ITEM 1. BUSINESS
Chesapeake has made statements in this Form 10-K that are considered to be forward-looking statements. These statements are not matters of historical fact. Sometimes they contain words such as "believes," "expects," "intends," "plans," "will," or "may," and other similar words of a predictive nature. These statements relate to matters such as customer growth, changes in revenues or margins, capital expenditures, environmental remediation costs, regulatory approvals, market risks associated with the Company's propane marketing operation, the competitive position of the Company and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. See Item 7 under the heading "Management's Discussion and Analysis -- Cautionary Statement."
(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 marketing, advanced information services and other related businesses.
Chesapeake's three natural gas distribution divisions serve approximately 40,800 residential, commercial and industrial customers in southern Delaware, Maryland's Eastern Shore and Florida. The Company's natural gas transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"), operates a 281-mile interstate pipeline system that transports gas from various points in Pennsylvania to the Company's Delaware and Maryland distribution divisions, as well as to other utilities and industrial customers in Delaware and on the Eastern Shore of Maryland. The Company's propane distribution operation serves approximately 35,300 customers in southern Delaware, the Eastern Shore of both Maryland and Virginia and parts of Florida. The advanced information services segment provides consulting, custom programming, training and development tools for national and international 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 -- Note C."
(c) NARRATIVE DESCRIPTION OF BUSINESS
The Company is engaged in three primary business activities: natural gas distribution and transmission, propane distribution and marketing, and advanced information services. In addition to the three primary groups, Chesapeake has four subsidiaries engaged in other service-related businesses.
(i) (a) NATURAL GAS DISTRIBUTION AND TRANSMISSION
GENERAL
Chesapeake distributes natural gas to approximately 40,900 residential, commercial and industrial customers in southern Delaware, the Salisbury and Cambridge, Maryland areas on Maryland's Eastern Shore, and Florida. These activities are conducted through three utility divisions, one division in Delaware, another in Maryland and a third division in Florida. The Company offers natural gas supply management services in the state of Florida under the name of Peninsula Energy Services Company ("PESCO").
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions ("Delaware", "Maryland" or "the divisions") serve an average of approximately 30,885 customers, of which approximately 30,730 are residential and commercial customers purchasing gas primarily for heating purposes and the remainder are industrial customers. For the year, residential and commercial customers account for approximately 64% of the volume delivered by the
divisions and 69% of the divisions' revenue. The divisions' industrial customers purchase gas, primarily on an interruptible basis, for a variety of manufacturing, agricultural and other uses. Most of Chesapeake's customer growth in these divisions comes from new residential construction using gas heating equipment.
Florida. The Florida division distributes natural gas to approximately 9,953 residential and commercial and 88 industrial customers in Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto and Citrus Counties. Currently 42 of the division's 88 industrial customers, which purchase and transport gas on a firm and interruptible basis, account for approximately 89% of the volume delivered by the Florida division and 39% of the revenues. These customers are primarily engaged in the citrus and phosphate industries and in electric cogeneration. The Company's Florida division, through Peninsula Energy Services Company also provides natural gas supply management services to 19 customers.
Eastern Shore. The Company's wholly owned transmission subsidiary, Eastern Shore, operates an interstate natural gas pipeline and provides open access transportation services for affiliated and non-affiliated companies through an integrated gas pipeline extending from southeastern Pennsylvania to Delaware and the Eastern Shore of Maryland. Eastern Shore also provides contract storage services as a sales service for system balancing purposes ("swing gas"). Eastern Shore's rates are subject to regulation by the Federal Energy Regulatory Commission ("FERC").
ADEQUACY OF RESOURCES
General. The Delaware and Maryland divisions have firm and interruptible contracts with four interstate "open access" pipelines including Eastern Shore. The divisions are directly interconnected with Eastern Shore and services upstream of Eastern Shore are contracted with Transco Gas Pipeline Corporation ("Transco"), Columbia Gas Transmission ("Columbia") and Columbia Gulf Transmission Company ("Gulf"). The divisions use their firm transportation supply sources to meet a significant percentage of their projected demand requirements. In order to meet the difference between firm supply and firm demand, peak-shaving (Delaware and Maryland divisions inject propane into their system which increases the BTU and the level of natural gas) and purchases natural gas 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 the availability of gas supply to the Delaware and Maryland divisions is adequate under existing arrangements to meet customer's needs.
Delaware. Delaware's 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, with provisions to continue from year to year, subject to six (6) months notice for termination.
Delaware's contracts with Columbia include: (a) firm transportation capacity of 852 Dt per day, which expires in 2014; (b) firm transportation capacity of 1,132 Dt per day, which expires in 2017; (c) firm transportation capacity of 549 Dt per day, which expires in 2018; (d) firm transportation capacity of 899 per day, which expires in 2019; (e) firm storage service providing a peak day entitlement of 6,193 Dt and a total capacity of 298,195 Dt, which expires in 2014; and (f) firm storage service, providing a peak day entitlement of 635 Dt and a total capacity of 57,139 Dt, which expires in 2017; (g) firm storage service providing a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires in 2018; and (h) firm storage service providing a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires in 2019. Delaware's contracts with Columbia for storage-related transportation provide quantities that are equivalent to the peak day entitlement for the period of October through March and are equivalent to fifty percent (50%) of the peak day entitlement for the period of April through September. The terms of the storage-related transportation contracts mirror the storage services that they support.
Delaware's contract with Gulf, which expires in 2004, provides firm transportation capacity of 868 Dt per day for the period November through March and 798 Dt per day for the period April through October.
Delaware's contracts with Eastern Shore include: (a) firm transportation capacity of 28,425 Dt per day for the period December through February, 27,203Dt per day for the months of November, March and April, and 18,127 Dt per day for the period May through October, with various expiration dates ranging from 2004 to 2017; (b) firm storage capacity under Eastern Shore's 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 Shore's 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 Shore's Rate Schedule LGA providing a peak day entitlement of 911 Dt and a total capacity of 5,708 Dt, which expires in 2006. Delaware's firm transportation contracts with Eastern Shore also include Eastern Shore's provision of swing transportation service. This service includes: (a) firm transportation capacity of 1,846 Dt per day on Transco's pipeline system, retained by Eastern Shore, in addition to Delaware's Transco capacity referenced earlier and (b) an interruptible storage service under Transco's Rate Schedule ESS that supports a swing supply service provided under Transco's Rate Schedule FS.
Delaware currently has contracts for the purchase of firm natural gas supply with four suppliers. These supply contracts provide the availability of a maximum firm daily entitlement of 19,700 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore under Delaware's transportation contracts. The gas purchase contracts have various expiration dates and daily quantities may vary from day to day and month to month.
Maryland. Maryland's contracts with Transco include: (a) firm transportation capacity of 4,738 Dt per day, which expires in 2005; (b) firm transportation capacity of 155 Dt per day for December through February, expiring in 2006; and (c) firm storage service providing a total capacity of 33,120 Dt, with provisions to continue from year to year, subject to six months notice for termination.
Maryland's contracts with Columbia include: (a) firm transportation capacity of 442 Dt per day, which expires in 2014; (b) firm transportation capacity of 908 Dt per day, which expires in 2017; (c) firm transportation capacity of 350 Dt per day, which expires in 2018; (d) firm storage service providing a peak day entitlement of 3,142 Dt and a total capacity of 154,756 Dt, which expires in 2014; and (e) firm storage service providing a peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which expires in 2017. Maryland's contracts with Columbia for storage-related transportation provide quantities that are equivalent to the peak day entitlement for the period October through March and are equivalent to fifty percent (50%) of the peak day entitlement for the period April through September. The terms of the storage-related transportation contracts mirror the storage services that they support.
Maryland's contract with Gulf, which expires in 2004, provides firm transportation capacity of 590 Dt per day for the period November through March and 543 Dt per day for the period April through October.
Maryland's contracts with Eastern Shore include: (a) firm transportation capacity of 13,378 Dt per day for the period December through February, 12,654 Dt per day for the months of November, March and April, and 8,093 Dt per day for the period May through October; (b) firm storage capacity under Eastern Shore's 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 Shore's 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 Shore's Rate Schedule LGA providing a peak day entitlement of 569 Dt and a total capacity of 3,560 Dt, which expires in 2006. Maryland's firm transportation contracts with Eastern Shore also include Eastern Shore's provision of swing transportation service. This service includes: (a) firm transportation capacity of 969 Dt per day on Transco's pipeline system, retained by Eastern Shore, in addition to Maryland's Transco capacity referenced earlier and (b) an interruptible storage service under Transco's Rate Schedule ESS that supports a swing supply service provided under Transco's Rate Schedule FS.
Maryland currently has contracts for the purchase of firm natural gas supply with four suppliers. These contracts provide the availability of a maximum firm daily entitlement of 9,000 Dt and the supplies are transported by
Transco, Columbia, Gulf and Eastern Shore under Maryland's transportation contracts. The gas purchase contracts have various expiration dates and daily quantities may vary from day to day and month to month.
Florida. The Florida division receives transportation service from Florida Gas Transmission Company ("FGT"), a major interstate pipeline. Chesapeake has contracts with FGT for: (a) daily firm transportation capacity of 27,579 Dt in November through April, 21,200 Dt in May through September, and 27,416 Dt in October under FGT's firm transportation service FTS-1 rate schedule; (b) daily firm transportation capacity of 5,100 Dt in May through October, and 8,100 in November through April under FGT's firm transportation service FTS-2 rate schedule. The firm transportation contract FTS-1 expires on August 1, 2010 with the Company retaining a right of first refusal on this capacity. The firm transportation contract FTS-2 expires on March 1, 2015. Chesapeake has requested and been approved for a turnback of all but 1,000 Dt per day year round of it's FTS-2 capacity in two increments. These turnbacks coincide with the in service dates of FGT's Phase 4 Project scheduled to be in service in May 2001, and the Phase 5 Project scheduled to be in service in the second quarter of 2002. 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. The Company believes that the availability of gas supply to the Florida division is adequate under existing arrangements to meet customer's needs.
Eastern Shore. Eastern Shore has 4,916 thousand cubic feet ("Mcf") of firm transportation capacity under Rate Schedule FT under contract with Transco, which expires in 2005. Eastern Shore also has 7,046 Mcf of firm peak day entitlements and total storage capacity of 278,264 Mcf under Rate Schedules GSS, LSS and LGA, respectively, under contract with Transco. The GSS and LSS contracts expire in 2013 and the LGA contract expires in 2006.
Eastern Shore also has firm storage service under Rate Schedule FSS and firm storage transportation capacity under Rate Schedule SST under contract with Columbia. These contracts, which expire in 2004, provide for 1,073 Mcf of firm peak day entitlement and total storage capacity of 53,738 Mcf.
Eastern Shore has retained the firm transportation capacity and firm storage services described above in order to provide swing transportation service to those customers that requested such service.
COMPETITION
See discussion on competition in Item 7 under the heading "Management's Discussion and Analysis -- Competition."
RATES AND REGULATION
General. Chesapeake's natural gas distribution divisions are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions with respect to various aspects of the Company's business, including the rates for sales to all of their customers in each jurisdiction. All of Chesapeake's firm distribution rates are subject to purchased gas adjustment clauses, which match revenues with gas costs and normally allow eventual full recovery of gas costs. Adjustments under these clauses require periodic filings and hearings with the relevant regulatory authority, but do not require a general rate proceeding. Rates on interruptible sales by the Florida division are also subject to purchased gas adjustment clauses.
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.
Management monitors the rate of return in each jurisdiction in order to ensure the timely filing of rate adjustment applications.
REGULATORY PROCEEDINGS
Delaware. In September 1998, Chesapeake's Delaware division filed an application with the Delaware Public Service Commission ("DPSC") to propose certain rate design changes to its existing margin sharing mechanism which was approved in Chesapeake's last rate case.
The Company proposed certain rate design changes to its existing margin sharing mechanism in order to address the level of recovery of fixed distribution costs from the residential heating service customers and smaller commercial heating customers. The Company also proposed to change the existing margin sharing mechanism to take into consideration the appropriate treatment of margins achieved by the addition of new interruptible customers on the distribution system for which the Company makes additional capital investments
In March 1999, the Company, DPSC Staff and the Division of the Public Advocate settled all the issues in this matter and executed a proposed settlement agreement. The settlement allows the Company to increase or decrease the current margin sharing thresholds based on the actual level of recovery of fixed distribution costs from residential service heating and general service heating customers as compared to the level at which the base tariff rates were designed to recover in the last rate case. Per the settlement, the Company can implement an adjustment to the margin sharing thresholds if the weather is at least 6.5% warmer or colder than normal; however, the total increase or decrease in the amount of additional gross margin that the Company will retain or credit to the firm ratepayers cannot exceed a $500,000 cap.
Also, the Company will exclude the interruptible margins from the existing margin sharing mechanism for one specific interruptible customer on its distribution system for whom the Company made a capital investment to serve and currently has under a contract for interruptible service. Any additional margin retained for this customer will be included in the $500,000 cap mentioned above. The DPSC issued its final approval of the proposed settlement on May 25, 1999.
The Company earned or retained $500,000 of additional gross margin during 2000 as the Company met the requirements of the approved settlement in order to implement the approved mechanism.
Maryland. During the 1999 Maryland General Assembly legislative session, taxation of electric and gas utilities changed by the passage of The Electric and Gas Utility Tax Reform Act ("Tax Act"). Effective January 1, 2000, the Tax Act altered utility taxation to account for the restructuring of the electric and gas industries by either repealing and/or amending the existing Public Service Company Franchise Tax, Corporate Income Tax and Property Tax. Chesapeake submitted a regulatory filing with the Maryland Public Service Commission ("MPSC") on December 30, 1999 to implement new tariff sheets necessary to incorporate the changes necessitated by the passage of the Tax Act. The tariff revisions (1) would implement new base tariff rates to reflect the estimated state corporate income tax liability; (2) assess the new per unit distribution franchise tax; and (3) repeal specified portions of the tariff that related to the former 2% gross receipts tax.
On January 12, 2000, the Maryland Public Service Commission ("MPSC") issued an order requiring the Company to file new tariff sheets, with an effective date of January 12, 2000, to increase its natural gas delivery service rates by $82,763 on an annual basis to recover the estimated impact of the state corporate income tax. Also as part of the MPSC order, the Company was directed to recover the new distribution franchise tax of $0.0042 per Ccf as a separate line item charge on the customers' bills. On January 14, 2000, the Company filed new natural gas tariff sheets in compliance with the MPSC order.
Florida. On July 15, 1999, the Florida Division filed a Joint Petition with Tampa Electric / Peoples Gas System for approval of a territorial boundary agreement in Hillsborough, Polk and Osceola Counties. On November 10, 1999, the Florida Public Service Commission issued an order approving the terms and conditions of the agreement. The
agreement included the transfer of facilities in Hillsborough County owned by Chesapeake to Peoples Gas System and the transfer of facilities in Gilchrist and Union Counties owned by Peoples Gas System to Chesapeake. The transfers were made at the depreciated book value of the facilities.
On August 19,1999, the Florida Division filed a petition with the Florida Public Service Commission for approval of a gas transportation agreement with Citrosuco North America, Inc. located in Polk County, Florida. The Florida Public Service Commission approved the agreement on October 25, 1999. The agreement provides for the Florida Division to lease an 8-inch steel natural gas pipeline from Citrosuco and in return, the Florida Division will provide natural gas service under its CTS rate schedule as a special contract.
On January 28, 2000, the Florida Division filed a request for approval of a rate increase with the Florida Public Service Commission. An Order was issued on November 28, 2000 approving a rate increase of $1,251,900 that was 69% of the requested $1,826,569. A return on equity of 11.5% was approved with an overall rate of return of 8.6%. The new rates were effective December 7, 2000. In addition, all non-residential customers became eligible for transportation services. In order to transport, each customer with annual consumption less than 100,000 therms per year must aggregate into pools to meet certain established minimums for therm thresholds and number of customer per pool.
On October 17, 2000, the FPSC approved a special contract with Peace River Citrus in Desoto County. The agreement is for the construction of a 4" steel natural gas main extending from Florida Gas Transmission's new Phase IV pipeline in Desoto County approximately eight miles to the citrus processing plant near Arcadia.
Eastern Shore. In September 1998, Eastern Shore filed an application before the FERC requesting authorization to construct and operate a total of eight miles (4.5 miles in Pennsylvania and 3.5 miles in Delaware) of 16-inch pipeline looping on Eastern Shore's existing system and to install 1,085 horsepower of additional compression at its Delaware City compressor station. The purpose of these new facilities is to enable Eastern Shore to provide 16,540 dekatherms of additional firm transportation capacity on its system for two existing customers, Delmarva Power and Light Company and Star Enterprise. The expansion was completed during the fourth quarter of 1999. The project cost was approximately $7.0 million.
In March 1998, the FERC authorized Eastern Shore to replace 2.3 miles of 6-inch pipeline with 10-inch pipeline along Route 72 and Power Road, all in conjunction with a Delaware Department of Transportation highway relocation project. In September 1998, Eastern Shore filed an amendment requesting that the FERC authorize an increase in the diameter of the previously approved 2.3-mile pipeline from 10 inches to 16 inches. This proposal was approved by the FERC in October 1998. Construction was completed during 1999.
On December 9, 1999, Eastern Shore filed an application before the FERC requesting authorization for the following: (1) construct and operate approximately two miles of 16-inch mainline looping in Pennsylvania, (2) abandonment of one mile of 2-inch lateral in Delaware and Maryland and replacement of the segment with a 4-inch lateral, (3) construct and operate approximately ten miles of 6-inch mainline extension in Delaware, (4) construct and operate five delivery points on the new 6-inch mainline extension in Delaware, and (5) install certain minor auxiliary facilities at the existing Daleville compressor station in Pennsylvania. The purpose of the construction was to enable Eastern Shore to provide 7,065 Dts of additional daily firm service capacity on Eastern Shore's system. The FERC approved Eastern Shore's application on April 28, 2000. The two miles of 16-inch mainline looping in Pennsylvania and the one mile of 4-inch lateral replacement in Delaware and Maryland were completed and placed in service during the fourth quarter of 2000. The ten miles of 6-inch mainline extension and associated delivery points in Delaware are expected to be completed and placed into service during the second quarter of 2001.
On December 22, 2000, Eastern Shore filed an application before the FERC requesting authorization for the following: (1) to construct and operate six miles of 16-inch pipeline looping in Pennsylvania and Maryland, (2)
install 3,330 horsepower of additional capacity at the existing Daleville compressor station and (3) construct and operate a new delivery point in Chester County, Pennsylvania. The purpose of the construction is to enable Eastern Shore to provide 19,800 Dts of additional daily firm service capacity on its system. The proposed expansion is targeted for completion by November 1, 2001 and is expected to cost approximately $12.5 million.
On January 4, 2001 FERC notified Eastern Shore that its December 22 application was deficient in that it did not conform to the Commission's minimum certificate filing requirements and was therefore rejected without prejudice to Eastern Shore filing a complete application. Eastern Shore re-filed a complete application on January 11, 2001.
(i) (b) PROPANE DISTRIBUTION AND MARKETING
GENERAL
Chesapeake's propane distribution group consists of (1) Sharp Energy, Inc. ("Sharp Energy"), a wholly owned subsidiary of Chesapeake, (2) Sharpgas, Inc. ("Sharpgas"), a wholly owned subsidiary of Sharp Energy, and (3) Tri-County Gas Company, Inc. ("Tri-County"), a wholly owned subsidiary of Chesapeake. The propane marketing group consists of Xeron, Inc. ("Xeron"), a wholly owned subsidiary of Chesapeake.
The Company's consolidated propane distribution operation served approximately 35,600 propane customers on the Delmarva Peninsula and delivered approximately 28 million retail and wholesale gallons of propane during 2000.
In April 2000, Sharp Energy, Inc. started a propane distribution operation in West Palm Beach Florida doing business as Treasure Coast Propane.
In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeron markets propane to large independent and petrochemical companies, resellers and southeastern retail propane companies in the United States.
The propane distribution business is affected by many factors such as seasonality, the absence of price regulation and competition among local providers. The propane marketing business is affected by wholesale price volatility and the demand and supply of propane at a wholesale level.
Propane is a form of liquefied petroleum gas which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is a gas at normal 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 is significantly affected by seasonal variations, particularly the relative severity of winter temperatures, because of its use in residential and commercial heating.
ADEQUACY OF RESOURCES
The Company's propane distribution operations purchase propane primarily from suppliers, including major domestic oil companies and independent producers of gas liquids and oil. Supplies of propane from these and other sources are readily available for purchase by the Company. Supply contracts generally include minimum (not subject to a take-or-pay premiums) and maximum purchase provisions.
The Company's propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to the Company's bulk storage facilities. From these facilities, propane is delivered in portable cylinders or by "bobtail" trucks, owned and operated by the Company, to tanks located at the customer's premises.
Xeron has no physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.
COMPETITION
The Company's propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally local because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. 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.
Xeron competes against various marketers, many of which have significantly great resources and are able to obtain price or volumetric advantages over Xeron.
The Company's propane distribution and marketing activities are not subject to any federal or state pricing regulation. Transport operations are subject to regulations concerning the transportation of hazardous materials promulgated under the Federal Motor Carrier Safety Act, which is administered by the United States Department of Transportation and enforced by the various states in which such operations take place. Propane distribution operations are also subject to state safety regulations relating to "hook-up" and placement of propane tanks.
The Company's propane operations are subject to all operating hazards normally associated with the handling, storage and transportation of combustible liquids, such as the risk of personal injury and property damage caused by fire. The Company carries general liability insurance in the amount of $35,000,000 per occurrence, but there is no assurance that such insurance will be adequate.
(i) (c) ADVANCED INFORMATION SERVICES
GENERAL
Chesapeake's advanced information services segment consists of United Systems, Inc. ("USI"), a wholly owned subsidiary of the Company.
USI is based in Atlanta and 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, web development and customer software development for its client base, which includes many large domestic and international corporations.
COMPETITION
The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them than does the Company. In addition, changes in the advanced information services business are occurring rapidly, which could adversely impact the markets for the products and services offered by these businesses.
(i) (d) OTHER SUBSIDIARIES
Skipjack, Inc. ("Skipjack"), Eastern Shore Real Estate, Inc. and Chesapeake Investment Company are wholly owned subsidiaries of Chesapeake Service Company. Skipjack and Eastern Shore Real Estate, Inc. own and lease office buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is a Delaware affiliated investment company.
In March 1998, the Company acquired Sam Shannahan Well Co., based in Salisbury, Maryland, doing business as Tolan Water Service ("Tolan"). Tolan was a privately owned EcoWater dealership serving 3,000 customers on the Delmarva Peninsula with divisions supporting residential, commercial and industrial water treatment. The 3000 customers are receiving recurring water treatment services during the year.
In 1999, the Company established Sharp Water, Inc., a wholly owned subsidiary of Chesapeake, which in November 1999, acquired EcoWater Systems of Michigan, Inc., doing business as Douglas Water Conditioning, an EcoWater dealership that has services the Detroit, Michigan area. This dealership provides water treat products and services.
In January 2000, the Company acquired Carroll Water Systems, Inc. of Westminster, Maryland. Carroll was a privately owned EcoWater dealership serving the suburban area of Baltimore, Maryland. This dealership provides water treat products and services
(II) SEASONAL NATURE OF BUSINESS
Revenues from the Company's residential and commercial natural gas sales and from its propane distribution activities are affected by seasonal variations, since the majority of these sales are to customers using the fuels for heating purposes. Revenues from these customers are accordingly affected by the mildness or severity of the heating season.
(III) CAPITAL BUDGET
A discussion of capital expenditures by business segment is included in Item 7 under the heading "Management Discussion and Analysis -- Liquidity and Capital Resources."
(IV) EMPLOYEES
As of December 31, 2000, Chesapeake had 542 employees, including 344 in natural gas and propane, 82 in advanced information services and 71 in water conditioning. The remaining 45 employees are considered general and administrative and include officers of the Company, treasury, accounting, information technology, human resources and other administrative personnel. The acquisition of Carroll Water Services added 15 employees.
(v) EXECUTIVE OFFICERS OF THE REGISTRANT
Information pertaining to the executive officers of the Company is as follows:
Ralph J. Adkins (age 58) Mr. Adkins is Chairman of the Board of Directors of Chesapeake. He has served as Chairman since 1997. Prior to January 1, 1999, Mr. Adkins served as Chief Executive Officer, a position he had held since 1990. During his tenure with Chesapeake Mr. Adkins has also served as President and Chief Executive Officer, President and Chief Operating Officer, Executive Vice President, Senior Vice President, Vice President and Treasurer of Chesapeake. He has been a director of Chesapeake since 1989.
John R. Schimkaitis (age 53) Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. He has served as President since 1997. His present term will expire on May 15, 2001. Prior to his new post, Mr. Schimkaitis has also served as President and Chief Operating Officer, Executive Vice President and Chief Operating Officer, Senior Vice President and Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer and Assistant Secretary of Chesapeake. He has been a director of Chesapeake since 1996.
Michael P. McMasters (age 42) 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 40) 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, Director of Gas Supply and Marketing, Superintendent of Eastern Shore and Regional Manager for the Florida distribution Operations.
William C. Boyles (age 43) Mr. Boyles is Vice President and Corporate Secretary of Chesapeake Utilities Corporation. Mr. Boyles has served as Corporate Secretary since 1998 and Vice President since 1997. He previously served as Director of Administrative Services, Director of Accounting and Finance, Treasurer, Assistant Treasurer and Treasury Department Manager. Prior to joining Chesapeake, he was employed as a Manager of Financial Analysis at Equitable Bank of Delaware and Group Controller at Irving Trust Company of New York.
ITEM 2.
ITEM 2. PROPERTIES
(a) GENERAL
The Company owns offices and operates facilities in the following locations: Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; and Winter Haven, Florida. Chesapeake rents office space in Dover, Delaware; Plant City, Jupiter, and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton, Salisbury, Westminster and Pocomoke, Maryland; Detroit, Michigan; Houston, Texas 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 Company's facilities can vary significantly due to the seasonal nature of the natural gas and propane distribution businesses.
(b) TOLAN WATER SERVICE
The Company owns and operates a resin regeneration facility in Salisbury, Maryland to serve approximately 3,000 exchange tank and meter water customers.
(c) NATURAL GAS DISTRIBUTION
Chesapeake owns over 645 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas and 547 miles of 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. Portions of the properties constituting Chesapeake's distribution system are encumbered pursuant to Chesapeake's First Mortgage Bonds.
(d) NATURAL GAS TRANSMISSION
Eastern Shore owns approximately 281 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 compressor stations are used to provide increased pressures required to meet demands on the system.
(e) PROPANE DISTRIBUTION AND MARKETING
The company's Delmarva-based propane distribution operation own bulk propane storage facilities with an aggregate capacity of approximately 1.9 million gallons at 32 plant facilities in Delaware, Maryland and Virginia, located on real estate they either own or lease. The company's Florida-based propane distribution operation owns one bulk propane storage facility with a capacity of 30,000 gallons. Xeron has no physical storage facilities or equipment to transport propane.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
(a) GENERAL
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.
(b) ENVIRONMENTAL
DOVER GAS LIGHT SITE
In 1984, the State of Delaware notified the Company that they had discovered contamination on a parcel of land it purchased in 1949 from Dover Gas Light Company, a predecessor gas company. The State also asserted that the Company was the responsible party for any clean-up and prospective environmental monitoring of the site. The Delaware Department of Natural Resources and Environmental Control ("DNREC") and Chesapeake conducted subsequent investigations and studies in 1984 and 1985. Soil and ground-water contamination associated with the operations of the former manufactured gas plant ("MGP"), the Dover Gas Light Company, were found on the property.
In February 1986, the State of Delaware entered into an agreement ("the 1986 Agreement") with Chesapeake whereby Chesapeake reimbursed the State for its costs to purchase an alternate property for construction of its Family Court Building and the State agreed to never construct on the property of the former MGP.
In October 1989, the Environmental Protection Agency ("EPA") listed the Dover Gas Light Site ("site") on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"). EPA named both the State of Delaware and the Company as potentially responsible parties ("PRPs") for the site.
The EPA issued a clean-up remedy for the site through a Record of Decision ("ROD") dated August 16, 1994. The remedial action selected by the EPA in the ROD addressed the ground-water and soil. The ground-water remedy included a combination of hydraulic containment and natural attenuation. The soil remedy included complete excavation of the former MGP property. The ROD estimated the costs of the 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 implement the remedy described in 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, including the State of Delaware, were not ordered to perform the ROD. Although notifying EPA of its objections to the Order, the Company agreed to comply. GPU informed EPA that it did not intend to comply with the Order and to this date has not complied with the EPA Order.
The Company performed field studies and investigations during 1995 and 1996 to further characterize the extent of contamination at the site. In April 1997, the EPA issued a fact sheet stating that the EPA was considering a modification to the soil remedy that would take into account the site's future land use restrictions, which prohibited future development on the site. The EPA proposed a soil remediation that included some on-site excavation of contaminated soils and use of institutional controls; EPA estimated the cost of its proposed soil remedy at $5.7 million. Additionally, the fact sheet acknowledged that the soil remedy described in the ROD would cost $10.5 million, instead of the $3.3 million estimated in the ROD, making the overall remedy cost $13.2 million ($10.5 million to perform the soil remedy and $2.7 million to perform the ground-water remediation).
In June 1997, the Company submitted a supplement to the focused feasibility study, which proposed an alternative soil remedy that would take into account the 1986 Agreement between Chesapeake and the State of Delaware restricting
future development at the site. On December 16, 1997, the EPA issued a ROD Amendment to modify the soil remedy to include: (1) excavation and off-site thermal treatment of the contents of the former subsurface gas holders; (2) implementation of soil vapor extraction; (3) pavement of the parking lot and (4) use of institutional controls restricting future development on the site. The overall clean-up cost of the site was estimated at $4.2 million ($1.5 million for soil remediation and $2.7 million for ground-water remediation).
During the fourth quarter of 1998, the Company completed the field work associated with the remediation of the gas holders (a major component of the soil remediation). During the first quarter of 1999, the Company submitted reports to the EPA documenting the gas holder remedial activities and requesting closure of the gas holder remedial project. In April 1999, the EPA approved the closure of the gas holder remediation project, certified that all performance standards for the project were met and no additional work was needed for that phase of the soil remediation. The gas holder remediation project was completed at a cost of $550,000.
During 1999, the Company completed the construction of the soil vapor extraction ("SVE") system (another major component of the soil remediation) and continued with the ongoing operation of the system at a cost of $250,000. In 2000, the Company operated the SVE system and during the last quarter of 2000, the Company submitted to the EPA their finding along with a request to discontinue the SVE operations. The Company is awaiting a response from the EPA on their request. If discontinuation of the SVE procedures is approved, the company will initiate final construction of a parking lot and proceed with a ground-water remedial program.
The Company's independent consultants have prepared preliminary cost estimates of two potentially acceptable alternatives to complete the ground-water remediation activities at the site. The costs range from a low of $390,000 in capital and $37,000 per year of operating costs for 30 years for natural attenuation to a high of $3.3 million in capital and $1.0 million per year in operating costs to operate a pump-and-treat / ground-water containment system. The pump-and-treat / ground-water containment system is intended to contain the MGP contaminants to allow the ground-water outside of the containment area to naturally attenuate. The operating cost estimate for the containment system is dependent upon the actual ground-water quality and flow conditions. The Company continues to believe that a ground-water containment system is not necessary for the MGP contaminants, that there is insufficient information to design an overall ground-water containment program and that natural attenuation is the appropriate remedial action for the MGP wastes.
The Company cannot predict what the EPA will require for the overall ground-water program, and accordingly, has not adjusted the $2.1 million accrued at December 31, 1999 for the Dover site, as well as a regulatory asset for an equivalent amount. Of this amount, $1.5 million is for ground-water remediation and $600,000 is for the remaining soil remediation. The $1.5 million represents the low end of the ground-water remedy estimates described above.
In March 1995, the Company commenced litigation against the State of Delaware for contribution to the remedial costs being incurred to implement 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: reaffirm the 1986 Agreement with Chesapeake not to construct on the MGP property and support the Company's proposal to reduce the soil remedy for the site; contribute $600,000 toward the cost of implementing the ROD and 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 response costs incurred by Chesapeake and a declaratory judgment as to GPU's liability for future costs at the site. In August 1997, the United States Department of Justice also filed a lawsuit against GPU seeking a Court Order to require GPU to participate in the site clean-up, pay penalties for GPU's failure to comply with the EPA Order, pay EPA's past costs and a declaratory judgment as to GPU's liability for future costs at the site. In November 1998, Chesapeake's case was consolidated with the United States' case against GPU. A case management order scheduled the trial for February 2001. In early February 2001, the Company and GPU reached a tentative settlement agreement that is subject to approval of the courts.
The Company is currently engaged in investigations related to additional parties who may be PRPs. Based upon these investigations, the Company will consider filings lawsuits against these other PRPs. The Company expects continued negotiations with PRPs in an attempt to resolve these matters.
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 remedial costs. The Company expects that it will be able to recover actual costs incurred (exclusive of carrying costs), which are not recovered from other responsible parties, through the ratemaking process in accordance with the existing environmental cost recovery rider provisions described below.
Through December 31, 2000, the Company has incurred approximately $8.4 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 1995, the Delaware Public Service Commission, authorized recovery of all unrecovered environmental costs incurred by a means of a rider (supplement) to base rates, applicable to all firm service customers. The costs, exclusive of carrying costs, would be recovered through a five-year amortization offset by the associated deferred tax benefit. The deferred tax benefit is the carrying cost savings associated with the timing of the deduction of environmental costs for tax purposes as opposed to financial reporting purposes. Each year an environmental surcharge rate is calculated to become effective December 1. The surcharge or rider rate is based on the amortization of expenditures through September of the filing year plus amortization of expenses from previous years. The rider is that it makes it unnecessary to file a rate case every year to recover expenses incurred. Through December 31, 2000, the unamortized balance and amount of environmental costs not included in the rider; effective January 1, 2001 were $3,048,000 and $335,000, respectively. With the rider mechanism established, it is management's opinion that these costs and any future cost, net of the deferred income tax benefit, will be recoverable in rates.
SALISBURY TOWN GAS LIGHT SITE
In cooperation with the Maryland Department of the Environment ("MDE"), the Company completed assessment of the Salisbury manufactured gas plant site, determining that there was localized ground-water contamination. During 1996, the Company completed construction and began Air Sparging and Soil-Vapor Extraction remediation procedures. Chesapeake has been reporting the remediation and monitoring results to the MDE on an ongoing basis since 1996. The Company has request approval from the MDE approval to shutdown the remediation procedures currently in place. The MDE approved a temporary shutdown and is evaluating a complete shutdown of the system.
The estimated cost of the remaining remediation is approximately $125,000 per year for operating expenses for a period of two years and capital costs of $50,000 to shut down the remediation process in year two. Based on these estimated costs, the Company adjusted both its liability and related regulatory asset to $175,000 on December 31, 2000, to cover the Company's projected remediation costs for this site. Through December 31, 2000, the Company has incurred approximately $2.7 million for remedial actions and environmental studies. Of this amount, approximately $972,000 of incurred costs have not been recovered through insurance proceeds or received ratemaking treatment. Chesapeake will apply for the recovery of these and any future costs in the next base rate filing with the Maryland Public Service Commission.
WINTER HAVEN COAL GAS SITE
Chesapeake has been working with the Florida Department of Environmental Protection ("FDEP") in assessing a coal gas site in Winter Haven, Florida. In May 1996, the Company filed an Air Sparging and Soil Vapor Extraction Pilot Study Work Plan for the Winter Haven site with the FDEP. The Work Plan described the Company's proposal to undertake an Air Sparging and Soil Vapor Extraction ("AS/SVE") pilot study to evaluate the site. After discussions with the FDEP, the Company filed a modified AS/SVE Pilot Study Work Plan, the description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the
FDEP approved the AS/SVE Pilot Study Work Plan, which the Company completed during the third quarter of 1999. Chesapeake has reported the results of the Work Plan to the FDEP for further discussion and review. In February 2001, the company filed a remedial action plan ("RAP") with the FDEP to address the contamination of the subsurface soil and groundwater in the northern portion of the site. The RAP included a cost estimate of $635,000 to complete this phase of the remediation. The Company is awaiting FDEP approval of the RAP. Once the FDEP approves the RAP, the Company will commence remediation procedures according to the RAP.
Based on the RAP filed with the FDEP, the Company has accrued $635,000 as of December 31, 2000 for the Florida site, as well as a regulatory asset for an equivalent amount. The Company has recovered all environmental costs incurred to date, approximately $781,000, through rates charged to customers. Additionally, the Florida Public Service Commission has allowed the Company to continue to recover amounts for future environmental costs that might be incurred. At December 31, 2000, Chesapeake had received $560,000 related to future costs, which might be incurred.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS
(a) COMMON STOCK PRICE RANGES, COMMON STOCK DIVIDENDS AND SHAREHOLDER INFORMATION:
The Company's Common Stock is listed on the New York Stock Exchange under the symbol "CPK." The high, low and closing prices of Chesapeake's Common Stock and dividends declared per share for each calendar quarter during the years 2000 and 1999 were as follows:
Indentures pertaining to the long-term debt of the Company and its subsidiaries each 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, 2000, the amounts available for future dividends permitted by the Series I covenant are $19.3 million.
At December 31, 2000, there were approximately 2,166 shareholders of record of the Common Stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(1) 1994 and prior years have not been restated to include the business combinations with Tri-County Gas Company, Inc., Tolan Water Service and Xeron, Inc. (2) For the years 1992 and 1991, the Company had discontinued operations, which had an effect on earnings of $73,500 and ($594,000), respectively.
(1) 1994 and prior years have not been restated to include the business combinations with Tri-County Gas Company, Inc., Tolan Water Service and Xeron, Inc. (2) Earnings per share amounts shown prior to 1995 represent primary and fully diluted earnings per share. (3) 1993 excludes earnings per share of $0.02 for the cummulative effect of change in accounting principle. (4) 1992 exclude earnings per share of $0.02 for discontinued operations. (4) 1991 excludes a loss per share of $0.17 for discontinued operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BUSINESS DESCRIPTION
Chesapeake Utilities Corporation is a diversified utility company engaged in natural gas distribution and transmission, propane distribution and wholesale marketing, advanced information services and other related businesses.
LIQUIDITY AND CAPITAL RESOURCES
Chesapeake's capital requirements reflect the capital-intensive nature of its business and are principally attributable to the construction program and the retirement of outstanding debt. The Company relies on cash generated from operations and short-term borrowing to meet normal working capital requirements and to temporarily finance capital expenditures. During 2000, net cash provided by operating activities was $8.4 million, cash used by investing activities was $21.8 million and cash provided by financing activities was $15.7 million. Based upon anticipated cash requirements in 2001, Chesapeake may refinance its short-term debt and fund capital requirements through the issuance of long-term debt. The timing of such an issuance is dependent upon the nature of the securities involved as well as current market and economic conditions.
The Board of Directors has authorized the Company to borrow up to $45.0 million from various banks and trust companies. As of December 31, 2000, Chesapeake had four unsecured bank lines of credit with two financial institutions, totaling $60.0 million, for short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. Two of the bank lines are committed. The outstanding balances of short-term borrowing at December 31, 2000 and 1999 were $25.4 million and $23.0 million, respectively. In 2000, Chesapeake used funds provided from operations and the issuance of long-term debt to fund capital expenditures and the increase in working capital associated with high gas costs. At December 31, 2000, the Company had an under-recovered purchased gas cost balance of $7.3 million, an increase of $6.1 million over the 1999 balance. The Company expects to recover these gas costs through the gas cost recovery mechanism in each of our regulated jurisdictions. In 1999, Chesapeake used cash provided by operations and short-term borrowing to fund capital expenditures.
During 2000, 1999 and 1998, capital expenditures were approximately $21.8 million, $25.1 million and $12.0 million, respectively. Capital expenditures in 2000 were slightly less than 1999 due to a reduced level of acquisition-related expenditures. The increase in capital expenditures in 1999 when compared to 1998 was primarily due to the expansion of both the Company's natural gas transmission pipeline and its Florida natural gas distribution system, as well as the acquisition of EcoWater Systems of Michigan. Chesapeake has budgeted $31.5 million for capital expenditures during 2001. This amount includes $25.8 million for natural gas distribution and transmission, $2.5 million for propane distribution and marketing, $500,000 for advanced information services and $2.7 million for general plant. The natural gas distribution expenditures are for expansion and improvement of facilities. Natural gas transmission expenditures are for improvement and expansion of the pipeline system to increase the level of service provided to existing customers and to provide service to customers in the City of Milford, Delaware. The propane expenditures are to support customer growth and for the replacement of equipment. The advanced information services expenditures are for computer hardware, software and related equipment. Expenditures for general plant include building improvements, computer software and hardware. Financing for the 2001 capital expenditure program is expected to be provided from short-term borrowing, cash provided by operating activities and the potential issuance of long-term debt. The capital expenditure program is subject to continuous review and modification. Actual capital expenditures may vary from the above estimates due to a number of factors including acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation and new growth opportunities.
Chesapeake has budgeted $1.9 million for environmental-related expenditures during 2001 and expects to incur additional expenditures in future years, a portion of which may need to be financed through external sources (see Note L to the Consolidated Financial Statements). 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, 2000, common equity represented 55.7 percent of permanent capitalization, compared to 64.0 percent in 1999 and 60.0 percent in 1998. Including short-term borrowing, the equity component of the Company's capitalization would have been 45.6 percent, 51.5 percent and 53.4 percent. The reduction in common equity as a percentage of permanent capitalization is primarily the result of the issuance of $20.0 million in long-term debt in 2000. Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company's regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as to the Company's investors.
FINANCING ACTIVITIES
During the past two years, the Company has utilized debt and equity financing for the purpose of funding capital expenditures and acquisitions.
In December 2000, Chesapeake completed a private placement of $20.0 million of 7.83% Senior Notes due January 1, 2015. The Company used the proceeds to repay short-term borrowing.
During 2000 and 1999, Chesapeake repaid approximately $2.7 million and $1.5 million of long-term debt, respectively. In connection with its Automatic Dividend Reinvestment and Stock Purchase Plan, Chesapeake issued 41,056, 36,319 and 32,925 shares of its common stock during the years of 2000, 1999 and 1998, respectively.
RESULTS OF OPERATIONS
Net income for 2000 was $7.5 million as compared to $8.3 million for 1999 and $5.3 million for 1998. The reduction in net income for 2000 is primarily due to a one-time after tax gain of $863,000 on the sale of the Company's investment in Florida Public Utilities Company recorded in the fourth quarter of 1999 (see Note E to the Consolidated Financial Statements). Exclusive of this gain, net income for 2000 increased by $81,000; however, earnings per share decreased $0.01 per share. This increase in net income for 2000 reflected improved pre-tax operating income for the natural gas business segment, offset by a reduction in contribution from the advanced information services and the propane gas segments. The natural gas segment benefited from cooler temperatures, a 5 percent growth in customers and increased transportation services. In terms of heating degree-days, temperatures for the year were 16 percent cooler than the prior year and 4 percent cooler than normal. The reduced contribution from the advanced information services segment reflects lower revenues from their traditional lines of business in 2000. The propane gas segment also benefited from cooler weather and an increase in marketing margins; however, higher operating expenses offset these increases. Also contributing to the increase in net income for 2000 was the Company's other business operations, which included a full year of operations from the water business acquisitions that occurred in late 1999 and early 2000.
The increase in net income for 1999 when compared to 1998 was due to increased contributions from all three business segments and the gain on the sale of Company's investment in Florida Public Utilities Company. The natural gas and propane segments each benefited from increased deliveries related to customer growth, averaging more than 4 percent in 1999, combined with cooler temperatures. In terms of heating degree-days, temperatures for 1999 were 10 percent cooler than 1998, but still 11 percent warmer than normal. The natural gas segment also benefited from an increase in transportation services. Pre-tax operating income for the advanced information services segment increased due to additional consulting projects and product sales.
Net income for 1999 includes an after-tax gain of $863,000 on the sale of the Company's investment in Florida Public Utilities Company, while net income for 1998 includes an after-tax gain of $750,000 from the restructuring of the
Company's retirement benefit plans (see Note J to the Consolidated Financial Statements). Both of these gains are shown in non-operating income on the Company's financial statements.
PRE-TAX OPERATING INCOME (IN THOUSANDS)
NATURAL GAS DISTRIBUTION AND TRANSMISSION
Pre-tax operating income increased $2.1 million from 1999 to 2000. The increase was the result of a $3.4 million increase in gross margin offset by a $1.3 million increase in operating expenses. The principal factors responsible for this increase in gross margin were:
- increased levels of firm transportation services;
- customer growth of 5 percent, primarily residential and commercial;
- greater deliveries due to temperatures in 2000 which were 16 percent cooler than 1999;
- an adjustment to the Delaware operation's margin sharing mechanism to compensate for warmer temperatures in late 1999 and early 2000; and
- interim rates in the Florida operation beginning in August 2000, with final rate increase taking effect in December 2000.
The customer growth and cooler temperatures resulted in a 14 percent increase in volumes delivered to residential and commercial customers. Under normal temperatures and customer usage, the Company estimates that 5 percent customer growth would generate an additional margin of $850,000 on an annual basis.
The principal costs that contributed to higher operating expenses were depreciation, compensation, marketing and employee benefits.
NATURAL GAS GROSS MARGIN SUMMARY (IN THOUSANDS)
Pre-tax operating income increased $1.5 million from 1998 to 1999. The increase was the result of a $3.5 million increase in gross margin offset by a $2.0 million increase in operating expenses. The principal factors responsible for this increase in gross margin were:
- increased levels of firm transportation services provided on a limited term basis, combined with the 1999 expansions;
- customer growth of 5.1 percent, primarily residential and commercial; and
- greater deliveries due to temperatures in 1999 which were 10 percent cooler than 1998.
These factors were somewhat offset by a decline in margins earned on volumes sold and transported to industrial customers served by the Florida operation.
The customer growth and cooler temperatures resulted in an 11 percent increase in volumes delivered to residential and commercial customers.
In 1998, the Company restructured its retirement benefit plans ("the benefit restructuring"), resulting in a one-time reduction of $1.2 million in consolidated pension expenses. Exclusive of the benefit restructuring, operating expenses increased by $1.0 million, or 4.7 percent. The principal costs that contributed to higher operating expenses were depreciation, compensation, marketing and employee benefits.
PROPANE DISTRIBUTION AND MARKETING
Pre-tax operating income for 2000 was $2.3 million compared to $2.6 million for 1999. This decrease of $308,000 was the result of an increase in operating expenses of $2.4 million offset by an increase of $2.1 million in gross margin.
Operating expenses were higher due to several initiatives the Company has undertaken to enhance long-term growth and the level of service we are providing our current customers. These initiatives include:
- the opening of a customer service/marketing office in a location convenient to retail shopping;
- an increase in merchandise sales and service activities;
- the extension of customer service hours; and
- three propane distribution start-ups in Florida.
The Company expects that some of the increased costs associated with these initiatives will decrease during the first half of 2001. However, the propane distribution start-ups in Florida may take up to three years to achieve profitability.
Gross margin was higher in 2000 due primarily to an increase of 102 percent in wholesale marketing margins earned. Additionally, gallons delivered by the distribution operation increased 2 percent. During 2000, marketing revenues increased by $73 million or 64 percent while margins increased $1.7 million over 1999. Wholesale marketing is a high volume, low margin business.
Pre-tax operating income for 1999 was $2.6 million compared to $1.0 million for 1998. This increase of $1.6 million was the result of a $1.9 million increase in gross margin, offset by an increase in operating expenses of $300,000. Gross margin was higher due to the following: gallons delivered by the distribution operation increased by 11 percent; margin earned per gallon sold by the distribution operation increased by 6 percent; and wholesale marketing margins earned increased by 28 percent.
The increase in gallons delivered by the distribution operation was directly related to temperatures, which were 10 percent cooler than 1998 coupled with a 3.4 percent growth in customers. In 1999, marketing revenues increased by $35
million or 44 percent over 1998, while margins increased $360,000. Operating expenses increased in 1999, primarily in the areas of incentive compensation, marketing and employee benefit costs.
ADVANCED INFORMATION SERVICES
The advanced information services segment contribution to consolidated pre-tax operating income for 2000 decreased $1.1 million or 77 percent from 1999. The decline is directly related to a reduction in revenues earned from the traditional information technology business. This reduction occurred primarily due to many clients implementing their year 2000 contingency plans in 1999, then significantly reducing their information technology expenditures in 2000. This reduction was somewhat offset by continued growth in revenue earned on web-related products and services. Operating expenses increased 5 percent, primarily in the areas of compensation, marketing and uncollectible accounts.
Pre-tax operating income for 1999 increased $154,000 or 12 percent over 1998. This increase was the result of revenue growth of $3.2 million or 31 percent, resulting in a gross margin increase of $1.3 million or 24 percent. The majority of revenue growth was due to increased web-related products and services. The increase in costs were primarily in the areas of compensation, marketing and uncollectible accounts.
INCOME TAXES
Income taxes were higher in 2000 when compared to 1999; however, pre-tax operating income for 2000 was slightly lower. The increase is the result of adjusting 1999 income tax expenses to recognize accumulated deferred income tax timing differences at the 35 percent federal rate. This was offset by a $238,000 reduction in the income tax accrual due to a reassessment of known tax exposures.
OTHER
Non-operating income was $361,000, $1,066,000 and $253,000 for the years 2000, 1999 and 1998, respectively. In 1999, the Company recognized a pre-tax gain of $1,415,000, or $863,000 after tax, on the sale of Chesapeake's investment in Florida Public Utilities Company (see Note E to the Consolidated Financial Statements). Exclusive of this transaction, non-operating income for 1999 was $203,000. The resulting decrease from 1998 was primarily due to a reduction in interest income.
INTEREST EXPENSE
Interest expense increased in 2000 due to a higher average short-term borrowing balance of $24.2 million in 2000 compared to $9.9 million in 1999. Also contributing to the increase in interest expense is a higher short-term borrowing rate of 6.89 percent in 2000, up from 5.51 percent in 1999.
REGULATORY ACTIVITIES
The Company's natural gas distribution operations are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions while the natural gas transmission operation is subject to regulation by the Federal Energy Regulatory Commission.
In January 2000, the Company filed a request for approval of a rate increase with the Florida Public Service Commission. In November 2000, an order was issued approving a rate increase of $1.25 million effective in early December 2000. During 2000, the Company was notified that two of its large industrial customers would be closing their operations. As a result of the rate increase, offset by the loss of these two customers, the Company estimates that margins earned in 2001 will increase by approximately $449,000 over those earned in 2000.
In 1999, the Company requested and received approval from the Delaware Public Service Commission to annually adjust its interruptible margin sharing mechanism in order to address the level of recovery of fixed distribution costs from residential and small commercial heating customers. The annual period runs from August 1 to July 31. During 2000, the
weather for the period ending August 31, 2000 was warmer than the threshold, resulting in a reduction in margin sharing. This reduction resulted in a $417,000 increase in margin for 2000.
During the 1999 Maryland General Assembly legislative session, taxation of electric and gas utilities was changed by the passage of The Electric and Gas Utility Tax Reform Act ("Tax Act"). Effective January 1, 2000, the Tax Act altered utility taxation to account for the restructuring of the electric and gas industries by either repealing and/or amending the existing Public Service Company Franchise Tax, Corporate Income Tax and Property Tax. Prior to this Tax Act, the State of Maryland allowed utilities a credit to their income tax liability for Maryland gross receipts taxes paid during the year. The modification eliminates the gross receipts tax credit. The Company requested and received approval from the Maryland Public Service Commission to increase its natural gas delivery service rates by $83,000 on an annual basis to recover the estimated impact of the Tax Act.
The Company plans to file for a base rate increase with the Delaware Public Service Commission during the second quarter of 2001. Interim rates are expected to be put into effect, subject to refund, in the second or third quarter of 2001.
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 L to the Consolidated Financial Statements). The Company believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by other responsible parties.
MARKET RISK
Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on the change in interest rates. The Company's long-term debt consists of first mortgage bonds, senior notes and convertible debentures (see Note G to the Consolidated Financial Statements for annual maturities of consolidated long-term debt). All of Chesapeake's long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of the Company's long-term debt was $53.6 million at December 31, 2000 as compared to a fair value of $56.0 million, based mainly on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The Company is exposed to changes in interest rates as a result of financing through its issuance of fixed-rate long-term debt. The Company evaluates whether to refinance existing debt or permanently finance existing short-term borrowing based in part on the fluctuation in interest rates.
The propane marketing operation is a party to natural gas liquids ("NGL") forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL to the Company or the counter party. The wholesale propane marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment of a net amount equal to the difference between the current market price of the futures contract and the original contract price.
The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane marketing operation is subject to commodity price risk on its open positions to the extent that market prices for NGL deviate from fixed contract settlement amounts. Market risk associated with the trading of futures and forward contracts are monitored daily for compliance with Chesapeake's Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed by oversight officials on a daily basis. Additionally, the Risk Management Committee reviews periodic reports on market and credit risk, approves any exceptions to the Risk Management Policy (within the limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on the forward and futures contracts at December 31, 2000 and 1999 are shown below.
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire within twelve months.
COMPETITION
The Company's natural gas operations compete with other forms of energy such as electricity, oil and propane. The principal competitive factors are price, and to a lesser extent, accessibility. The Company's natural gas distribution operations have several large volume industrial customers that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers convert to oil to satisfy their fuel requirements. Lower levels in interruptible sales occur when oil prices are lower relative to the price of natural gas. Oil prices, as well as the prices of electricity and other fuels are subject to fluctuation for a variety of reasons; therefore, future competitive conditions are not predictable. 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. As a result of the transmission segment's conversion to open access, the segment has shifted from providing competitive sales service to providing transportation and contract storage services.
The Company's natural gas distribution operations located in Maryland and Delaware began offering transportation services to certain industrial customers during 1998 and 1997, respectively. With transportation services now available on the Company's distribution systems, the Company is competing with third party suppliers to sell gas to industrial customers. The Company's competitors include the interstate transmission company if the distribution customer is located close enough to the transmission company's pipeline to make a connection economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the distribution operations in this manner. In certain situations, the distribution operations may adjust services and rates for these customers to retain their business. The Company expects to expand the availability of transportation services to additional classes of distribution customers in the future. The Florida distribution operation has been providing
transportation services to certain industrial customers since 1994. At that time, the Company established a natural gas brokering and supply operation in Florida to compete for these customers.
The Company's propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price. Competitors include several large national propane distribution companies, as well as an increasing number of local suppliers.
The Company's advanced information services segment faces significant competition from a number of larger competitors, many of which have substantially greater resources available to them than those of the Company. This segment competes on the basis of technological expertise, reputation and price.
INFLATION
Inflation affects the cost of labor, products and services required for operation, maintenance and capital improvements. While the impact of inflation has lessened in recent years, natural gas and propane prices are subject to rapid fluctuations. Fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanism in the Company's tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for regulated operations while monitoring the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, Chesapeake adjusts its propane selling prices to the extent allowed by the market.
RECENT PRONOUNCEMENTS
In 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, establishing accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Chesapeake will adopt the requirements of this standard in the first quarter of 2001, as required. The adoption of SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, will not have a material impact on the Company's financial position or results of operations.
In February 2001, the FASB issued a revised limited Exposure Draft on Business Combinations and Intangible Assets. Under the draft, the pooling-of-interests method of accounting for business combinations would be eliminated and the purchase method would be required. Additionally, the draft would require a non-amortization approach to account for purchased goodwill, which would be separately tested for impairment. The provisions of the draft would be effective as of the beginning of the first fiscal quarter following the issuance of the final statement. Neither early application, nor retroactive application, would be permitted. Once the exposure draft is final, the Company will be able to determine the impact the standard will have on the Company's financial position and results of operations.
CAUTIONARY STATEMENT
Chesapeake has made statements in this report that are considered to be forward-looking statements. These statements are not matters of historical fact. Sometimes they contain words such as "believes," "expects," "intends," "plans," "will," or "may," and other similar words of a predictive nature. These statements relate to matters such as customer growth, changes in revenues or margins, capital expenditures, environmental remediation costs, regulatory approvals, market risks associated with the Company's propane marketing operation, the competitive position of the Company and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. These factors include, among other things:
- the temperature sensitivity of the natural gas and propane businesses;
- the wholesale prices of natural gas and propane and market movements in these prices;
- the effects of competition on the Company's unregulated and regulated businesses;
- the effect of changes in federal, state or local legislative requirements;
- the ability of the Company's new and planned facilities and acquisitions to generate expected revenues; and
- the Company's ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information concerning quantitative and qualitative disclosure about market risk is included in Item 7 under the heading "Management's Discussion and Analysis -- Market Risk."
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
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REPORT OF INDEPENDENT ACCOUNTANTS
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To the Stockholders of Chesapeake Utilities Corporation
In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(1) of this Form 10-K present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(2) of this Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PRICEWATERHOUSECOOPERS LLP PRICEWATERHOUSECOOPERS LLP Philadelphia, Pennsylvania February 13, 2001
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes
CONSOLIDATED BALANCE SHEETS
See accompanying notes
CONSOLIDATED BALANCE SHEETS
See accompanying notes
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(1) Cash dividends per share for 2000, 1999 and 1998 were $1.06, $1.02 and $1.00, respectively.
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME TAXES
(1) Includes $298,000, $39,000 and $156,000 of deferred state income taxes for the years 2000, 1999 and 1998, respectively.
(2) 1999 includes a $238,000 tax benefit associated with the adjustment to deferred income taxes for known tax exposures, offset by a $78,000 to adjust deferred income taxes to the 35% income tax rate.
See accompanying notes
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF ACCOUNTING POLICIES
NATURE OF BUSINESS
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is engaged in natural gas distribution to approximately 40,900 customers located in central and southern Delaware, Maryland's Eastern Shore and Florida. The Company's natural gas transmission subsidiary operates a pipeline from various points in Pennsylvania and northern Delaware to the Company's Delaware and Maryland distribution divisions, as well as other utility and industrial customers in Delaware and the Eastern Shore of Maryland. The Company's propane distribution and marketing segment provides distribution service to approximately 35,600 customers in central and southern Delaware, the Eastern Shore of Maryland, Florida and Virginia, and markets propane to a number of large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States. The advanced information services segment provides consulting, custom programming, training, development tools and website development for national and international clients.
PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries. Investments in all entities in which the Company owns more than 20 percent but less than 50 percent, 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 their respective Public Service Commissions with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore Natural Gas Company ("Eastern Shore") is an open access pipeline and is subject to regulation by the Federal Energy Regulatory Commission ("FERC"). The Company's financial statements are prepared in accordance with generally accepted accounting principles, which give appropriate recognition to the ratemaking and accounting practices and policies of the various commissions. The propane distribution and marketing and advanced information services segments are not subject to regulation with respect to rates or maintenance of accounting records.
PROPERTY, PLANT, EQUIPMENT AND DEPRECIATION
Utility property is stated at original cost while the assets of the non-utility segments are recorded at cost. The costs of repairs and minor replacements are charged 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 that amortize the unrecovered cost of depreciable property over the estimated useful life of the asset. Depreciation and amortization expenses are provided at an annual rate for each segment. Average rates for the past three years were 4 percent for natural gas distribution and transmission, 5 percent for propane distribution and marketing, 19 percent for advanced information services and 7 percent for general plant.
CASH AND CASH EQUIVALENTS
The Company's policy is to invest cash in excess of operating requirements in overnight income producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less are considered cash equivalents.
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 is reduced along with the environmental regulatory asset. These amounts, awaiting ratemaking treatment, are recorded to either environmental expenditures as an
asset or accumulated depreciation as cost of removal. Environmental expenditures are amortized and/or recovered through a rider to base rates in accordance with the ratemaking treatment granted in each jurisdiction.
OTHER DEFERRED CHARGES AND INTANGIBLE ASSETS
Other deferred charges include discount, premium and issuance costs associated with long-term debt and rate case expenses. Debt costs are deferred, then amortized over the original lives of the respective debt issuances. Gains and losses on the reacquisition of debt are amortized over the remaining lives of the original issuances. 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 weighted average period of seventeen years. Gross intangibles and the net unamortized balance at December 31, 2000 were $7.7 million and $5.9 million, respectively. Gross intangibles and the net unamortized balance at December 31, 1999 were $7.1 million and $5.6 million, respectively.
INCOME TAXES AND INVESTMENT TAX CREDIT ADJUSTMENTS
The Company files a consolidated federal income tax return. Income tax expense allocated to the Company's subsidiaries is based upon their respective taxable incomes and tax credits.
Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements and tax bases of assets and liabilities and are measured using current effective income tax rates. The portions of the Company's deferred tax liabilities applicable to utility operations, which have not been reflected in current service rates, represent income taxes recoverable through future rates. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
FINANCIAL INSTRUMENTS
Xeron, the Company's propane marketing operation, engages in trading activities using forward and futures contracts which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, the Company's trading contracts are recorded at fair value, net of future servicing costs, and changes in market price are recognized as gains or losses in the period of change. The resulting unrealized gains and losses are recorded as assets or liabilities, respectively. At December 31, 2000 and 1999, the unrealized gains were $831,000 and $142,000, respectively. These trading assets are recorded in prepaid expenses and other current assets.
OPERATING REVENUES
Revenues for the natural gas distribution operations of the Company are based on rates approved by the various public service commissions. The natural gas transmission operation revenues are based on rates approved by FERC. Customers' base rates may not be changed without formal approval by these commissions. With the exception of the Company's 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 the end of the month. The Florida division recognizes revenues based on services rendered and records an amount for gas delivered but not yet billed.
Chesapeake's natural gas distribution operations each have a gas cost recovery mechanism that provides for the adjustment of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution's industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative types of supply. Neither the Company nor the customer is contractually obligated to deliver or receive natural gas.
The propane distribution operation records revenues on either an "as delivered" or a "metered" basis depending on the customer type. The propane marketing operation calculates revenues daily on a mark-to-market basis for open contracts.
The advanced information services and other segments record revenue in the period the products are delivered and/or services are rendered.
EARNINGS PER SHARE
The calculations of both basic and diluted earnings per share are presented in the following table.
CERTAIN RISKS AND UNCERTAINTIES
The financial statements are prepared in conformity with generally accepted accounting principles that require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes L and M to the Consolidated Financial Statements for significant estimates). These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond the control of the Company; therefore, actual results could differ from those estimates.
The Company records certain assets and liabilities in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71. If the Company were required to terminate application of SFAS No. 71 for its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material.
FASB STATEMENTS AND OTHER AUTHORITATIVE PRONOUNCEMENTS
In 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, establishing accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement does not allow retroactive application to financial statements for prior periods. Chesapeake will adopt the requirements of this standard in the first quarter of 2001, as required. The Company believes that adoption of SFAS No. 133 will not have a material impact on the Company's financial position or results of operations. This statement, originally effective for all fiscal quarters of the fiscal years beginning after June 15, 1999 was deferred by the FASB under SFAS No. 137 and now is effective for all fiscal quarters of the fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, amending the accounting and reporting standards of SFAS No.133. The adoption of SFAS No. 138 will not have a material impact on the Company's financial position or results of operations.
In February 2001, the FASB issued a revised limited Exposure Draft on Business Combinations and Intangible Assets. Under the draft, the pooling-of-interests method of accounting for business combinations would be eliminated and the purchase method would be required. Additionally, the draft would require a non-amortization approach to account for purchased goodwill, which would be separately tested for impairment. The provisions of the draft would be effective as
of the beginning of the first fiscal quarter following the issuance of the final statement. Neither early application, nor retroactive application, would be permitted. Once the exposure draft is final, the Company will be able to determine the impact the standard will have on the Company's financial position and results of operations.
RESTATEMENT AND RECLASSIFICATION OF PRIOR YEARS' AMOUNTS
Certain prior years' amounts have been reclassified to conform to the current year presentation.
B. BUSINESS COMBINATIONS
In January 2000, Chesapeake acquired Carroll Water Systems, Inc. ("Carroll") of Westminster, Maryland. Carroll was a privately owned EcoWater dealership serving the suburban areas around Baltimore, Maryland. The acquisition was accounted for as a purchase and the Company's financial results include the results of operations of Carroll from the date of acquisition.
In November 1999, Chesapeake acquired EcoWater Systems of Michigan, Inc., operating as Douglas Water Conditioning ("Douglas"). Douglas is an EcoWater dealership that has served the Detroit, Michigan area for 11 years. The acquisition was accounted for as a purchase and the Company's financial results include the results of operations of Douglas from the date of acquisition.
C. SEGMENT INFORMATION
Chesapeake uses the management approach to identify operating segments. Chesapeake organizes its business around differences in products or services and the operating results of each segment are regularly reviewed by the Company's chief operating decision maker in order to make decisions about resources and to assess performance. The following table presents information about the Company's reportable segments.
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
D. FAIR VALUE OF FINANCIAL INSTRUMENTS
Various items within the balance sheet are considered to be financial instruments because they are cash or are to be settled in cash. The carrying values of these items generally approximate their fair value (see Note E to the Consolidated Financial Statements for disclosure of fair value of investments). The Company's open forward and futures contracts at December 31, 2000 and December 31, 1999 had a net fair value of $831,000 and $142,000, respectively based on market rates. The fair value of the Company's long-term debt is estimated using a discounted cash flow methodology. The Company's long-term debt at December 31, 2000, including current maturities, had an estimated fair value of $56.0 million as compared to a carrying value of $53.6 million. At December 31, 1999, the estimated fair value was approximately $36.3 million as compared to a carrying value of $36.4 million. These estimates are based on published corporate borrowing rates for debt instruments with similar terms and average maturities.
E. INVESTMENTS
The investment balance at December 31, 2000 consists primarily of a Rabbi Trust ("the trust") associated with the acquisition of Xeron, Inc. The Company has classified the underlying investments held by the trust as trading securities, which require all gains and losses to be recorded into non-operating income. The trust was established during the acquisition as a retention bonus for an executive of Xeron. The Company has an associated liability recorded which is adjusted, along with non-operating expense, for the gains and losses incurred by the trust.
In November 1999, Chesapeake finalized the sale of its investment in Florida Public Utilities Company ("FPU") for $16.50 per share. Chesapeake recognized a gain on the sale of $1,415,000 pre-tax or $863,000 after-tax. The Company had a 7.3 percent ownership interest in the common stock of FPU, which had been classified as an available for sale security. This classification required 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, 1998, the market value had exceeded the aggregate cost basis of the Company's portfolio by $1,552,000 pre-tax and $487,000 after-tax, respectively.
F. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL
The following is a schedule of changes in the Company's shares of common stock.
(1)12,000,000 shares are authorized at a par value of $.4867 per share.
(2)Includes dividends and reinvested optional cash payments.
(3)The Company has 7,442 shares held in a Rabbi Trust as of December 31, 2000.
In 2000, the Company entered into an agreement with an investment banker to assist in identifying acquisition candidates. Under the agreement, the Company issued warrants to the investment banker to purchase 15,000 shares of Company stock, which are exercisable during the next seven years at a price of $18.00 per share. During 2000, no warrants were exercised.
G. LONG-TERM DEBT
Annual maturities of consolidated long-term debt for the next five years are as follows: $2,665,091 for the years 2001 and 2002, $3,665,091 for the years 2003 and 2004 and $2,909,091 for the year 2005.
The convertible debentures may be converted, at the option of the holder, into shares of the Company's common stock at a conversion price of $17.01 per share. During 2000 and 1999, debentures totaling $181,000 and $147,000, respectively, 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. At the Company's option, the debentures may be redeemed at the stated amounts. During 2000, debentures totaling $10,000 were redeemed.
Indentures to the long-term debt of the Company and its subsidiaries contain various restrictions. The most stringent restrictions state that the Company must maintain equity of at least 40 percent of total capitalization, 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 $2.1 million plus consolidated net income recognized on or after January 1, 1989. As of December 31, 2000, the amounts available for future dividends permitted by the Series I covenant approximated $19.3 million.
Portions of the Company's natural gas distribution plant assets are subject to a lien under the mortgage pursuant to which the Company's first mortgage sinking fund bonds are issued.
H. SHORT-TERM BORROWING
The Board of Directors has authorized the Company to borrow up to $45.0 million from various banks and trust companies. As of December 31, 2000, the Company had four unsecured bank lines of credit totaling $60.0 million, none of which required compensating balances. Under these lines of credit, the Company had short-term debt outstanding of $25.4 million and $23.0 million at December 31, 2000 and 1999, respectively, with weighted average interest rates of 6.89 percent and 5.51 percent, respectively.
I. LEASE OBLIGATIONS
The Company has entered several operating lease arrangements for office space at various locations and pipeline facilities. Rent expense related to these leases was $652,000, $357,000 and $385,000 for 2000, 1999 and 1998, respectively. Future minimum payments under the Company's current lease agreements are $719,000, $573,000, $520,000, $483,000 and $385,000 for the years of 2001 through 2005, respectively; and $464,000 thereafter, totaling $3.1 million.
J. EMPLOYEE BENEFIT PLANS
PENSION PLAN In December 1998, the Company restructured the employee benefit plans to be competitive with those in similar industries. Chesapeake offered existing participants of the defined benefit plan the option to remain in the existing plan or receive a one-time payout and enroll in an enhanced retirement savings plan. Chesapeake closed the defined benefit plan to new participants, effective December 31, 1998. Based on the election options selected by the employees, the Company reduced its accrued pension liability to $1,283,088. As a result of the change in the accrued liability, the Company recorded a curtailment gain of $1,224,298 in 1998. Benefits under the plan are based on each participant's years of service and highest average compensation. The Company's funding policy provides that payments to the trustee shall be equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974.
The following schedule sets forth the funded status of the pension plan at December 31, 2000 and 1999:
(1) Benefits paid in 1999 include $4 million in one-time payments related to the restructuring of the pension plan.
Net periodic pension costs for the defined pension benefit plan for 2000, 1999 and 1998 include the following components:
The Company sponsors an unfunded executive excess benefit plan. The accrued benefit obligation and accrued pension costs were $676,000 and $515,000, respectively as of December 31, 2000 and $478,000 and $373,000, respectively at December 31, 1999.
RETIREMENT SAVINGS PLAN
The Company sponsors a 401(k) Retirement Savings Plan, which provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions of up to 15 percent of eligible base compensation, subject to IRS limitations. For participants still covered by the defined benefit pension plan, the Company makes a contribution matching 60 percent or 100 percent of each participant's pre-tax contributions based on the participant's years of service, not to exceed 6 percent of the participant's eligible compensation for the plan year.
Effective January 1, 1999, the Company began offering an enhanced 401(k) plan to all new employees, as well as existing employees that elected to no longer participate in the defined benefit plan. The Company makes matching contributions on a basis of up to 6 percent of each employee's pre-tax compensation for the year. The match is between 100 percent and 200 percent, based on a combination of the employee's age and years of service. The first 100 percent of the funds are matched with Chesapeake common stock. The remaining match is invested in the Company's 401(k) plan according to each employee's election options.
Effective, January 1, 1999 the Company began offering a non-qualified supplemental employee retirement savings plan open to Company executives over a specific income threshold. Participants receive a cash only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds earn interest income monthly. This Plan is not funded externally.
The Company's contributions to the 401(k) plans totaled $1,231,000, $1,066,000 and $495,000 for the years ended December 31, 2000, 1999 and 1998, respectively. As of December 31, 2000, there are 32,055 shares reserved to fund future contributions to the Retirement Savings Plan.
OTHER POST-RETIREMENT BENEFITS
The Company sponsors a defined benefit post-retirement health care and life insurance plan that covers substantially all natural gas and corporate employees.
Net periodic post-retirement costs for 2000, 1999 and 1998 include the following components:
The following schedule sets forth the status of the post-retirement health care and life insurance plan:
The health care inflation rate for 2000 is assumed to be 8.0 percent. This rate is projected to gradually decrease to an ultimate rate of 5 percent 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 $84,511 as of January 1, 2001, and would increase the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2001 by approximately $6,846.
K. EXECUTIVE INCENTIVE PLANS
The Performance Incentive Plan ("the Plan") adopted in 1992 provides for the granting of stock options, stock appreciation rights and performance shares to certain officers of the Company over a 10-year period. The Plan provides participants an option to purchase shares of the Company's common stock, exercisable in cumulative installments of up to one-third on each anniversary of the commencement of the award period. The Plan also enables participants the right to earn performance shares upon the Company's achievement of certain performance goals as set forth in the specific agreements associated with particular options and/or performance shares.
The Company executed Stock Option Agreements for a three-year performance period ending December 31, 2000 with certain executive officers. One-half of these options become exercisable over time and the other half become exercisable if certain performance targets are achieved. In 2000, the Company replaced the third year of this Stock Option Agreement with Stock Appreciation Rights ("SARs"). The SARs are awarded based on performance with a minimum number of SARs established for each participant. During 2000, the Company awarded 26,300 SARs in conjunction with the agreement. Chesapeake currently awards Performance Share Agreements annually for certain other executive officers. Each year participants are eligible to earn a maximum number of performance shares, based on the Company's achievement of certain performance goals. The Company recorded compensation expense of $118,000, $131,000 and $49,000 associated with these performance shares in 2000, 1999 and 1998, respectively.
Changes in outstanding options were as follows:
In December 1997, the Company granted stock options to certain executive officers of the Company. As required by Statement of Financial Accounting Standards No. 123, the pro forma information as if fair value based accounting had been used to account for the stock-based compensation costs is shown below.
L. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES
The Company is currently 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 three of these sites, the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites.
With respect to the Dover Gas Light site, the Company and General Public Utilities Corporation, Inc. ("GPU") have been ordered by the Environmental Protection Agency ("EPA") to fund or implement the EPA's Record of Decision ("ROD") on the appropriate remedial activities to be performed, which include both soil and ground-water remedies.
During 1999, the Company completed the first phase of the soil remediation process at that site. During 2000, the Company initiated the second soil remediation phase, soil vapor extraction procedures ("SVE") with the finding submitted to the EPA for review. Based on the finding the Company has filed a request with the EPA to discontinue the SVE and is awaiting the EPA's response. Once the SVE remediation procedures are completed, the Company expects to complete the third and final phase of soil remediation and then initiate the ground-water remedial activities.
The Company's independent consultants have prepared preliminary estimates of the costs of two potentially acceptable alternatives to complete the ground-water remediation activities at the site. The costs to remediate the ground-water range from a low of $390,000 in capital and $37,000 per year of operating costs for 30 years for natural attenuation to a high of $3.3 million in capital and $1.0 million per year in operating costs to operate a pump-and-treat/ground-water containment system. The pump-and-treat/ground-water containment system is intended to contain the manufactured gas plant ("MGP") contaminants to allow the ground-water outside of the containment area to attenuate naturally. The operating cost estimate for the pump-and-treat containment system is dependent upon the actual ground-water quality and flow conditions at the site. The Company continues to believe that a ground-water pump-and-treat system is not necessary for the MGP contaminants, that there is insufficient information to design an overall ground-water containment program and that natural attenuation is the appropriate remedial action for the MGP wastes.
Chesapeake cannot predict the ground-water remediation that the EPA will require; therefore, the Company in 2000 has not adjusted the $2.1 million accrued at December 31, 1999 for the Dover site and the associated regulatory asset for an equivalent amount. Of this amount, $1.5 million is for ground-water remediation and $600,000 is for the remaining soil remediation. The $1.5 million represents the low end of the ground-water remedy estimates described above.
In 1996, the Company initiated litigation against GPU, one of the other potentially responsible parties, for contribution to the remedial costs incurred by Chesapeake in connection with complying with the ROD. In February 2001, the Company and GPU reached a tentative settlement, pending the approval of the courts. The terms of the settlement prohibit disclosure of the provisions of the settlement until finalized. 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. The Company expects that it will be able to recover actual costs incurred, which are not recovered from other responsible parties, exclusive of associated carrying costs, through the ratemaking process in accordance with environmental cost recovery rider provisions currently in effect.
In cooperation with the Maryland Department of the Environment ("MDE"), the Company is engaged in remediation procedures at the Salisbury site. In addition, the Company reports the remediation and monitoring results to the MDE. The remediation procedures at the site are currently suspended awaiting approval from the MDE to permanently shutdown the remediation procedures. The Company has adjusted the liability with respect to the Salisbury site to $175,000 in December 2000. The Company had previous accrued $240,000 as of December 31, 1999. This amount is based on the estimated operating costs of the remediation facilities over the next two years and capital costs to shut down
the remediation procedures in 2002. A corresponding regulatory asset has been recorded, reflecting the Company's belief that costs incurred will be recoverable in base rates.
The third site is located in the state of Florida and in January 2001 the Company filed a remedial action plan ("RAP") with the Florida Department of the Environment. The RAP included an estimate of $635,000 to complete the remediation procedures at a portion on the site. Accordingly in December 2000, the Company accrued $635,000 and an associated regulatory asset. Once the FDEP approves the RAP, the Company will commence with the remediation procedures per the RAP. The Company continues to accrue for future environmental costs and at December 31, 2000 has collected $505,000 in excess of costs incurred.
It is management's opinion that any unrecovered current costs and any other future costs associated with any of the three sites incurred will be recoverable through future rates or sharing arrangements with other responsible parties.
M. OTHER COMMITMENTS AND CONTINGENCIES
NATURAL GAS SUPPLY
The Company's natural gas distribution operations have entered into contractual commitments for daily entitlements of natural gas from various suppliers. The contracts have various expiration dates. In 2000, the Company entered into a long-term contract with an energy marketing and risk management company to manage the Company's natural gas transportation and storage capacity.
OTHER
The Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on the consolidated financial position of the Company.
N. QUARTERLY FINANCIAL DATA (UNAUDITED)
In the opinion of the Company, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods. Due to the seasonal nature of the Company's business, there are substantial variations in operations reported on a quarterly basis.
(1) Results for the fourth quarter of 1999 reflect a gain on the sale of investments of $863,000, net of income tax expense.
See Note E to the Consolidated Financial Statements.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
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", Section 16(a) Beneficial Ownership Reporting Compliance" to be filed on or before May 1, 2001 in connection with the Company's Annual Meeting to be held on May 15, 2001
The information required by this item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Part I of this Form 10-K under "Executive Officers of the Registrant."
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
This information is incorporated herein by reference to the Proxy Statement, under "Management Compensation Committee Interlocks and Insider Participation", in the Proxy Statement to be filed on or before April 30, 2001, in connection with the Company's Annual Meeting to be held on May 15, 2001.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is incorporated herein by reference to the information included, under "Beneficial Ownership of the Company's Securities", in the Proxy Statement, dated and to be filed on or before March 30, 2001 in connection with the Company's Annual Meeting to be held on May 15, 2001.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is incorporated herein by reference to the information included, under "Certain Transactions" in the Proxy Statement, dated and to be filed on or before April 30, 2001, in connection with the Company's Annual Meeting to be held on May 15, 2001
PART IV
ITEM 14.
ITEM 14. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K
(a) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT: 1. Financial Statements:
- Accountants' Report dated February 13, 2001 of PricewaterhouseCoopers LLP, Independent Accountants
- Consolidated Statements of Income for each of the three years ended December 31, 2000, 1999, and 1998
- Consolidated Balance Sheets at December 31, 2000 and December 31,
- Consolidated Statements of Cash Flows for each of the three years ended December 31, 2000,1999, and 1998
- Consolidated Statements of Common Stockholders' Equity for each of the three years ended December 31, 2000, 1999, and 1998
- Consolidated Statements of Income Taxes for each of the three years ended December 31, 2000, 1999, and 1998
- Notes to Consolidated Financial Statements
2. Financial Statement Schedules -- Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not required, are inapplicable or the information is otherwise shown in the financial statements or notes thereto.
(b) REPORTS ON FORM 8-K: None
(c) EXHIBITS:
Exhibit3(a) Amended Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590.
Exhibit 3(b) Amended Bylaws of Chesapeake Utilities Corporation, effective August 20, 1999, are incorporated herein by reference to Exhibit 3 of the Company's Registration Statement on Form 8-A, File No. 001-11590, filed August 24, 1999.
Exhibit 4(a) Form of Indenture between the Company and Boatmen's Trust Company, Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of the Company's Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989.
Exhibit 4(b) Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593.
Exhibit 4(c) Note Purchase Agreement entered into by the Company on October 2, 1995, pursuant to which the Company privately placed $10 million of its 6.91% Senior Notes due in 2010, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the Commission upon request.
Exhibit 4(d) Note Purchase Agreement entered into by the Company on December 15, 1997, pursuant to which the Company privately placed $10 million of its 6.85% senior notes due 2012, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the Commission upon request.
Exhibit 4(e) Note Purchase Agreement entered into by the Company on December 27, 2000, pursuant to which the Company privately placed $20 million of its 7.83% senior notes due 2015, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the Commission upon request.
*Exhibit 10(a) 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 Company's Quarterly Report on Form 10-Q for the period ended June 30, 1997, File No. 001-11590.
*Exhibit 10(b) Executive Employment Agreement dated January 1, 2001, by and between Chesapeake Utilities Corporation and Ralph J. Adkins, filed herewith.
*Exhibit 10(c) Form of Performance Share Agreement dated January 1, 1998, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Ralph J. Adkins and John R. Schimkaitis is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 001-11590.
*Exhibit 10(d) Form of Performance Share Agreement dated January 1, 2001, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Ralph J. Adkins, John R. Schimkaitis, Michael P. McMasters and Stephen C. Thompson, filed herewith.
*Exhibit 10(e) Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 1992, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-593.
*Exhibit 10(f) Chesapeake Utilities Corporation Performance Incentive Plan dated January 1, 1992, is incorporated herein by reference to the Company's Proxy Statement dated April 20, 1992, in connection with the Company's Annual Meeting held on May 19, 1992.
*Exhibit 10(g) Form of Stock Appreciation Rights Agreement dated January 1, 2001, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Philip S. Barefoot, William C. Boyles, Thomas A. Geoffroy, James R. Schneider and William P. Schneider, filed herewith.
*Exhibit 10(h) Directors Stock Compensation Plan adopted by Chesapeake Utilities Corporation in 1995 is incorporated herein by reference to the Company's Proxy Statement dated April 17, 1995 in connection with the Company's Annual Meeting held in May 1995.
*Exhibit 10(i) United Systems, Inc. Executive Appreciation Rights Plan dated December 31, 2000, filed herewith.
*Exhibit 10(j) United Systems, Inc. Employee Appreciation Rights Plan dated December 31, 2000, 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.
* Management contract or compensatory plan or agreement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHESAPEAKE UTILITIES CORPORATION
By: /S/ JOHN R. SCHIMKAITIS ------------------------------------- John R. Schimkaitis President and Chief Executive Officer Date:March 15,2001
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.
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
(1) Recoveries.
(2) Uncollectible accounts charged off.
Upon written request, Chesapeake will provide, free of charge, a copy of any exhibit to the 2000 Annual Report on Form 10-K not included in this document.