1997, at which time it disposed of substantially all of its assets. USI is an Atlanta-based company that primarily provides support for users of PROGRESS(TM), a fourth generation computer language and Relational Database Management System. USI offers consulting, training, software development "tools" and customer software development for its client base, which includes many large domestic and international corporations. Competition The advanced information services businesses face significant competition from a number of larger competitors having substantially greater resources available to them than the Company. In addition, changes in the advanced information services businesses are occurring rapidly, which could adversely impact the markets for the Companys products and services. (i) (e) Other Subsidiaries Skipjack, Inc. ("Skipjack") and Chesapeake Investment Company ("Chesapeake Investment"), are wholly owned subsidiaries of Chesapeake Service Company. Skipjack owns and leases to affiliates, two office buildings in Dover, Delaware. Chesapeake Investment is a Delaware affiliated investment company. On March 6, 1997, in connection with the acquisition of Tri-County, the Company acquired Eastern Shore Real Estate, Inc. ("ESR"), which became a wholly owned subsidiary of Chesapeake Service Company. ESR owns and leases office buildings to affiliates and external companies. (ii) Seasonal Nature of Business Revenues from the Companys 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 "Liquidity and Capital Resources". (iv) Employees The Company has 397 employees, including 114 in natural gas distribution, nine in natural gas transmission, 131 in propane distribution and 63 in advanced information services. The remaining 80 employees are considered general and administrative and include officers of the Company and marketing, engineering, treasury, accounting, data processing, planning, human resources and other administrative personnel. The acquisition of Tri-County added 43 employees to the total number of employees of the Company. Item 2. Properties (a) General The Company owns offices and operates facilities in Pocomoke, Salisbury, Cambridge, and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; and Winter Haven, Florida, and rents office space in Dover, Delaware; Plant City, Florida; Chincoteague and Belle Haven, Virginia; Easton and Pocomoke, Maryland; Detroit, Michigan; and Atlanta, Georgia. In general, the properties of the Company are adequate for the uses for which they are employed. Capacity and utilization of the Companys facilities can vary significantly due to the seasonal nature of the natural gas and propane distribution businesses. (b) Natural Gas Distribution Chesapeake owns over 542 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas, and 469 miles of such 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. A portion of the properties constituting Chesapeakes distribution system are encumbered pursuant to Chesapeakes First Mortgage Bonds. (c) Natural Gas Transmission Eastern Shore owns approximately 271 miles of transmission lines extending from Parkesburg, Pennsylvania to Salisbury, Maryland. Eastern Shore also owns three compressor stations located in Delaware City, Delaware, Daleville, Pennsylvania and Bridgeville, Delaware. The Delaware City compressor facility and associated piping are needed to stabilize capacity on Eastern Shores system as a result of steadily declining inlet pressures at the Hockessin interconnect with Transcontinental Gas Pipe Line Corporation. The Daleville station is used to increase Columbia supply pressures to match Transco supply pressures, and to increase Eastern Shores pressures in order to serve Eastern Shores firm customers demands, including those of Chesapeakes Delaware and Maryland divisions. The Bridgeville station is being used to provide increased pressures required to meet demands on the system. (d) Propane Distribution Sharpgas and Tri-County own bulk propane storage facilities with an aggregate capacity of 1.9 million gallons at 33 plant facilities in Delaware, Maryland and Virginia, located on real estate they either own or lease. Item 3. Legal Proceedings The Company and its subsidiaries are 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 of the Company. Environmental (a) Dover Gas Light Site In 1984, the State of Delaware notified the Company that a parcel of land it purchased in 1949 from Dover Gas Light Company, a predecessor gas company, contained hazardous substances. The State also asserted that the Company is responsible for any clean-up and prospective environmental monitoring of the site. The Delaware Department of Natural Resources and Environmental Control ("DNREC") investigated the site and surroundings, finding coal tar residue and some ground-water contamination. In October 1989, the Environmental Protection Agency Region III ("EPA") listed the Dover Site on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"). At that time under CERCLA, both the State of Delaware and the Company were named as potentially responsible parties ("PRPs") for clean-up of the site. The EPA issued the site Record of Decision ("ROD") dated August 16, 1994. The remedial action selected by the EPA in the ROD addressed the ground-water contamination with a combination of hydraulic containment and natural attenuation. Remediation selected for the soil at the site was to meet stringent cleanup standards for the first two feet of soil and less stringent standards for the soil below two feet. The ROD estimated the costs of selected remediation of ground-water and soil at $2.7 million and $3.3 million, respectively. In May 1995, EPA issued an order to the Company under section 106 of CERCLA (the "Order"), which required the Company to fund or implement the ROD. The Order was also issued to General Public Utilities Corporation, Inc. ("GPU"), which both EPA and the Company believe is liable under CERCLA. Other PRPs such as the State of Delaware were not ordered to perform the ROD. EPA may seek judicial enforcement of its Order, as well as significant financial penalties for failure to comply. Although notifying EPA of objections to the Order, the Company agreed to comply. GPU informed EPA that it did not intend to comply with the Order. In March 1995, the Company commenced litigation against the State of Delaware for contribution to the remedial costs being incurred to carry out the ROD. In December of 1995, this case was dismissed without prejudice based on a settlement agreement between the parties (the "Settlement"). Under the Settlement, the State agreed to support the Companys proposal to reduce the soil remedy for the site, described below, to contribute $600,000 toward the cost of implementing the ROD and to reimburse the EPA for $400,000 in oversight costs. The Settlement is contingent upon a formal settlement agreement between EPA and the State of Delaware. Upon satisfaction of all conditions of the Settlement, the litigation will be dismissed with prejudice. In June 1996, the Company initiated litigation against GPU for contribution to the remedial costs incurred by Chesapeake in connection with complying with the ROD. At this time, management cannot predict the outcome of the litigation or the amount, if any, of proceeds to be received. In July 1996, the Company began the design phase of the ROD, on-site pre- design and investigation. A pre-design investigation report ("the report") was filed in October 1996 with the EPA. The report, which required EPA approval, provided up to date status on the site, which the EPA used to determine if the remedial design selected in the ROD was still the appropriate remedy. In the report, the Company proposed a modification to the soil clean-up remedy selected in the ROD to take into account an existing land use restriction banning future development at the site. In April of 1997, the EPA issued a fact sheet stating that the EPA was considering the proposed modification. The fact sheet included an overall cost estimate of $5.7 million for the proposed modified remedy and a new overall cost estimate of $13.2 million for the remedy selected in the ROD. On August 28, 1997, the EPA issued a Proposed Plan to modify the current clean-up plan that would involve: (1) excavation of off-site thermal treatment of the contents of the former subsurface gas holders; (2) implementation of soil vaporization extraction; (3) pavement of the parking lot; and (4) use of institutional controls that would restrict future development of the Site. The overall estimated clean-up cost of the Site under the proposed plan was $4.2 million, as compared to EPAs estimate of the current clean-up plan at $13.2 million. In January 1998, the EPA issued a revised ROD, which modified the soil remediation to conform to the proposed plan and included the estimated clean- up costs of $4.2 million. The Company is currently engaged in investigations related to additional parties who may be PRPs. Based upon these investigations, the Company will consider suit against other PRPs. The Company expects continued negotiations with PRPs in an attempt to resolve these matters. The Company adjusted its accrued liability recorded with respect to the Dover Site to $4.2 million. This amount reflects the EPAs estimate, as stated in the ROD issued in 1998 for remediation of the site according to the ROD. The recorded liability may be adjusted upward or downward as the design phase progresses and the Company obtains construction bids for performance of the work. The Company has also recorded a regulatory asset of $4.2 million, corresponding to the recorded liability. Management believes that in addition to the $600,000 expected to be contributed by the State of Delaware under the Settlement, the Company will be equitably entitled to contribution from other responsible parties for a portion of the expenses to be incurred in connection with the remedies selected in the ROD. Management also believes that the amounts not so contributed will be recoverable in the Companys rates. As of December 31, 1997, the Company has incurred approximately $5.0 million in costs relating to environmental testing and remedial action studies. In 1990, the Company entered into settlement agreements with a number of insurance companies resulting in proceeds to fund actual environmental costs incurred over a five to seven-year period. In December 1995, the Delaware Public Service Commission, authorized recovery of all unrecovered environmental cost incurred by a means of a rider (supplement) to base rates, applicable to all firm service customers. The costs would be recovered through a five-year amortization offset by the deferred tax benefit associated with those environmental costs. The deferred tax benefit equals the projected cashflow savings realized by the Company in connection with a reduced income tax liability due to the possibility of accelerated deduction allowed on certain environmental costs when incurred. Each year a new rider rate is calculated to become effective December 1. The rider rate is based on the amortization of expenditures through September of the filing years plus amortization of expenses from previous years. The advantage of the rider is that it is not necessary to file a rate case every year to recover expenses incurred. As of December 31, 1997, the unamortized balance and amount of environmental costs not included in the rider, effective January 1, 1998 was $2.1 million and $190,000, respectively. With the rider mechanism established, it is managements opinion that these costs and any future cost, net of the deferred income tax benefit, will be recoverable in rates. (b) Salisbury Town Gas Light Site In cooperation with the Maryland Department of the Environment ("MDE"), the Company has completed assessment, construction and has begun remediation of the Salisbury manufactured gas plant site. The assessment determined that there was localized contamination of ground-water. A remedial design report was submitted to MDE in November 1990 and included a proposal to monitor, pump and treat any contaminated ground-water on-site. Through negotiations with the MDE, the remedial action work plan was revised with final approval from MDE obtained in early 1995. The remediation process for ground-water was revised from pump-and-treat to Air Sparging and Soil-Vapor Extraction, resulting in a substantial reduction in overall costs. During 1996, the Company completed construction and began remediation procedures at the Salisbury site and has been reporting the remediation and monitoring results to the Maryland Department of the Environment on an ongoing basis. The cost of remediation is estimated to range from $140,000 to $190,000 per year for operating expenses. Based on these estimated costs, the Company recorded both a liability and a deferred regulatory asset of $665,000 on December 31, 1997, to cover the Companys projected remediation costs for this site. The liability payout for this site is expected to be over a five- year period. As of December 31, 1997, the Company has incurred approximately $2.4 million for remedial actions and environmental studies and has charged such costs to accumulated depreciation. In January 1990, the Company entered into settlement agreements with a number of insurance companies resulting in proceeds to fund actual environmental costs incurred over a three to five- year period beginning in 1990. The final insurance proceeds were requested and received in 1992. In December 1995, the Maryland Public Service Commission approved recovery of all environmental cost incurred through September 30, 1995 less amounts previously amortized and insurance proceeds. The amount approved for a 10-year amortization was $964,251. Of the $2.4 million in costs reported above, approximately $597,000 has not been recovered through insurance proceeds or received ratemaking treatment. It is managements opinion that these costs incurred and future costs incurred, if any, will be recoverable in rates. (c) Winter Haven Coal Gas Site In May 1996, the Company filed an Air Sparging and Soil Vapor Extraction Pilot Study Work Plan for the Winter Haven site with the Florida Department of Environmental Protection ("FDEP"). The Work Plan described the Companys proposal to undertake an Air Sparging and Soil Vapor Extraction ("AS/SVE") pilot study to evaluate at the site. After discussions with the FDEP, the Company filed a modified AS/SVE Pilot Study Work Plan, scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed recently. The Company will be awaiting FDEPs comments to the modified Work Plan. It is not possible to determine whether remedial action will be required by FDEP and, if so, the cost of such remediation. The company has spent and received ratemaking treatment of approximately $678,000 on these investigations as of September 30, 1997. The Company has been allowed by the Florida Public Service Commission to continue to accrue for future environmental costs. At September 30, 1997, the Company had $432,000 accrued. It is managements opinion that future costs, if any, will be recoverable in rates. Item 4. Submission of Matters to a Vote of Security Holders None Item 10. Executive Officers of the Registrant Information pertaining to the Executive Officers of the Company is as follows: Ralph J. Adkins (age 55) Mr. Adkins is Chairman of the Board and Chief Executive Officer of Chesapeake. He has served as Chairman of the Board and Chief Executive Officer since August 1997. Prior to holding his present position, Mr. Adkins served as President and Chief Executive Officer, President and Chief Operating Officer, Executive Vice President, Senior Vice President, Vice President and Treasurer of Chesapeake. Mr. Adkins is also Chairman and Chief Executive Officer of Chesapeake Service Company, and Chairman and Chief Executive Officer of Sharp Energy, Inc., Tri-County Gas Company, Inc., Chesapeake Service Company and Eastern Shore Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He has been a director of Chesapeake since 1989. John R. Schimkaitis (age 50) Mr. Schimkaitis is President and Chief Operating Officer. He has served as President since August 1997. He previously served as Executive Vice President, Chief Financial Officer, Senior Vice President, Treasurer and Assistant Secretary. From 1983 to 1986, Mr. Schimkaitis was Vice President of Cooper & Rutter, Inc., a consulting firm providing financial services to the utility and cable industries. He was appointed as a director of Chesapeake in February 1996. Michael P. McMasters (age 39) Mr. McMasters is Vice President, Chief Financial Officer and Treasurer of Chesapeake Utilities Corporation. He has served as Vice President, Chief Financial Officer and Treasurer since December 1996. He previously served as Vice President of Eastern Shore, Director of Accounting and Rates and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company. Stephen C. Thompson (age 37) Mr. Thompson is Vice President of the Natural Gas Operations, as well as Vice President of Chesapeake Utilities Corporation. He has served as Vice President since May 1997. He has served as President, Vice President, Manager, Director of Gas Supply and Marketing and Superintendent of Eastern Shore and Regional Manager for the Florida distribution Operations. Philip S. Barefoot (age 51) Mr. Barefoot joined Chesapeake as Division Manager of Florida Operations in July 1988. In May 1994 he was elected Vice President of Chesapeake Utilities Corporation. Prior to joining Chesapeake, he was employed by Peoples Natural Gas Company where he held the positions of Division Sales Manager, Division Manager and Vice President of Florence Operations. Jeremy D. West (age 48) Mr. West joined Chesapeake as President of Sharp Energy in June 1990. In May 1992 he was elected Vice President of Chesapeakes Propane Operations and in May 1997, he was promoted to Vice President of Strategic Planning and Acquisitions. Prior to joining Chesapeake, he was employed by Columbia Propane Corporation, a subsidiary of Columbia Gas System, as Vice President of Marketing, and later, President of Columbia Propane Corporation. He has also serviced as Regional Manager of Suburban Propane. PART II Item 5. Market for the Registrants Common Stock and Related Security Holder Matters (a) Common Stock Dividends and Price Ranges: The following table sets forth sale price and dividend information for each calendar quarter during the years December 31, 1997 and 1996: - --------------------------------------------------------------------------- Dividends Declared Quarter Ended: High Low Close Per Share - --------------------------------------------------------------------------- 1997 March 31 $18.000 $16.500 $17.375 $0.2425 June 30 17.500 16.000 17.000 0.2425 September 30 18.500 16.250 18.375 0.2425 December 31 21.750 18.375 20.500 0.2425 - --------------------------------------------------------------------------- 1996 March 31 $17.000 $14.500 $16.750 $0.2325 June 30 17.875 15.875 16.000 0.2325 September 30 17.750 15.125 17.500 0.2325 December 31 18.000 16.375 16.875 0.2325 - --------------------------------------------------------------------------- The common stock of the Company trades on the New York Stock Exchange under the symbol "CPK". (b) Approximate number of holders of common stock as of December 31, 1997: Number of Shareholders Title of Class of Record --------------------------- ---------------------- Common stock, par value $.4867 2,178 (c) Dividends: During the years ended December 31, 1997 and 1996, cash dividends paid by Chesapeake have been declared each quarter, in the amounts set forth in the table above. During 1996 and 1995, Tri-County paid dividends of $79,000 and $592,000, respectively. Indentures to the long-term debt of the Company and its subsidiaries contain a restriction that the Company cannot, until the retirement of its Series I Bonds, pay any dividends after December 31, 1988 which exceed the sum of $2,135,188 plus consolidated net income recognized on or after January 1, 1989. As of December 31, 1997, the amounts available for future dividends permitted by the Series I covenant are $14.6 million. (d) On March 6, 1997, in conjunction with the acquisition of Tri-County Gas Company, Inc., the Company issued 639,000 shares of Company stock to William P. Schneider and James R. Schneider in reliance on the private placement exemption provided by Section 4(2) of the Securities Act of 1933 and Regulation D, thereunder. Item 6. Selected Financial Data - -------------------------------------------------------------------------------------------------- (dollars in thousands except stock data) For the Years Ended December 31, 1997 1996 1995 1994 (1) 1993 (1) - -------------------------------------------------------------------------------------------------- Operating Operating revenues $122,775 $130,213 $111,796 $98,572 $85,873 Operating income $8,559 $10,110 $10,067 $7,227 $6,311 Income before cumulative effect of change in accounting principle $5,683 $7,605 $7,594 $4,460 $3,914 Cumulative effect of change in accounting principle $58 Net income $5,683 $7,605 $7,594 $4,460 $3,972 - -------------------------------------------------------------------------------------------------- Balance Sheet Gross plant $143,345 $133,001 $119,837 $110,023 $100,330 Net plant $99,517 $93,570 $84,589 $75,313 $69,794 Total assets $137,379 $136,046 $123,339 $108,271 $100,988 Long-term debt, net $38,226 $28,984 $31,619 $24,329 $25,682 Common stockholders' equity $50,336 $47,537 $42,582 $37,063 $34,878 Capital expenditures $11,381 $14,837 $12,887 $10,653 $10,064 - -------------------------------------------------------------------------------------------------- Common Stock Basic earnings per share: Income before cumulative effect of change in accounting principle $1.27 $1.72 $1.75 $1.23 $1.10 Cumulative effect of change in accounting principle $0.02 Net income $1.27 $1.72 $1.75 $1.23 $1.12 Diluted earnings per share: Income before cumulative effect of change in accounting principle $1.24 $1.67 $1.70 $1.20 $1.08 Cumulative effect of change in accounting principle $0.02 Net income $1.24 $1.67 $1.70 $1.20 $1.10 Average shares outstanding 4,472,087 4,412,137 4,336,431 3,628,056 3,551,932 Cash dividends per share $0.97 $0.93 $0.90 $0.88 $0.86 Book value per share $11.18 $10.71 $9.77 $10.15 $9.76 Common equity/Total capitalization 56.80% 62.10% 57.40% 60.37% 57.59% Return on equity 11.29% 16.00% 17.80% 12.03% 11.39% - -------------------------------------------------------------------------------------------------- Other Number of Employees 397 386 383 320 326 Number of Registered Stockholders 2,178 2,213 2,098 1,721 1,743 Heating Degree Days 4,418 4,717 4,593 4,398 4,705 Heating Degree Days (10-year average) 4,577 4,596 4,586 4,564 4,588 - -------------------------------------------------------------------------------------------------- <FN> (1) 1994 and 1993 have not been restated to include the business combination with Tri-County Gas Company, Inc. </FN> Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources The capital requirements of Chesapeake Utilities Corporation ("Chesapeake" or "the Company") reflect the capital-intensive nature of its business and are attributable principally 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 finance capital expenditures. During 1997, net cash provided by operating activities, used by investing activities and used by financing activities were $12.3 million, $12.4 million and $1.5 million, respectively. The Board of Directors has authorized the Company to borrow up to $20.0 million from various banks and trust companies. As of December 31, 1997, Chesapeake had four unsecured bank lines of credit, totaling $34.0 million, for short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. The outstanding balances of short-term borrowing at December 31, 1997 and 1996 were $7.6 million and $12.7 million, respectively. In 1997, Chesapeake used cash provided by operations and the issuance of long-term debt to fund capital expenditures and reduce short-term borrowing. During 1996, the Company used cash provided by operating activities and short-term borrowing to fund the capital expenditures and increases in working capital requirements. During 1997, 1996 and 1995, capital expenditures were approximately $12.8 million, $14.8 million and $12.9 million, respectively. Chesapeake has budgeted $15.6 million for capital expenditures during 1998. This amount includes $8.7 million and $2.7 million for natural gas and propane distribution, respectively; $3.1 million for natural gas transmission, $395,000 for advanced information services and $632,000 for general plant. The natural gas and propane distribution expenditures are for expansion and improvement of facilities in existing service territories. Natural gas transmission expenditures are for improvement and expansion of the pipeline system. The advanced information services expenditures are for computer hardware, software and related equipment. Financing for the 1998 construction program is expected to be provided from short-term borrowing and cash from operations. The construction program is subject to continuous review and modification. Actual construction expenditures may vary from the above estimates due to a number of factors including inflation, changing economic conditions, regulation, sales growth and the cost and availability of capital. Chesapeake has budgeted $2.8 million for environmental related expenditures during 1998 and expects to incur additional expenditures in future years (see Note J to the Consolidated Financial Statements), a portion of which may need to be financed through external sources. Management does not expect such financing to have a material adverse effect on the financial position or capital resources of the Company. Capital Structure As of December 31, 1997, common equity represented 56.8% of permanent capitalization compared to 62.1% in 1996 and 57.4% in 1995. 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 Companys regulated operations, helps to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The achievement of these objectives will provide benefits to customers and creditors, as well as to the Companys investors. Financing Activities In December 1997, Chesapeake finalized a private placement of $10 million of 6.85% Senior Notes due January 1, 2012. The Company used the proceeds to repay a portion of its short-term borrowing. In October 1995, the Company finalized a private placement of $10 million of 6.91% Senior Notes due in 2010. The Company used the proceeds to retire $4.1 million of the 10.85% Senior Notes of Eastern Shore Natural Gas Company, the Companys natural gas transmission subsidiary ("Eastern Shore") originally due in 2003. The remaining proceeds were used to reduce short-term borrowing. The Company issued no long-term debt in 1996. During 1997, the Company repaid approximately $3.1 million of long-term debt, compared to $823,000 and $5.4 million in 1996 and 1995, respectively. The increase in debt payments for 1997 resulted from the payoff of $2.2 million of debt assumed in the pooling of interests with Tri-County Gas Company, Inc. ("Tri-County"). On March 6, 1997, the Company acquired all of the outstanding common stock of Tri-County and associated properties. Tri-County distributes propane to both retail and wholesale customers on the peninsula. The transaction was effected through the exchange of 639,000 shares of the Companys common stock and was accounted for as a pooling of interests. Chesapeake issued 32,169, 33,926 and 38,660 shares of common stock in connection with its Automatic Dividend Reinvestment and Stock Purchase Plan during the years of 1997, 1996 and 1995, respectively. Results of Operations Net income for 1997 was $5,682,946 as compared to $7,604,915 for 1996. The decrease in net income is primarily related to temperatures in the Companys northern service territory, which were, on average, 6% warmer than in 1996. The warmer weather resulted in a reduction in volumes sold by the natural gas and propane distribution segments. The lower gas volumes contributed to the reduction in Earnings Before Interest and Taxes ("EBIT") for both distribution segments as shown in the table below. EARNINGS BEFORE INTEREST AND TAXES (in thousands): - ------------------------------------------------------------------------------------------------------- Increase/ Increase/ For the Years Ended December 31, 1997 1996 (decrease) 1996 1995 (decrease) - ------------------------------------------------------------------------------------------------------- EBIT by Business Segment: Natural gas distribution $5,498 $7,167 ($1,669) $7,167 $4,728 $2,439 Natural gas transmission 3,721 2,458 1,263 2,458 6,083 (3,625) Propane distribution 1,064 2,815 (1,751) 2,815 2,252 563 Advanced information services 1,046 1,056 (10) 1,056 1,061 (5) Other 558 561 (3) 561 (32) 593 - ------------------------------------------------------------------------------------------------------- Total EBIT $11,887 $14,057 ($2,170) $14,057 $14,092 ($35) ======================================================================================================= Chesapeakes 1996 net income was $7,604,915, as compared to $7,593,506 for 1995. Although net income was relatively unchanged, the contribution to net income from each business segment differed during the two-year period. Natural gas distribution EBIT was higher in 1996 due to rate increases placed in effect in two of the three service territories during 1995. EBIT for the propane distribution segment increased due to greater volumes sold due to temperatures being 3% colder than in 1995. Natural gas transmissions contribution decreased due to a reduction in volumes sold to industrial interruptible customers during 1996. In addition, 1995 net income includes a one-time benefit from a settlement with the Federal Energy Regulatory Commission (see Note K to the Consolidated Financial Statements). Natural Gas Distribution The reduction in EBIT of $1.7 million from 1996 to 1997 is primarily related to a decline in total gross margin, as indicated in the following table, coupled with an overall increase in expenses. The reduction in gross margin earned on volumes sold is primarily the result of a 3% decline in volumes sold to residential and commercial customers and a decrease in volumes sold to industrial interruptible customers in Chesapeakes Florida service territory. The reduction in volumes sold to residential and commercial customers was directly related to warmer temperatures, primarily during the first quarter of 1997. Operations and maintenance expenses increased $633,000 and $108,000, respectively. Compensation, regulatory commission expenses and costs related to data processing and billable service revenue contributed to the increase in operations expenses. A greater level of maintenance to the gas pipeline system resulted in an increase in maintenance expenses. The $2.4 million rise in EBIT from 1995 to 1996 resulted from an increase in gross margin earned on sales of natural gas in two of Chesapeakes three service territories, offset by an overall increase in expenses. The $4.0 million increase in gross margin was partially due to a full year of rate increases, which went into effect in 1995. Maryland operations rates became effective during December and interim rates were in effect during June of 1995 for Delaware operations. In addition, colder temperatures contributed to the 20% increase in deliveries to residential and commercial customers located in Chesapeakes northern service territory. The $583,000 increase in operations expenses was primarily the result of higher compensation, benefits, data processing costs, bad debts and regulatory expenses. Plant additions placed in service during 1996 resulted in higher depreciation expense. In addition, other taxes increased by $460,000 or 23%, partially due to the inclusion of certain state revenue related taxes, which were previously included as reductions to revenue. GROSS MARGIN SUMMARY (in thousands) - ------------------------------------------------------------------------------------------------------- Increase/ Increase/ For the Years Ended December 31, 1997 1996 (decrease) 1996 1995 (decrease) - ------------------------------------------------------------------------------------------------------- Revenues: Gas sold $54,205 $52,290 $1,915 $52,290 $42,784 $9,506 Gas transported 3,061 2,991 70 2,991 2,618 373 Gas marketed 18,419 19,382 (963) 19,382 8,555 10,827 Other 275 193 82 193 168 25 - ------------------------------------------------------------------------------------------------------- Total Revenues $75,960 $74,856 $1,104 $74,856 $54,125 $20,731 ======================================================================================================= Cost of Sales:* Gas sold $35,507 $32,846 $2,661 $32,846 $26,789 $6,057 Gas marketed 18,233 19,117 (884) 19,117 8,410 10,707 - ------------------------------------------------------------------------------------------------------- Total Cost of Sales $53,740 $51,963 $1,777 $51,963 $35,199 $16,764 ======================================================================================================= Gross Margin: Gas sold $18,698 $19,444 ($746) $19,444 $15,995 $3,449 Gas transported 3,061 2,991 70 2,991 2,618 373 Gas marketed 186 265 (79) 265 145 120 Other 275 193 82 193 168 25 - ------------------------------------------------------------------------------------------------------- Total Gross Margin $22,220 $22,893 ($673) $22,893 $18,926 $3,967 ======================================================================================================= * Transportation service does not have an associated cost of sales. Natural Gas Transmission The Companys natural gas transmission segment, Eastern Shore, which became an open access pipeline on November 1, 1997, had an increase in EBIT of $1.3 million for 1997. The rise in EBIT is partially attributable to a rate increase and an increase in firm services implemented in 1997, as well as an overall reduction in expenses. The rate increase is designed to generate additional gross margin of approximately $1.2 million annually. Also contributing to the increase in EBIT were additional revenues generated by the increase in transportation services that were effective with the implementation of open access. On an annual basis, the additional services will generate revenue of approximately $1.3 million. Operations expense decreased by $143,000 or 5%, primarily consisting of compensation, relocation costs and property insurance. Maintenance expenses were also lower due to reduced maintenance required during the year on the gas pipeline system. Capital additions during the year resulted in higher depreciation expense. The $3.6 million reduction in 1996 EBIT was primarily due to lower gross margin on sales to industrial customers. The gross margin decreased due to a 67% reduction in volumes delivered, primarily reflecting lower deliveries to two industrial interruptible customers -- a municipal power plant and a methanol plant. The methanol plant shut down operations on April 1, 1996. During 1996 and 1995, deliveries to the methanol and power plants contributed approximately $284,000 and $2.4 million, respectively to gross margin. As interruptible customers, they had no ongoing commitment, contractual or otherwise, to purchase natural gas from the Company (see Note A to the Consolidated Financial Statements). The $109,000 increase in operating expenses reflects increased compensation and benefit related expenses. Depreciation increased due to plant placed in service. With Eastern Shores conversion to open access, all of its customers will have the opportunity to transport gas over its system at rates regulated by the FERC. The variability in Eastern Shores margins, historically driven by the sales to industrial customers, will dramatically decrease, as capacity reservation fees for transportation services will drive prospective margins. It is expected that in the future, Eastern Shores EBIT will tend to be more stable and resemble a fully regulated return. Taking the 1997 rate increase, revenues associated with additional capacity and lower margins on services provided to industrial customers into account, the Company expects gross margin during 1998 to be between $7.9 and $8.2 million (see Cautionary Statement). Comparatively, gross margin for the past three years has been $7.9 million, $6.7 million and $10.2 million for 1997, 1996 and 1995, respectively. Propane Distribution In 1997, Chesapeake integrated the operations of Tri-County and the Companys existing propane distribution operations. Like Chesapeakes existing propane operations, Tri-Countys earnings are heavily dependent upon weather conditions. The reduction in 1997 EBIT of $1.8 million was primarily due to a reduction in gross margin, partially offset by a reduction in expenses. Gross margin decreased due to an 11% reduction in sales volumes coupled with a 13% lower margin per gallon sold. The decline in sales volumes is directly related to the warmer temperatures, which averaged 6% warmer than the prior year. Furthermore, during the first quarter of 1997 temperatures were 14% warmer than normal. The Company normally sells a high percentage of its annual volume during this period. The reduction in margin per gallon sold was also the result of abnormally warmer temperatures. As temperatures warmed during the first quarter, demand decreased and supply-prices declined rapidly. Due to the low cost of wholesale-supply, retail prices declined, thereby reducing margins. Operations expenses decreased $554,000 or 7% primarily in the areas of compensation, delivery related costs, advertising and legal fees. Maintenance expenses declined primarily in equipment and structures. Depreciation and amortization expenses declined $477,000 or 28% primarily the result of a non-compete agreement, which became fully amortized in November of 1996. The increase in 1996 EBIT of $563,000 is primarily attributable to a rise in gross margin partially offset by higher expenses. Gross margin was higher due to a 12% increase in volumes sold and a slight increase in margin earned per gallon sold. The increases are directly related to temperatures which were 3% colder than those in 1995. Operating expenses increased $1.3 million or 19% in 1996 primarily due to compensation, delivery related costs, benefits and outside services. Maintenance expenses increased in the areas of propane storage facilities, equipment and structures. Advanced Information Services The results of the advanced information services segment consisted primarily of those of United Systems, Inc. ("USI"), due to the downsizing of Chesapeakes North Carolina operations in early 1997. Although the EBIT contribution of this segment has remained unchanged from 1996 to 1997, USIs gross margin has increased by $970,000 or 34%. Operating expenses increased due to the opening of a new office in Detroit, Michigan and the expansion of staff training and marketing efforts to position USI to be able to provide new services and for future growth of current services. Since the rise in operating costs offset most of the growth in gross margin, EBIT remained constant. Although the EBIT contributed by the advanced information segment was relatively unchanged from 1995 to 1996, EBIT contributed by USI increased $268,000. This was mostly offset by a reduction in EBIT contributed by the North Carolina operation as they ceased to provide facilities management services beginning in early 1996. Income Taxes Operating income taxes in 1997 decreased $619,000 due to a reduction in EBIT. This was partially offset by the one-time expense of $318,000 recorded in 1997 to establish the deferred income tax liability for Tri-County. Prior to 1997, Tri-County was a subchapter S Corporation for income tax reporting; therefore, no deferred income taxes were recorded on its balance sheet. In addition, the Companys 1996 and 1995 restated financial statements do not include any income tax expense for Tri-County due to its subchapter S status during those years. Other Non-operating income was $428,000, $458,000 and $391,000 for 1997, 1996 and 1995, respectively. The decrease in 1997 is primarily due to a reduction in interest income, partially offset by the gain on the sale of fixed assets. The increase in 1996 is primarily the result of a rise in interest income earned partially offset by a reduction in the gain on sales of fixed assets. Environmental Matters The Company continues to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at several former gas manufacturing plant sites (see Note J to the Consolidated Financial Statements). The Company believes that any future costs associated with these sites will be recoverable in rates. The Year 2000 Chesapeake is dependent upon information systems to operate efficiently and effectively. In order to address the impact of the year 2000 on its many information systems, Chesapeake is in the process of evaluating and remediating any deficiencies. The Company has segregated the evaluation of its readiness and the potential impact of the year 2000 on its systems into two components: primary internal applications and other applications. The Companys primary applications include systems for its financial information; natural gas customer information and billing; and propane customer information, billing and delivery. Other applications include systems for services such as telephone, system control and data acquisition for the pipeline, as well as other vendors systems. With respect to the three primary applications, Chesapeake has updated its propane customer information, billing and delivery system to a year 2000 compliant version. This system will be tested further to insure compliance during 1998. With respect to the other two primary applications, Chesapeake has conducted initial evaluations and estimates that the cost of any remediation will not be significant. Each application will be tested during 1998. Chesapeake has developed an inventory of other applications and is in the process of developing plans to contact its vendors, test and remediate to the extent necessary. Competition Historically, the Companys natural gas operations have successfully competed with other forms of energy such as electricity, oil and propane. The principle considerations have been price, and to a lesser extent, accessibility. As a result of Eastern Shores recent conversion to open access, the Company expects to be subject to competitive pressures from other sellers of natural gas. With open access transportation services available on Eastern Shores system, third party suppliers will compete with Chesapeake to sell gas to the local distribution companies and the end users on Eastern Shores system. Eastern Shore has shifted from providing sales service to providing transportation and contract storage services. The Companys distribution operations located in Delaware began to offer transportation services to certain industrial customers in December 1997. Chesapeake expects that during 1998, the distribution operations located in Maryland will also begin offering transportation services. The Company expects to expand the availability of transportation services to additional customers in the future. Since the Florida distribution operations have been open to certain industrial customers since 1994, the Company has gained experience in operating in an open access environment. The Company established a natural gas brokering and supplies operation in Florida to compete for these customers. The Company is evaluating whether to establish similar services in our northern service territory. Both the propane distribution and the advanced information services businesses face significant competition from a number of larger competitors with substantially greater resources available to them than those of the Company. In addition, in the advanced information services business, changes are occurring rapidly, which could adversely affect the markets for the Companys services. Inflation Inflation affects the cost of labor and other goods and services required for operation, maintenance and capital improvements. The impact of inflation has lessened in recent years, except for the effect on purchased gas costs. These costs are passed on to customers through the purchased gas adjustment clause in the Companys 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. Cautionary Statement Statements made herein and elsewhere in this Form 10-K, which are not historical fact, are forward-looking statements. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, Chesapeake is providing the following cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated in forward-looking statements made herein or otherwise by or on behalf of the Company. A number of factors and uncertainties make it difficult to predict the effect on future operating results of Eastern Shore operating as an open access pipeline, relative to historical results. While open access eliminates industrial interruptible sales margins, such sales have varied widely from year to year and, in future years, might have made a less significant contribution to earnings even in the absence of open access. Additionally, there are a number of uncertainties, including future open access proceedings and the effects of competition, which will affect whether the Company will be able to provide economical gas marketing, transportation and other services. In addition, a number of factors and uncertainties affecting other aspects of the Companys business could have a material impact on earnings. These include: the seasonality and temperature sensitivity of Chesapeakes natural gas and propane businesses, the relative price of alternative energy sources and the effects of competition on both unregulated and natural gas sales, now that the Company operates in an open access environment. There are also uncertainties relative to the impact of the year 2000 on the information systems of the Company, its vendors and other third parties. Item 8. Financial Statements and Supplemental Data REPORT OF INDEPENDENT ACCOUNTANTS ________ To the Stockholders of Chesapeake Utilities Corporation We have audited the consolidated financial statements and consolidated financial statement schedules of Chesapeake Utilities Corporation and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Companys Management. Our responsibility is to express an opinion on these financial statements and the financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Chesapeake Utilities Corporation and Subsidiaries as of December 31, 1997 and 1996, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. In addition, in our opinion, the consolidated financial statement schedules referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. We have also previously audited, in accordance with generally accepted standards, the consolidated balance sheets and statements of capitalization as of December 31, 1995, 1994 and 1993, and the related consolidated statements of income, cash flows, stockholders equity, and income taxes for each of the two years in the period ended December 31, 1994 (none of which are presented herein) and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Financial Highlights included in the Selected Financial Data for each of the five years in the period ended December 31, 1997, appearing on page 17 is fairly stated in all material respects in relation to the financial statements from which it has been derived. COOPERS & LYBRAND L.L.P. Baltimore, Maryland February 12, 1998 CONSOLIDATED BALANCE SHEETS Assets - ---------------------------------------------------------------------------------------------- At December 31, 1997 1996 - ---------------------------------------------------------------------------------------------- Property, Plant and Equipment Natural gas distribution $74,769,458 $69,853,054 Natural gas transmission 33,856,873 30,655,492 Propane distribution 26,920,403 25,279,217 Advanced information services 841,757 1,003,850 Other plant 6,161,631 5,414,249 Gas plant acquisition adjustment 795,004 795,004 - ---------------------------------------------------------------------------------------------- Total property, plant and equipment 143,345,126 133,000,866 Less: Accumulated depreciation and amortization (43,827,961) (39,430,738) - ---------------------------------------------------------------------------------------------- Net property, plant and equipment 99,517,165 93,570,128 - ---------------------------------------------------------------------------------------------- Investments 2,721,443 2,263,068 - ---------------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents 555,198 2,213,529 Accounts receivable (less allowance for uncollectibles of $331,775 and $392,412 in 1997 and 1996, respectively) 13,087,999 14,488,944 Materials and supplies, at average cost 1,380,120 1,284,876 Propane inventory, at average cost 2,288,516 2,345,531 Storage gas prepayments 2,926,618 3,731,680 Underrecovered purchased gas costs 1,673,389 2,192,170 Income taxes receivable 849,623 112,942 Prepaid expenses 1,060,911 942,359 Deferred income taxes 247,487 158,010 - ---------------------------------------------------------------------------------------------- Total current assets 24,069,861 27,470,041 - ---------------------------------------------------------------------------------------------- Deferred Charges and Other Assets Environmental regulatory assets 4,865,073 6,650,088 Environmental expenditures, net 2,372,929 1,778,348 Other deferred charges and intangible assets 3,832,389 4,314,235 - ---------------------------------------------------------------------------------------------- Total deferred charges and other assets 11,070,391 12,742,671 - ---------------------------------------------------------------------------------------------- Total Assets $137,378,860 $136,045,908 ============================================================================================== See accompanying notes Capitalization and Liabilities - ---------------------------------------------------------------------------------------------- At December 31, 1997 1996 - ---------------------------------------------------------------------------------------------- Capitalization Stockholders' equity Common stock $2,191,792 $2,160,628 Additional paid-in capital 19,819,604 18,745,718 Retained earnings 28,218,763 26,957,048 Less: Unearned compensation related to restricted stock awarded (190,886) (364,529) Unrealized gain on marketable securities, net 296,872 38,598 - ---------------------------------------------------------------------------------------------- Total stockholders' equity 50,336,145 47,537,463 Long-term debt, net of current portion 38,226,000 28,984,368 - ---------------------------------------------------------------------------------------------- Total capitalization 88,562,145 76,521,831 - ---------------------------------------------------------------------------------------------- Current Liabilities Current portion of long-term debt 582,500 3,078,489 Short-term borrowing 7,600,000 12,700,000 Accounts payable 12,451,570 14,426,983 Refunds payable to customers 357,041 353,734 Accrued interest 784,533 741,768 Dividends payable 1,092,168 883,621 Other accrued expenses 3,807,484 3,733,233 - ---------------------------------------------------------------------------------------------- Total current liabilities 26,675,296 35,917,828 - ---------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 11,490,358 9,798,676 Deferred investment tax credits 821,617 876,432 Environmental liability 4,865,073 6,650,088 Accrued pension costs 1,754,715 1,866,661 Other liabilities 3,209,656 4,414,392 - ---------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 22,141,419 23,606,249 - ---------------------------------------------------------------------------------------------- Commitments and Contingencies (Notes J and K) Total Capitalization and Liabilities $137,378,860 $136,045,908 ============================================================================================== See accompanying notes CONSOLIDATED STATEMENTS OF INCOME - ----------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------- Operating Revenues $122,774,593 $130,213,409 $111,795,778 Cost of Sales 77,764,830 82,226,644 65,616,368 - ----------------------------------------------------------------------------------------------------------- Gross Margin 45,009,763 47,986,765 46,179,410 - ----------------------------------------------------------------------------------------------------------- Operating Expenses Operations 21,831,194 22,230,425 20,612,585 Maintenance 2,041,043 2,504,894 2,477,454 Depreciation and amortization 5,396,975 5,504,637 5,802,884 Other taxes 3,853,954 3,689,748 3,194,673 Income taxes 3,327,627 3,947,056 4,025,274 - ----------------------------------------------------------------------------------------------------------- Total operating expenses 36,450,793 37,876,760 36,112,870 - ----------------------------------------------------------------------------------------------------------- Operating Income 8,558,970 10,110,005 10,066,540 - ----------------------------------------------------------------------------------------------------------- Other Income Interest income 239,543 249,509 191,845 Other income, net 405,156 177,045 239,687 Income taxes (216,988) (83,739) (105,280) Allowance for equity funds used during construction 115,434 65,198 - ----------------------------------------------------------------------------------------------------------- Total other income 427,711 458,249 391,450 - ----------------------------------------------------------------------------------------------------------- Income Before Interest Charges 8,986,681 10,568,254 10,457,990 - ----------------------------------------------------------------------------------------------------------- Interest Charges Interest on long-term debt 2,347,369 2,392,458 2,282,247 Amortization of debt expense 119,401 120,345 109,399 Other 922,110 514,856 566,320 Allowance for borrowed funds used during construction (85,145) (64,320) (93,482) - ----------------------------------------------------------------------------------------------------------- Total interest charges 3,303,735 2,963,339 2,864,484 - ----------------------------------------------------------------------------------------------------------- Net Income $5,682,946 $7,604,915 $7,593,506 =========================================================================================================== Earnings Per Share of Common Stock: Basic: $1.27 $1.72 $1.75 Diluted: $1.24 $1.67 $1.70 See accompanying notes CONSOLIDATED STATEMENTS OF CASH FLOWS - ----------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------- Operating Activities Net Income $5,682,946 $7,604,915 $7,593,506 Adjustments to reconcile net income to net operating cash: Depreciation and amortization 6,090,665 6,148,232 6,246,222 Allowance for equity funds used during construction (115,434) (65,198) Investment tax credit adjustments (54,815) (54,815) (54,815) Deferred income taxes, net 1,437,206 1,794,146 252,727 Employee benefits (238,826) 471,870 178,803 Employee compensation from lapsing of stock restrictions 173,643 334,745 431,694 Allowance for refund (1,356,705) Other, net (286,147) 83,301 (339,081) Changes in assets and liabilities: Accounts receivable, net 1,400,945 (904,516) (4,727,364) Other current assets 648,282 (2,141,048) 1,588,675 Other deferred charges (625,395) (977,652) (946,450) Accounts payable, net (1,823,912) 1,422,807 3,619,023 Refunds payable to customers 3,307 (613,206) 400,192 Overrecovered (underrecovered) purchased gas costs 518,781 (2,245,544) 162,399 Other current liabilities (619,668) 396,326 939,750 - ----------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 12,307,012 11,204,127 13,923,378 - ----------------------------------------------------------------------------------------------------------- Investing Activities Property, plant and equipment expenditures, net (12,380,826) (14,069,116) (11,666,442) Allowance for equity funds used during construction 115,434 65,198 Purchases of investments (36,167) (129,406) (38,836) - ----------------------------------------------------------------------------------------------------------- Net cash used by investing activities (12,416,993) (14,083,088) (11,640,080) - ----------------------------------------------------------------------------------------------------------- Financing Activities Common stock dividends, net of amounts reinvested of $382,932, $346,308 and $304,106 in 1997, 1996 and 1995, respectively (3,829,752) (3,337,755) (3,324,376) Issuance of stock -- Dividend Reinvestment Plan optional cash 167,337 208,813 202,835 Issuance of stock -- Retirement Savings Plan 404,297 349,031 Net (repayments) borrowings under line of credit agreements (5,100,000) 7,300,000 (3,197,039) Proceeds from issuance of long-term debt 9,908,223 10,428,753 Repayment of long-term debt (3,098,455) (823,213) (5,439,151) - ----------------------------------------------------------------------------------------------------------- Net cash (used) provided by financing activities (1,548,350) 3,696,876 (1,328,978) - ----------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (1,658,331) 817,915 954,320 Cash and Cash Equivalents at Beginning of Year 2,213,529 1,395,614 441,294 - ----------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $555,198 $2,213,529 $1,395,614 =========================================================================================================== Supplemental Disclosure of Cash Flow Information Cash paid for interest $3,203,709 $2,831,109 $2,884,864 Cash paid for income tax $3,400,479 $2,122,120 $3,288,895 See accompanying notes CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - ----------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------- Common Stock Balance -- beginning of year $2,160,628 $2,122,212 $2,096,515 (1) Dividend Reinvestment Plan 15,398 16,514 18,816 USI restricted stock award agreements 10,639 6,881 Conversion of debentures 4,461 429 Company's Retirement Savings Plan 11,305 9,928 Exercised stock options 906 - ----------------------------------------------------------------------------------------------------------- Balance -- end of year 2,191,792 2,160,628 2,122,212 - ----------------------------------------------------------------------------------------------------------- Additional Paid-in Capital Balance -- beginning of year 18,745,718 17,489,108 16,731,689 (1) Dividend Reinvestment Plan 529,453 538,607 488,125 USI restricted stock award agreements 344,570 176,029 Sale of treasury stock to Company's Retirement Savings Plan 93,265 Conversion of debentures 151,441 14,557 Company's Retirement Savings Plan 392,992 328,465 Exercised stock options 30,411 - ----------------------------------------------------------------------------------------------------------- Balance -- end of year 19,819,604 18,745,718 17,489,108 - ----------------------------------------------------------------------------------------------------------- Retained Earnings Balance -- beginning of year 26,957,048 23,458,776 19,480,374 Net income 5,682,946 7,604,915 7,593,506 (1) Cash dividends -- Chesapeake (2) (4,341,964) (3,514,694) (3,331,972) Cash dividends -- Pooled companies (79,267) (591,949) (283,132) - ----------------------------------------------------------------------------------------------------------- Balance -- end of year 28,218,763 26,957,048 23,458,776 - ----------------------------------------------------------------------------------------------------------- Treasury Stock (3) Unearned Compensation Balance -- beginning of year (364,529) (415,107) (696,679) Issuance of award (284,167) (121,343) Amortization of prior years' awards 173,643 334,745 402,915 - ----------------------------------------------------------------------------------------------------------- Balance -- end of year (190,886) (364,529) (415,107) - ----------------------------------------------------------------------------------------------------------- Unrealized Gain (Loss) on Marketable Securities (4) 296,872 38,598 (72,839) - ----------------------------------------------------------------------------------------------------------- Total Stockholders' Equity $50,336,145 $47,537,463 $42,582,150 =========================================================================================================== <FN> (1) The following adjustments have been made to 1995 presentation to reflect the Tri-County pooling of interests: Begining balances of Common Stock and Additional Paid-in Capital have been adjusted by $311,001 and ($103,314), respectively. Net income as shown in the Retained Earnings section has been adjusted by $356,811. (2) Dividends per share of common stock were $.97, $.93 and $.90 for the years 1997, 1996 and 1995, respectively. (3) The entire Treasury Stock balance of ($99,842) was sold to the Company's Retirement Savings Plan during 1995, leaving a zero balance. (4) Net of income tax expense (benefit) of approximately $190,000, $25,000 and ($48,000) for the the years 1997, 1996 and 1995, respectively. </FN> See accompanying notes CONSOLIDATED STATEMENTS OF INCOME TAXES - ----------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------- Current Income Tax Expense Federal $1,916,654 $1,884,609 $3,182,346 State 442,563 356,576 621,238 Investment tax credit adjustments, net (54,815) (54,815) (54,815) - ----------------------------------------------------------------------------------------------------------- Total current income tax expense 2,304,402 2,186,370 3,748,769 - ----------------------------------------------------------------------------------------------------------- Deferred Income Tax Expense Property, plant and equipment 1,335,802 581,373 455,151 Deferred gas costs (204,170) 873,904 (56,915) Pensions and other employee benefits (19,508) 107,131 57,508 Unbilled revenue (104,632) 54,320 (260,922) Contributions in aid of construction (33,028) (6,979) (283,033) Environmental expenditures 249,417 108,578 272,068 Allowance for refund 121,671 442,064 Other 16,332 4,427 (244,136) - ----------------------------------------------------------------------------------------------------------- Total deferred income tax expense (1) 1,240,213 1,844,425 381,785 - ----------------------------------------------------------------------------------------------------------- Total Income Tax Expense $3,544,615 $4,030,795 $4,130,554 =========================================================================================================== Reconciliation of Effective Income Tax Rates Federal income tax expense at 34% 3,171,505 3,956,118 3,986,180 State income taxes, net of Federal benefit 399,213 537,566 546,955 Acquisition of subchapter S Corporation (2) 317,821 (268,211) (137,800) Other (343,924) (194,678) (264,781) - ----------------------------------------------------------------------------------------------------------- Total income tax expense $3,544,615 $4,030,795 $4,130,554 =========================================================================================================== Effective income tax rate 38.4% 36.8% 36.3% - ---------------------------------------------------------------------------------------------- At December 31, 1997 1996 - ---------------------------------------------------------------------------------------------- Deferred Income Taxes Deferred income tax liabilities: Property, plant and equipment $12,095,782 $10,716,757 Deferred gas costs 649,681 853,851 Other 1,560,988 1,322,272 - ---------------------------------------------------------------------------------------------- Total deferred income tax liabilities 14,306,451 12,892,880 - ---------------------------------------------------------------------------------------------- Deferred income tax assets: State operating loss carryforwards 57,303 3,320 Deferred investment tax credit 403,789 426,565 Unbilled revenue 968,311 863,679 Pension and other employee benefits 898,060 917,568 Self insurance 585,995 545,836 Other 150,122 495,246 - ---------------------------------------------------------------------------------------------- Total deferred income tax assets 3,063,580 3,252,214 - ---------------------------------------------------------------------------------------------- Deferred Income Taxes Per Consolidated Balance Sheet $11,242,871 $9,640,666 ============================================================================================== <FN> (1) Includes $208,000, $392,000 and $108,000 of deferred state income taxes for the years 1997, 1996 and 1995, respectively. (2) Accounted for as a pooling of interests (see Note B to the Consolidated Financial Statements). </FN> See accompanying notes NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A. Summary of Accounting Policies Nature of Business Chesapeake Utilities Corporation (the "Company") is engaged in natural gas distribution to approximately 35,800 customers located in southern Delaware, Marylands Eastern Shore and Central Florida. The Companys natural gas transmission subsidiary operates a pipeline from various points in Pennsylvania to the Companys Delaware and Maryland distribution divisions, as well as other utility and industrial customers in Delaware and the Eastern Shore of Maryland. The Companys propane distribution segment serves approximately 34,000 customers in southern Delaware, the Eastern Shore of Maryland and Virginia. The advanced information services segment provides software services and products to a wide variety of clients. Principles of Consolidation The Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries, Eastern Shore Natural Gas Company ("Eastern Shore"), Sharp Energy, Inc. ("Sharp Energy"), Tri-County Gas Company, Inc. ("Tri-County") and Chesapeake Service Company. Sharp Energys accounts include those of its wholly owned subsidiary, Sharpgas, Inc. Chesapeake Service Companys accounts include United Systems, Inc. ("USI"), Capital Data Systems, Inc. and Skipjack, Inc. Investments in entities in which the Company owns more than 20 percent but 50 percent or less, are accounted for by the equity method. 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 the Delaware, Maryland and Florida Public Service Commissions with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore is subject to regulation by the Federal Energy Regulatory Commission ("FERC"). The Companys financial statements are prepared on the basis of 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 subsidiaries are not subject to regulation with respect to rates or maintenance of accounting records. Cash and Cash Equivalents The Companys policy is to invest cash in excess of operating requirements in overnight income producing accounts. Such amounts are stated at cost, which approximates market. Investments with an original maturity of three months or less are considered cash equivalents. Property, Plant, Equipment and Depreciation Utility property is stated at original cost while the assets of the propane subsidiary are valued at cost. The costs of repairs and minor replacements are charged to income as incurred and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of utility property, the recorded cost of removal, net of salvage value, is charged to accumulated depreciation. 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, which will amortize the unrecovered cost of depreciable property over the estimated useful life. Depreciation and amortization expense for financial statement purposes is provided at an annual rate for each segment averaging 4.73% for natural gas distribution; 3.04% for natural gas transmission and 5.46% for propane distribution. In addition, annualized rates average 4.73% for gas plant acquisition adjustments, 17.78% for the advanced information services segment and 2.59% for general plant. Allowance for Funds Used During Construction The allowance for funds used during construction ("AFUDC") is an accounting procedure whereby the cost of borrowed funds and other funds used to finance construction projects is capitalized as part of utility plant on the balance sheet, crediting the cost as a non-cash item on the income statement. The costs of borrowed and equity funds are segregated between interest expense and other income, respectively. AFUDC was capitalized on utility plant construction at the rates of 5.63%, 9.51% and 7.31% for 1997, 1996 and 1995, respectively. Environmental Regulatory Assets Environmental regulatory assets represent amounts related to environmental liabilities for which cash expenditures have not been made. As expenditures are incurred, the environmental liability can be reduced along with the environmental regulatory asset. These amounts are recorded to either environmental expenditures or accumulated depreciation as cost of removal. All amounts incurred are amortized in accordance with the ratemaking treatment granted in each jurisdiction. Other Deferred Charges and Intangible Assets Other deferred charges include discount, premium and issuance costs associated with long-term debt and rate case expenses. The discount, premium and issuance costs are deferred, then amortized over the original lives of the respective debt issues. Gains and losses on the reacquisition of debt are amortized over the remaining lives of the original issuance(s). Rate case expenses are deferred, then amortized over periods approved by the applicable regulatory authorities. Intangible assets are associated with the acquisition of non-utility companies, and are amortized on a straight-line basis over a period of five to 40 years. The gross intangible assets were $2,516,120 and $1,920,851 at December 31, 1997 and 1996, respectively. Accumulated amortization related to intangible assets was $1,093,905 and $962,227 at December 31, 1997 and 1996, respectively. In addition, the 1997 acquisition of a propane business resulted in the Company acquiring goodwill, a customer list and a non-compete agreement valued at $437,000, $108,000 and $50,000, respectively. Income Taxes and Investment Tax Credit Adjustments The Company files a consolidated federal income tax return. Income tax expense allocated to the Companys 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 portion of the Companys deferred tax liabilities applicable to utility operations which has not been reflected in current service rates represents 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. The Company had state tax loss carryforwards of $796,000 and $46,000 at December 31, 1997 and 1996, respectively. The Company expects to use all of the loss carryforwards; therefore, no valuation allowance was recorded at December 31, 1997 or 1996. The loss carryforwards expire in 2006 through 2012. 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 C to the Consolidated Financial Statements for disclosure of fair value of investments). The fair value of the Companys long-term debt is estimated using a discounted cash flow methodology. The estimated fair value of the Companys long-term debt at December 31, 1997, including current maturities, is approximately $40.7 million as compared to a carrying value of $38.8 million. At December 31, 1996, the estimated fair value was approximately $30.3 million as compared to a carrying value of $29.8 million. These estimates are based on published corporate borrowing rates for debt instruments with similar terms and average maturities. Operating Revenues Revenues for the natural gas distribution divisions of the Company are based on rates approved by the various commissions. Customers base rates may not be changed without formal approval by these commissions. With the exception of the Companys Florida division, the Company recognizes revenues from meters read on a monthly cycle basis. This practice results in unbilled and unrecorded revenue from the cycle date through month-end. The Florida division recognizes revenues based on services rendered and records an amount for gas delivered but not billed. The propane segment recognizes revenue for certain customers on a metered basis and all other customers on an as-delivered basis. The natural gas distribution divisions of the Company have purchased gas adjustment ("PGA") clauses that provide 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 natural gas transmission segment became an open access pipeline on November 1, 1997 with revenues based on rates approved by FERC. Before open access, only portions of revenues were based on rates approved by FERC. In addition, the transmission segment had a PGA clause similar to those in the distribution operations. Since the transmission segment records revenue for service only, the PGA clause no longer applies, now that open access is in effect. The Company charges flexible rates to the industrial interruptible customers of the natural gas distribution segment to make natural gas 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 customer is contractually obligated to deliver or receive natural gas. Earnings Per Share The Company has adopted Statement of Financial Accounting Standards ("SFAS") No. 128, issued by the Financial Accounting Standards Board ("FASB") in February 1997, requiring dual presentation of basic and diluted per share earnings on the face of the income statement. Basic earnings per share is based on the weighted average number of shares of common stock outstanding. On a diluted basis, both earnings and shares outstanding are adjusted for stock options for each year presented and the assumed conversion of the convertible debentures. The adoption of SFAS No. 128 did not have a material effect on the Companys financial statements. Prior years presentations of earnings per share have been restated to conform to the guidelines of SFAS No. 128. CALCULATION OF DILUTED EARNINGS PER SHARE - ------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - ------------------------------------------------------------------------------------------------- Reconciliation of Numerator: Net Income - basic $5,682,946 $7,604,915 $7,593,506 Effect of 8.25% Convertible debentures 204,070 207,825 213,043 - ------------------------------------------------------------------------------------------------- Adjusted numerator - diluted $5,887,016 $7,812,740 $7,806,549 ================================================================================================= Reconciliation of Denominator: Weighted Shares Outstanding - basic 4,472,087 4,412,137 4,336,431 Effect of Dilutive Securities 8.25% Convertible debentures 238,353 242,742 248,833 Stock options and performance shares * 38,462 22,053 4,487 - ------------------------------------------------------------------------------------------------- Adjusted denominator - diluted 4,748,902 4,676,932 4,589,751 ================================================================================================= Diluted Earnings per Share $1.24 $1.67 $1.70 ================================================================================================= <FN> * The impact of the 95,492 stock options that were granted in 1997 (see Note H to the Consolidated Financial Statements) could potentially dilute earnings per share in the future. </FN> Certain Risks and Uncertainties The financial statements are prepared in conformity with generally accepted accounting principles that require management to make estimates (see Note J to the Consolidated Financial Statements for significant estimates) in measuring assets and liabilities and related revenue and expenses. These estimates involve judgements 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 regulated operations, all such deferred amounts would be recognized in the income statement at that time, resulting in a charge to earnings, net of applicable income taxes. FASB Statements Issued Comprehensive Income. In June 1997, the FASB issued SFAS No. 130 regarding the reporting of comprehensive income in the full set of financial statements. The Company must adopt the requirements of the standard in its financial statements for the year beginning January 1, 1998. The effect of the adoption of the standard pertains primarily to SFAS No. 115 regarding held for sale investments, and is not expected to have a material impact on the Companys financial statements. Segment Information. In June 1997, FASB issued SFAS No. 131, establishing standards for public business enterprises to report information about operating segments in annual financial statements and requiring that those enterprises report selected information about operating segments in interim financial reports to shareholders. The Company will adopt the requirements of this standard in the first quarter of the 1998 fiscal year. The adoption of the standard is not expected to have a material impact on the Companys financial statements. Reclassification of Prior Years Amounts Certain prior years amounts have been reclassified to conform to current year presentation. B. Business Combinations In March 1997, the Company acquired all of the outstanding common stock of Tri-County Gas Company, Inc. and associated properties. Tri-Countys principal business is the distribution of propane to both retail and wholesale customers in southern Delaware, the Eastern Shore of Maryland and Virginia. Six hundred thirty-nine thousand shares of the Companys common stock were exchanged in the transaction, which was accounted for as a pooling of interests. All prior period consolidated financial statements presented have been restated to include the combined results of operations, financial position and cash flows of Tri-County. All material transactions between the Company and Tri-County have been eliminated in consolidation. The results of operations for the separate companies and the combined amounts are presented in the consolidated financial statements to follow. - --------------------------------------------------------------------------------------------------------------- Two months ended Year Ended Year Ended February 28, 1997 December 31, 1996 December 31, 1995 - --------------------------------------------------------------------------------------------------------------- Operating Revenues Chesapeake $29,690,819 $119,330,068 $104,020,416 Tri-County 2,652,910 10,883,341 7,775,362 - --------------------------------------------------------------------------------------------------------------- Combined $32,343,729 $130,213,409 $111,795,778 =============================================================================================================== Net Income Chesapeake $2,434,351 $6,910,428 $7,236,695 Tri-County 265,059 694,487 356,811 - --------------------------------------------------------------------------------------------------------------- Combined $2,699,410 $7,604,915 $7,593,506 =============================================================================================================== Unaudited Pro Forma Net Income* Chesapeake N/A $6,910,428 $7,236,695 Tri-County N/A 426,276 219,011 - --------------------------------------------------------------------------------------------------------------- Combined N/A $7,336,704 $7,455,706 =============================================================================================================== <FN> * Unaudited pro forma net income reflects adjustments to net income to record an estimated provision for income taxes, assuming Tri-County was a tax paying entity in 1996 and 1995. During 1997, Tri-County was a C Corporation for federal income tax purposes. Tri-County will be included in the Company's U.S. federal income tax return, effective March 1997. </FN> C. Investments The investment balance at December 31, 1997 and 1996 consists primarily of the common stock of Florida Public Utilities Company ("FPU"). The Companys ownership at December 31, 1997 and 1996 represents a 7.34% and 7.41% interest, respectively. The Company has classified its investment in FPU as an "Available for Sale" security, which requires that all unrealized gains and losses be excluded from earnings and be reported net of income tax as a separate component of stockholders equity. At December 31, 1997 and 1996, the market value exceeded the aggregate cost basis of the Companys portfolio by $486,872 and $63,598, respectively. D. Lease Obligations The Company has entered several operating lease arrangements for office space at various locations. Rent expense related to these leases was $277,000, $293,000 and $409,000 for 1997, 1996 and 1995, respectively. Future minimum payments under the Companys current lease agreements are $236,000; $228,000; $232,000; $145,000 and $91,000 for the years of 1998 through 2002, respectively; and $198,000 thereafter. E. Segment Information - ---------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------- Operating Revenues, Unaffiliated Customers Natural gas distribution $75,940,968 $74,904,100 $54,120,280 Natural gas transmission 12,164,369 15,188,752 24,984,767 Propane distribution 26,994,404 33,179,114 25,345,696 Advanced information services 7,636,407 6,903,246 7,307,413 Other 38,445 38,197 37,622 - ---------------------------------------------------------------------------------------------------------- Total operating revenues, unaffiliated customers $122,774,593 $130,213,409 $111,795,778 ========================================================================================================== Intersegment Revenues * Natural gas distribution $18,970 $12,232 $5,095 Natural gas transmission 19,282,359 21,543,352 16,663,043 Propane distribution 52,230 2,059 139,052 Advanced information services 149,602 326,913 1,554,498 Other 523,007 332,512 349,508 - ---------------------------------------------------------------------------------------------------------- Total intersegment revenues $20,026,168 $22,217,068 $18,711,196 ========================================================================================================== Operating Income Before Income Taxes Natural gas distribution $5,498,471 $7,167,237 $4,728,348 Natural gas transmission 3,721,148 2,458,442 6,083,440 Propane distribution 1,063,554 2,814,958 2,252,165 Advanced information services 1,045,912 1,056,201 1,061,309 Other 524,785 406,632 215,146 - ---------------------------------------------------------------------------------------------------------- Total 11,853,870 13,903,470 14,340,408 Add (Less): Eliminations 32,727 153,591 (248,594) - ---------------------------------------------------------------------------------------------------------- Total operating income before income taxes $11,886,597 $14,057,061 $14,091,814 ========================================================================================================== Depreciation and Amortization Natural gas distribution $3,076,654 $2,907,831 $2,468,141 Natural gas transmission 892,258 697,834 638,099 Propane distribution 1,204,968 1,681,588 1,629,971 Advanced information services 122,081 131,877 969,587 Other 101,014 85,507 97,086 - ---------------------------------------------------------------------------------------------------------- Total depreciation and amortization $5,396,975 $5,504,637 $5,802,884 ========================================================================================================== Capital Expenditures Natural gas distribution $5,826,065 $6,472,459 $7,424,489 Natural gas transmission 3,286,860 5,567,509 1,335,793 Propane distribution 2,820,166 2,189,368 2,427,773 Advanced information services 277,015 162,189 114,461 Other 559,043 445,916 1,584,813 - ---------------------------------------------------------------------------------------------------------- Total capital expenditures $12,769,149 $14,837,441 $12,887,329 ========================================================================================================== Identifiable Assets, at December 31, Natural gas distribution $78,732,860 $77,426,232 $72,256,841 Natural gas transmission 24,781,292 23,981,989 19,292,524 Propane distribution 24,209,693 25,009,751 22,723,647 Advanced information services 1,751,192 1,496,419 1,635,100 Other 7,903,823 8,131,517 7,430,616 - ---------------------------------------------------------------------------------------------------------- Total identifiable assets $137,378,860 $136,045,908 $123,338,728 ========================================================================================================== * All significant intersegment revenues have been eliminated from consolidated revenues. F. Long-term Debt The outstanding long-term debt, net of current maturities, is as follows: - ------------------------------------------------------------------------------------ At December 31, 1997 1996 - ------------------------------------------------------------------------------------ First mortgage sinking fund bonds: Adjustable rate Series G*, due January 1, 1998 $0 $62,500 9.37% Series I, due December 15, 2004 4,300,000 4,820,000 12.00% Mortgage, due February 1, 1998 14,868 8.25% Convertible debentures, due March 1, 2014 3,926,000 4,087,000 Uncollateralized Senior notes: 7.97% note, due February 1, 2008 10,000,000 10,000,000 6.91% note, due October 1, 2010 10,000,000 10,000,000 6.85% note, due January 1, 2012 10,000,000 - ------------------------------------------------------------------------------------ Total long-term debt $38,226,000 $28,984,368 ==================================================================================== <FN> * The Series G bonds are subject to an interest rate equal to seventy-three percent (73%) of the prime rate (8.50% and 8.25% at December 31, 1997 and 1996, respectively). Annual maturities of consolidated long-term debt for the five years are as follows: $582,500 for 1998, $1,520,000 for 1999 and $2,665,091 for the years 2000 through 2002. </FN> On December 15, 1997, the Company issued $10 million of 6.85% senior notes due January 1, 2012. The Company used the proceeds to repay a portion of the Companys short-term borrowing. The convertible debentures may be converted, at the option of the holder, into shares of the Companys common stock at a conversion price of $17.01 per share. During 1997, $156,000 in debentures were converted. The debentures are redeemable at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000 in the aggregate. As of December 31, 1997, no debentures have been accepted for redemption in 1998. At the Companys option, the debentures may be redeemed at the 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% of total capitalization, the times interest earned ratio must be at least 2.5 and the Company cannot, until the retirement of its Series I bonds, pay any dividends after December 31, 1988 which exceed the sum of $2,135,188 plus consolidated net income recognized on or after January 1, 1989. As of December 31, 1997, the amounts available for future dividends permitted by the Series I covenant approximated $14.6 million. A portion of the natural gas distribution plant assets owned by the Company are subject to a lien under the mortgage pursuant to which the Companys first mortgage sinking fund bonds are issued. G. Short-term Borrowings The Board of Directors has authorized the Company to borrow up to $20.0 million from various bank and trust companies. As of December 31, 1997, the Company had four unsecured bank lines of credit totaling $34.0 million, none of which required compensating balances. Under these lines of credit at December 31, 1997 and 1996, the Company had short-term debt outstanding of $7.6 million and $12.7 million, respectively, with a weighted average interest rate of 5.63% and 6.12%, respectively. H. Common Stock, Additional Paid-in Capital and Treasury Stock The following is a schedule of changes in the Companys shares of common stock. - ---------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 (1) - ---------------------------------------------------------------------------------------------------- Common Stock: Shares Issued and outstanding (2) Balance - beginning of year 4,439,516 4,360,589 4,307,791 Dividend Reinvestment Plan (3) 32,169 33,926 38,660 Sale of stock to Company's Retirement Savings Plan 23,228 20,398 USI restricted stock award agreements 21,859 14,138 Conversion of debentures 9,166 881 Exercised stock options 1,863 - ---------------------------------------------------------------------------------------------------- Balance - end of year 4,504,079 4,439,516 4,360,589 ==================================================================================================== <FN> (1) The 1995 beginning balance of 4,307,791 has been restated to include 639,000 shares of Common Stock that were issued to effect the business combination with Tri-County Gas Company, Inc. (2) 12,000,000 shares are authorized at a par value of $.4867 per share. (3) Includes dividends and reinvested optional cash payments. </FN> At the beginning of 1995, the Company had 15,609 shares of common stock held in treasury. During 1995, all of these were sold to the Companys retirement savings plan. Certain key USI employees entered into restricted stock award agreements under which shares of Chesapeake common stock can be issued. Shares were awarded as a non-cash transaction over a five-year period beginning in 1992, and restrictions lapse over a five to ten-year period from the award date, if certain financial targets are met. At December 31, 1997 and 1996, respectively, 12,515 and 24,350 shares valued at $190,886 and $364,529 remain restricted. The Performance Incentive Plan, which was adopted in 1992, provides for the granting of stock options to certain officers of the Company over a 10-year period. In November 1994, the Company executed Tandem Stock Option and Performance Share Agreements ("Agreements") with certain executive officers. These Agreements provide the participants an option to purchase shares of the Companys common stock, exercisable in cumulative installments of one- third on each anniversary of the commencement of the award period. The Agreements also enable the participants the right to earn performance shares upon the Companys achievement of the performance goals set forth in the Agreements. During the three-year period ended December 31, 1997, the aforementioned performance goals were achieved. Following the approval of the Board of Directors on February 27, 1998, the Company issued 44,081 performance shares. Forty-four thousand ninety-six stock options expired upon the issuance of the performance shares on February 27. In 1997, the Company recorded $415,681 to recognize the compensation expense associated with the performance shares. Changes in outstanding options were as follows: - -------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 - -------------------------------------------------------------------------------------------------------------------- Number Option Number Option Number Option of shares Price of Shares Price of shares Price - -------------------------------------------------------------------------------------------------------------------- Balance - beginning of year 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75 136,186 $12.625 - $12.75 Options granted 95,492 $20.50 Options exercised (12,135) $12.75 Options forfeited (11,000) $12.625 - -------------------------------------------------------------------------------------------------------------------- Balance - end of year 208,543 $12.625 - $20.50 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75 ==================================================================================================================== Exercisable 98,083 $12.625 - $12.75 83,114 $12.625 - $12.75 80,280 $12.75 - -------------------------------------------------------------------------------------------------------------------- In December 1997, the Company granted stock options to certain executive officers of the Company. As required by SFAS No. 123, 1997 pro forma net income as if fair value based accounting had been used to account for the stock-based compensation costs is $5,679,603. Pro forma basic and diluted earnings per share are $1.27 and $1.24, respectively. Pro forma disclosures for 1997 are not likely to be representative of future effects of reported net income. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1997: dividend yield of 4.73%; expected volatility of 15.53%; risk-free interest rate of 5.89%; and expected lives of four years. I. Employee Benefit Plans Pension Plan The Company sponsors a defined benefit pension plan covering substantially all of its employees. Benefits under the plan are based on each participants years of service and highest average compensation. The Companys 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. PENSION COST - --------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - --------------------------------------------------------------------------------------------- Service cost $680,192 $656,985 $474,000 Interest cost 732,188 658,238 562,003 Actual return on assets (2,427,768) (1,142,287) (1,546,325) Net amortization and deferral 1,421,028 269,135 689,947 - --------------------------------------------------------------------------------------------- Total net pension cost 405,640 442,071 179,625 Amounts capitalized as construction cost (33,942) (38,860) (30,740) - --------------------------------------------------------------------------------------------- Amount charged to expense $371,698 $403,211 $148,885 ============================================================================================= The following schedule sets forth the funding status of the pension plan at December 31, 1997 and 1996. ACCRUED PENSION COST - ------------------------------------------------------------------------------------ At December 31, 1997 1996 - ------------------------------------------------------------------------------------ Vested $7,615,194 $6,834,661 Non-vested 123,255 139,483 - ------------------------------------------------------------------------------------ Total accumulated benefit obligation 7,738,449 6,974,144 ==================================================================================== Plan assets at fair value $13,592,699 $10,720,514 Projected benefit obligation (11,534,355) (10,265,987) - ------------------------------------------------------------------------------------ Plan assets less projected benefit obligation 2,058,344 454,527 Unrecognized net gain (4,038,679) (2,820,957) Unamortized net assets from adoption of SFAS No. 87 (198,326) (141,579) - ------------------------------------------------------------------------------------ Accrued pension cost ($2,178,661) ($2,508,009) ==================================================================================== Assumptions: Discount rate 7.25% 7.25% Average increase in future compensation levels 4.75% 4.75% Expected long-term rate of return on assets 8.50% 8.50% - ------------------------------------------------------------------------------------ Other Post-retirement Benefits The Company sponsors a defined benefit post-retirement health care and life insurance plan that covers substantially all natural gas and corporate employees. The Company had deferred approximately $126,000, which represented the difference between the Maryland divisions SFAS No. 106 expense and its actual pay-as-you-go cost. The amount is being amortized over five years starting in 1995. The unamortized balance is $78,000 at December 31, 1997. POST-RETIREMENT COST - --------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 - --------------------------------------------------------------------------------------------- Service cost $3,287 $2,820 $1,827 Interest cost on APBO 60,221 54,651 59,706 Amortization of transition obligation over 20 years 29,413 27,859 27,859 - --------------------------------------------------------------------------------------------- Net periodic post-retirement benefit cost 92,921 85,330 89,392 Amount capitalized as construction cost (16,274) (16,672) (14,010) Amount amortized (deferred) 25,254 25,254 (20,561) - --------------------------------------------------------------------------------------------- Amount charged to expense $101,901 $93,912 $54,821 ============================================================================================= ACCRUED POST-RETIREMENT LIABILITY - ------------------------------------------------------------------------------------ At December 31, 1997 1996 - ------------------------------------------------------------------------------------ Accumulated post-retirement benefit obligation: Retirees $621,203 $567,599 Fully eligible active employees 145,356 137,378 Other active 102,340 86,894 - ------------------------------------------------------------------------------------ Total accumulated post-retirement benefit obligation 868,899 791,871 Unrecognized transition obligation (245,154) (273,013) Unrecognized net (loss) gain (147,422) (67,155) - ------------------------------------------------------------------------------------ Accrued post-retirement liability $476,323 $451,703 ==================================================================================== Assumption: Discount rate 7.25% 7.25% - ------------------------------------------------------------------------------------ The health care inflation rate for 1997 is assumed to be 9.5%. This rate is projected to gradually decrease to an ultimate rate of 5% by the year 2007. 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 $98,650 as of January 1, 1998, and would increase the aggregate of the service cost and interest cost components of net periodic post-retirement benefit cost for 1998 by approximately $8,293. Retirement Savings Plan The Company sponsors a Retirement Savings Plan, a 401(k) plan ("Plan"), that provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions based upon eligible compensation. The Company makes a contribution equal to 60% or 100% of each participants pre-tax contributions, not to exceed 6%, of the participants eligible compensation for the plan year. The Companys contributions totaled $404,406, $353,350 and $301,794 for the years ended December 31, 1997, 1996 and 1995, respectively. As of December 31, 1997, there are 56,374 shares reserved to fund future contributions to the Plan. J. Environmental Commitments and Contingencies The Company currently is participating in the investigation, assessment or remediation of three former gas manufacturing plant sites located in different jurisdictions, including the exploration of corrective action options to remove environmental contaminants. The Company has accrued liabilities for two of these sites, the Dover Gas Light and Salisbury Town Gas Light sites. The Dover sites remediation costs are estimated at $4.2 million in the Record of Decision ("ROD") issued by the Environmental Protection Agency ("EPA") in January 1998. The Company and General Public Utilities Corporation, Inc. ("GPU") were ordered by the EPA to fund or implement the ROD. During 1998, the Company will commence with the design phase. The Company has adjusted the liability associated with the Dover site from $6.0 million to $4.2 million. The Company has also recorded a regulatory asset in the same amount. The previous accrual of $6.0 million was based on the original Record of Decision issued by the EPA in 1994. The Company initiated litigation against one of the other potentially responsible parties for contribution to the remedial costs incurred by Chesapeake in connection with complying with the ROD. At this time, management cannot predict the outcome of the litigation or the amount of proceeds to be received, if any. Management believes that the Company will be equitably entitled to contribution from other responsible parties for a portion of the expenses to be incurred in connection with the remedies selected in the ROD. Management also believes that the amounts not so contributed will be recoverable in the Companys rates. In cooperation with the Maryland Department of the Environment ("MDE"), in 1996 the Company completed construction and began remediation procedures at the Salisbury site. In addition, the Company began quarterly reporting of the remediation and monitoring results to the MDE. The Company has established a liability with respect to the Salisbury site of $665,000 as of December 31, 1997. This amount is based on the estimated operating costs of the remediation facilities. A corresponding regulatory asset has been recorded, reflecting the Companys belief that costs incurred will be recoverable in rates. Portions of the liability payouts for the Dover and Salisbury sites are expected to be over 30 and five-year periods, respectively. In addition, the Company has a site located in the state of Florida, which is currently being evaluated. At this time, no estimate of liability can be made. It is managements opinion that any unrecovered current costs and any other future costs incurred will be recoverable through future rates or sharing arrangements with other responsible parties. ENVIRONMENTAL COSTS INCURRED - ------------------------------------------------------------------------------------ At December 31, 1997 1996 - ------------------------------------------------------------------------------------ Delaware $5,317,380 $4,423,843 Maryland 2,368,168 2,187,810 Florida 692,391 660,828 - ------------------------------------------------------------------------------------ Total costs incurred 8,377,939 7,272,481 Less: Amounts, net of insurance proceeds, which have been approved for ratemaking treatment (7,319,496) (6,396,108) - ------------------------------------------------------------------------------------ Amounts pending ratemaking recovery 1,058,443 876,373 ==================================================================================== K. Commitments and Contingencies FERC PGA In the third quarter of 1995, Eastern Shore reached a settlement with the FERC pertaining to Eastern Shores PGA methodology. Accordingly, Eastern Shore reversed a large portion of the estimated liability that had been accrued. This reversal contributed $1,385,000 to pre-tax earnings, or $833,000 to after-tax earnings, for the period. Other Commitments and Contingencies 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 of the Company. L. 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 Companys business, there are substantial variations in operations reported on a quarterly basis. - ----------------------------------------------------------------------------------- For the Quarters Ended: March 31 June 30 September 30 December 31 - ----------------------------------------------------------------------------------- 1997 Operating Revenue $43,645,111 $24,805,428 $19,910,307 $34,413,746 Operating Income 4,104,438 1,409,752 25,177 3,019,603 Net Income 3,366,113 692,841 (739,193) 2,363,185 Earnings per share: Basic 0.76 0.16 (0.17) 0.53 Diluted 0.72 0.15 (0.17) 0.51 - ----------------------------------------------------------------------------------- 1996 Operating Revenue $49,026,542 $25,213,979 $19,637,074 $36,335,814 Operating Income 6,667,499 1,084,392 (160,422) 2,518,536 Net Income 6,000,157 486,311 (747,779) 1,866,226 Earnings per share: Basic 1.37 0.11 (0.17) 0.42 Diluted 1.30 0.11 (0.17) 0.41 - ----------------------------------------------------------------------------------- Operating Statistics - -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 1994 (1) 1993 (1) - -------------------------------------------------------------------------------------------------- Revenues (in thousands) Natural gas Residential $21,540 $18,256 $14,857 $15,228 $14,007 Commercial 16,557 14,339 11,383 11,594 10,837 Industrial 22,625 28,546 36,898 32,718 31,622 Sale for resale 23,010 24,481 12,459 9,586 5,242 Transportation 4,212 3,369 2,993 2,639 2,480 Other 162 1,102 515 (50) 193 - -------------------------------------------------------------------------------------------------- Total natural gas revenues 88,106 90,093 79,105 71,715 64,381 Propane (1) 26,994 33,179 25,346 17,789 16,908 Other 7,675 6,941 7,345 6,173 4,584 - -------------------------------------------------------------------------------------------------- Total revenues $122,775 $130,213 $111,796 $95,677 $85,873 ================================================================================================== Volumes Natural gas deliveries (in MMCF) Residential 1,753 1,987 1,686 1,665 1,596 Commercial 2,138 2,092 1,792 1,771 1,676 Industrial 5,946 7,501 13,622 10,752 9,308 Sale for resale 872 1,065 990 998 984 Transportation 12,559 12,096 11,131 7,542 5,880 - -------------------------------------------------------------------------------------------------- Total natural gas deliveries 23,268 24,741 29,221 22,728 19,444 ================================================================================================== Propane (in thousands of gallons) (1) 26,682 29,975 26,184 18,395 17,250 ================================================================================================== Customers Natural gas Residential 31,277 30,349 29,285 28,260 27,312 Commercial 4,288 4,151 4,030 3,879 3,759 Industrial (2) 229 210 212 204 196 Sale for resale (2) 3 3 3 3 3 - -------------------------------------------------------------------------------------------------- Total natural gas customers 35,797 34,713 33,530 32,346 31,270 Propane 33,998 32,218 31,372 22,180 21,622 - -------------------------------------------------------------------------------------------------- Total customers 69,795 66,931 64,902 54,526 52,892 ================================================================================================== <FN> (1) 1994 and 1993 have not been restated to include the business combination with Tri-County Gas Company, Inc. (2) 1994 amounts exclude $2,895,000 in revenue and nine million gallons of propane sold to one large wholesale customer. (3) Includes transportation customers. </FN> Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure None PART III Item 10. Directors and Executive Officers of the Registrant Information pertaining to the Directors of the Company is incorporated herein by reference to the Proxy Statement, under "Information Regarding the Board of Directors and Nominees", dated and to be filed on or before March 30, 1998 in connection with the Companys Annual Meeting to be held on May 19, 1998. 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 Item 10 of Part I of this Form 10-K under "Executive Officers of the Registrant." Item 11. Executive Compensation This information is incorporated herein by reference to the Proxy Statement, under "Report on Executive Compensation", dated and to be filed on or before March 30, 1998 in connection with the Companys Annual Meeting to be held on May 19, 1998. Item 12. Security Ownership of Certain Beneficial Owners and Management This information is incorporated herein by reference to the Proxy Statement, under "Beneficial Ownership of the Companys Securities", dated and to be filed on or before March 30, 1998 in connection with the Companys Annual Meeting to be held on May 19, 1998. Item 13. Certain Relationships and Related Transactions This information is incorporated herein by reference to the Proxy Statement, under "Beneficial Ownership of the Companys Securities", dated and to be filed on or before March 30, 1998 in connection with the Companys Annual Meeting to be held on May 19, 1998. PART IV Item 14. Financial Statements, Financial Statement Schedules, and Exhibits and Reports on Form 8-K (a) The following documents are filed as a part of this report: 1. Financial Statements: - Accountants Report dated February 12, 1998 of Coopers & Lybrand L.L.P., Independent Accountants - Consolidated Statements of Income for each of the three years ended December 31, 1997, 1996 and 1995 - Consolidated Balance Sheets at December 31, 1997 and December 31, 1996 - Consolidated Statements of Cash Flows for each of the three years ended December 31, 1997, 1996 and 1995 - Consolidated Statements of Common Stockholders Equity for each of the three years ended December 31, 1997, 1996 and 1995 - Consolidated Statements of Income Taxes for each of the three years ended December 31, 1997, 1996 and 1995 - Notes to Consolidated Financial Statements 2. The following additional information for the years 1997, 1996 and 1995 is submitted herewith: - 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 None. (c) Exhibits Exhibit 2(a) - Agreement and Plan of Merger by and between Chesapeake Utilities Corporation and Tri-County Gas Company, Inc., filed on the Companys Form 8-K, File No. 001-11590 on January 13, 1997, is incorporated herein by reference. Exhibit 3(a) - Amended Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3 of the Companys Quarterly Report on Form 10-Q for the period ended June 30, 1995, File No. 001-11590. Exhibit 3(b) - Amended Bylaws of Chesapeake Utilities Corporation, effective July 11, 1997, are incorporated herein by reference to Exhibit 3 of the Quarterly Report on Form 10-Q for the period ended June 30, 1997, File No. 001-11590. Exhibit 4(a) - Form of Indenture between the Company and Boatmens Trust Company, Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of the Companys Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989. Exhibit 4(b) - Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Companys Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593. Exhibit 4(c) - Directors Stock Compensation Plan adopted by Chesapeake Utilities Corporation in 1995 is incorporated herein by reference to the Companys Proxy Statement dated April 17, 1995 in connection with the Companys Annual Meeting held in May 1995. 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 10(a) - Service Agreement dated November 1, 1989, by and between Transcontinental Gas Pipe Line Corporation and Eastern Shore Natural Gas Company, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1989, File No. 0-593. Exhibit 10(b) - Service Agreement dated November 1, 1989, by and between Columbia Gas Transmission Corporation and Eastern Shore Natural Gas Company, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1989, File No. 0-593. Exhibit 10(c) - Service Agreement for General Service dated November 1, 1989, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593. Exhibit 10(d) - Service Agreement for Preferred Service dated November 1, 1989, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593. Exhibit 10(e) - Service Agreement for Firm Transportation Service dated November 1, 1989, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593. Exhibit 10(f) - Form of Service Agreement for Interruptible Sales Services dated May 11, 1990, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593. Exhibit 10(g) - Interruptible Transportation Service Agreement dated February 23, 1990, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593. Exhibit 10(h) - Interruptible Transportation Service Agreement dated November 30, 1990, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593. Exhibit 10(i) - Executive Employment Agreement dated March 26, 1997, by and between Chesapeake Utilities Corporation and each Ralph J. Adkins and John R. Schimkaitis is incorporated herein by reference to Exhibit 10 to the Companys Quarterly Report on Form 10-Q for the period ended June 30, 1997, File No. 001-11590. Exhibit 10(j) - 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 filed herewith. Exhibit 10(k) - Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 1992, is incorporated herein by reference to Exhibit 10 to the Companys Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-593. Exhibit 10(l) - Chesapeake Utilities Corporation Performance Incentive Plan dated January 1, 1992, is incorporated herein by reference to the Companys Proxy Statement dated April 20, 1992, in connection with the Companys Annual Meeting held on May 19, 1992. Exhibit 10(m) - Form of Stock Option Agreement dated January 1, 1998, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Stephen C. Thompson, William C. Boyles, Philip S. Barefoot, Jeremy D. West, William P. Schneider and James R. Schneider, is filed herewith. 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. 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/ RALPH J. ADKINS ------------------------------- Ralph J. Adkins Chairman of the Board and Chief Executive Officer Date: March 20, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /S/ RALPH J. ADKINS /S/ JOHN R. SCHIMKAITIS - ------------------------------ ------------------------------ Ralph J. Adkins, Chairman of the John R. Schimkaitis, Board, President, Chief Executive Chief Operating Officer Officer and Director and Director Date: March 20, 1998 Date: March 20, 1998 /S/ MICHAEL P. MCMASTERS /S/ RICHARD BERNSTEIN - ------------------------------ ------------------------------ Michael P. McMasters, Vice President, Richard Bernstein, Director Chief Financial Officer and Treasurer (Principal Financial Officer) Date: March 20, 1998 Date: March 20, 1998 /S/ WALTER J. COLEMAN /S/ JOHN W. JARDINE, JR. - ------------------------------ ------------------------------ Walter J. Coleman, Director John W. Jardine, Jr., Director Date: March 20, 1998 Date: March 20, 1998 /S/ RUDOLPH M. PEINS, JR. /S/ ROBERT F. RIDER - ------------------------------ ------------------------------ Rudolph M. Peins, Jr., Director Robert F. Rider, Director Date: March 20, 1998 Date: March 20, 1998 /S/ JEREMIAH P. SHEA /S/ WILLIAM G. WARDEN, III - ------------------------------ ------------------------------ Jeremiah P. Shea, Director William G. Warden, III, Director Date: March 20, 1998 Date: March 20, 1998 CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ---------------------------------------------------------------------------------------------------------------- ----- Additions ----- Balance at Charged to Charged to Balance at Beginning Costs and Other End Description of Period Expense Accounts Deductions of Period - ---------------------------------------------------------------------------------------------------------------- Valuation accounts deducted from assets to which they apply for doubtful accounts receivable: 1997 . . . . . . . . . . . . . . $392,412 $203,624 $68,038 (B) ($332,299) (A) $331,775 1996 . . . . . . . . . . . . . . $309,955 $364,622 $55,631 (B) ($337,796) (A) $392,412 1995 . . . . . . . . . . . . . . $202,152 $328,012 $43,151 (B) ($263,360) (A) $309,955 Notes: (A) Uncollectible accounts charged off. (B) Recoveries.