STATE OF DELAWARE 51-0064146 ------------------- ---------- (STATE OR OTHER (I.R.S. EMPLOYER JURISDICTION OF IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) |
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ---------------------- ----------------------------------------------- COMMON STOCK - PAR NEW YORK STOCK EXCHANGE, INC. VALUE PER SHARE $.4867 |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]. No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [X]
As of March 25, 2002, 5,456,536 shares of common stock were outstanding. The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation, based on the last trade price on March 25, 2002, as reported by the New York Stock Exchange, was approximately $99.9 million.
TABLE OF CONTENTS
PAGE
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PART I.......................................................................1
Item 1. Business.........................................................1
Item 2. Properties......................................................10
Item 3. Legal Proceedings..............................................11
Item 4. Submission of Matters to a Vote of Security Holders.....14
PART II.....................................................................15
Item 5. Market for the Registrant's Common Stock and
Related Security Holder Matters.................................15
Item 6. Selected Financial Data.......................................16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................20
Item 7a. Quantitative and Qualitative Disclosures About Market Risk....30
Item 8. Financial Statements and Supplemental Data..................30
Item 9. Changes In and Disagreements With Accountants
on Accounting and Financial Disclosure........................50
PART III....................................................................50
Item 10. Directors and Executive Officers of the Registrant.......50
Item 11. Executive Compensation........................................50
Item 12. Security Ownership of Certain Beneficial Owners
and Management.................................................50
Item 13. Certain Relationships and Related Transactions.............50
PART IV.....................................................................51
Item 14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K............................51
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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 primarily in natural gas distribution and transmission, propane distribution and marketing, and providing advanced information services.
Chesapeake's three natural gas distribution divisions serve approximately 42,700 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 Southern Pennsylvania, Delaware and on the Eastern Shore of Maryland. The Company's propane distribution operation serves approximately 34,600 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 subsidiaries in other service-related businesses.
(I) (A) NATURAL GAS DISTRIBUTION AND TRANSMISSION GENERAL Chesapeake distributes natural gas to approximately 42,700 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 and supply management services in the state of Florida under the name of Peninsula Energy Services Company ("PESCO").
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions ("Delaware," "Maryland" or "the divisions") serve an average of approximately 32,400 customers, of which approximately 32,230 are residential and commercial customers purchasing gas primarily for heating purposes. The remainder are industrial customers. For the year 2001, residential and commercial customers accounted for approximately 78% of the volume delivered by the divisions and 70%
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Florida. The Florida division distributes natural gas to approximately 10,500 residential and commercial and 92 industrial customers in Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee and Citrus Counties. Currently the 92 industrial customers, which purchase and transport gas either on a firm or an interruptible basis, account for approximately 93% of the volume delivered by the Florida division and 40% 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 provides natural gas supply management services to 203 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 both firm and interruptible
contracts with four interstate "open access" pipelines including Eastern Shore.
The divisions are directly interconnected with Eastern Shore and services
upstream of Eastern Shore are contracted with Transco Gas Pipeline Corporation
("Transco"), Columbia Gas Transmission ("Columbia") and Columbia Gulf
Transmission Company ("Gulf"). The divisions use their firm transportation
supply resources to meet a significant percentage of their projected demand
requirements. In order to meet the difference between firm supply and firm
demand, the divisions purchase natural gas supply on the "spot market" from
various suppliers that is transported by the upstream pipelines and delivered to
the divisions' interconnects with Eastern Shore. The divisions also have the
capability to use propane-air peak-shaving to supplement or displace the "spot
market" purchases. The Company believes that the availability of gas supply to
the Delaware and Maryland divisions is adequate under existing arrangements to
meet the anticipated needs of their customers.
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; (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.
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Delaware currently has contracts for the purchase of firm natural gas supply with several suppliers. These supply contracts provide the availability of a maximum firm daily entitlement of 19,700 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore under firm transportation contracts. The gas purchase contracts have various expiration dates and daily quantities may vary from day to day and month to month.
Maryland. 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 several suppliers. These supply contracts provide the availability of a maximum firm daily entitlement of 7,600 Dt and the supplies are transported by
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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 1,600 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. This turnback coincides with the in service dates of FGT's 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 2,888 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.
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 for its transportation services. In addition, the FERC regulates the rates Eastern Shore is charged for transportation and transmission line capacity and services provided by Transco and Columbia.
Management monitors the rate of return in each jurisdiction in order to ensure the timely filing of rate adjustment applications.
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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 under the agreements, the Company excludes 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. The mechanism had no impact on 2001 gross margins.
On August 2, 2001, the Delaware Division filed a general rate increase application. Interim rates, subject to refund went into effect on October 1, 2001. A settlement agreement was reached on February 20, 2002 that would result in an annual increase in rates of approximately $380,000. The agreement is expected to be submitted to the DPSC for final approval in the second quarter of 2002.
As a result of filing the general rate increase application on August 2, 2001, the Delaware Division's previously approved rate design changes in 1999 to its margin sharing mechanism terminated. The previous rate design changes that addressed the level of recovery of fixed distribution costs from its residential and smaller commercial customers in relation to its margin sharing mechanism and the actual weather experienced, ended upon the implementation of interim rates on October 1, 2001.
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.
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Florida. On August 8, 2001, the Florida Division filed a petition for approval of tariff modifications relating to the Competitive Rate Adjustment Cost Recovery Clause (the "Clause"). On October 1, 2001, the Florida Public Service Commission ("FPSC") issued an order approving the Clause. The Clause provides for the equitable distribution of surpluses or collection of shortfalls from both sales and transportation customers of any variances between our tariff rates and actual revenue derived from those customers who are provided service under our flexible rate tariff. All "market price sensitive" customers are excluded from the Clause.
On November 19, 2001, the Florida Division filed a petition with the Florida Public Service Commission for approval of certain transportation cost recovery factors. The Florida Public Service Commission approved the factors on January 24, 2002. In the Florida Division's rate case approved in November 2000, the FPSC approved the concept but not the specifics of the recovery methodology or the level of costs to be recovered. The methodology and factors approved provide for the recovery, over a two year period, of the Florida Division's actual and projected expenses incurred in the implementation of the transportation provisions of the tariff as approved in the November 2000 rate case.
On February 4, 2002, the FPSC approved a special contract with Suwannee American Limited Partnership. The agreement is for the construction of distribution facilities connecting Florida Gas Transmission's (FGT) pipeline to the Suwannee American cement plant in order to provide natural gas service. The FGT pipeline and all of the Florida Division's facilities are located on Suwannee America's property located in Suwannee County, Florida.
Eastern Shore. 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 Dekatherms ("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 were completed and placed into service during the third quarter of 2001.
On January 11, 2001, 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 was to enable Eastern Shore to provide 19,800 Dts of additional daily firm service capacity on its system. The expansion was completed and placed in service in the fourth quarter of 2001.
On January 25, 2002, Eastern Shore filed an application before FERC requesting authorization for the following: (1) Segment 1 - construct and operate 1.5 miles of 16-inch mainline looping in Pennsylvania on Eastern Shore's existing
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On October 31, 2001, Eastern Shore filed revised tariff sheets to reflect a general Natural Gas Act Section 4 rate increase before the FERC. The filing was made pursuant to the requirements of Article XII of the Stipulation and Agreement dated August 1, 1997. Eastern Shore's filing proposed a change in base rates for firm transportation services.
On November 30, 2001, the Commission issued an Order, which accepted and suspended the effectiveness of the rates until May 1, 2002 subject to refund and the outcome of a hearing. A pre-hearing conference was held on December 18, 2001 and the hearing was scheduled has been September 24, 2002.
Discovery related to the rate proceeding began in January 2002 with FERC Staff data requests. The outcome of the proceedings is uncertain.
(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 34,600 propane customers on the Delmarva Peninsula and delivered approximately 22 million retail and wholesale gallons of propane during 2001.
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. Additional information on Xeron's trading and wholesale marketing activities, market risks and the controls that limit and monitor the risks are included in Item 7 under the heading "Management's Discussion and Analysis - Cautionary Statement."
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 supply and demand for 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.
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The Company's propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to the Company's bulk storage facilities. From these facilities, propane is delivered in portable cylinders or by "bobtail" trucks, owned and operated by the Company, to tanks located at the customer's premises.
Xeron does not own physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.
COMPETITION
The Company's propane distribution operations compete with several other propane
distributors in their service territories, primarily on the basis of service and
price, emphasizing reliability of service and responsiveness. Competition is
generally from local outlets of national distribution companies and local
businesses because distributors located in close proximity to customers incur
lower costs of providing service. Propane competes with electricity as an energy
source, because it is typically less expensive than electricity, based on
equivalent BTU value. 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 greater 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 $40,000,000 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 BravePoint, Inc. ("BravePoint"), a wholly owned subsidiary of the Company. The Company changed its name from United Systems, Inc. in 2001 to reflect a change in service offerings.
BravePoint is based in Atlanta and primarily provides web-related products and services and support for users of PROGRESS , a fourth generation computer language and Relational Database Management System. BravePoint offers consulting, training, placement, staffing, software development tools, web development and customer software development for its client base, which includes many large domestic and international corporations.
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(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 Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is a Delaware affiliated investment company.
The Company owns several businesses involved in water conditioning and treatment and bottled water services. Sam Shannahan Well Co., Inc. (dba Sharp Water, Inc.) and Sharp Water, Inc. are wholly owned subsidiaries of Chesapeake. EcoWater Systems of Michigan, Inc. (dba Douglas Water Conditioning), Carroll Water Systems, Inc., Absolute Water Care, Inc., Sharp Water of Florida, Inc. (dba Aquarius Water Systems), Sharp Water of Minnesota, Inc. (dba EcoWater Systems of Rochester) and Sharp Water of Idaho, Inc. (dba Intermountain Water) are wholly owned subsidiaries of Sharp Water, Inc.
The water operations serve central and southern Delaware; the eastern shore of Virginia; Maryland; Detroit, Michigan; Rochester, Minnesota; Boise, Idaho and parts of Florida. They face competition from a variety of national and local suppliers of water conditioning and treatment services and bottled water.
(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, 2001, Chesapeake had 580 employees, including 177 in natural gas, 128 in propane, 103 in advanced information services and 122 in water conditioning. The remaining 44 employees are considered general and administrative and include officers of the Company, treasury, accounting, information technology, human resources and other administrative personnel. The 2001 acquisitions added 51 employees.
(V) EXECUTIVE OFFICERS OF THE REGISTRANT Information pertaining to the executive officers of the Company is as follows:
Ralph J. Adkins (age 59) 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 54) Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. He has served as President since 1997. His present
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Michael P. McMasters (age 43) 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 41) 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 44) 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. 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; Winter Haven, Florida; and Fenton, Michigan.
Chesapeake rents office space in Dover, Delaware; Jupiter, Lecanto, Venice and
Stuart, Florida; Chincoteague and Belle Haven, Virginia; Easton, Salisbury,
Westminster and Pocomoke, Maryland; Waterford, Michigan; Houston, Texas;
Atlanta, Georgia; Boise and Moscow, Idaho; and Rochester, Minnesota. 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) 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.
(C) 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.
(D) 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 31 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 does not own physical storage facilities or equipment to transport propane.
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ITEM 3. LEGAL PROCEEDINGS
(F) 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.
(G) 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
Chesapeake Utilities Corporation Page 11
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.
Because the Company cannot predict what the EPA will require for the overall ground-water program, a liability of $2.1 million was 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.
Chesapeake Utilities Corporation Page 12
In May 2001, Chesapeake, General Public Utilities Corporation, Inc. ("GPU"), the State of Delaware and the United States Environmental Protection Agency ("EPA") signed a settlement term sheet reflecting the agreement in principle to settle a lawsuit with respect to the Dover Gas Light site. The parties are in the process of memorializing the terms of the final agreement in two consent decrees. The consent decrees will then be published for public comment and submitted to a federal judge for approval.
If the agreement in principle receives final approval, Chesapeake will:
- Design and construct a parking lot on the site and dismantle the soil vapor extraction system that had been erected at the site. - Receive a net payment of $1.15 million from other parties to the agreement. These proceeds will be passed on to Chesapeake's firm customers, in accordance with the environmental rate rider. - Receive a release from liability and covenant not to sue from the EPA and the State of Delaware. This will relieve Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to EPA is received that indicates the remedial action related to the prior manufactured gas plant is not sufficiently protective. These con- tingencies are standard, and are required by the United States in all liability settlements.
At December 31, 2001, the Company had accrued $2.1 million of costs associated with the remediation of the Dover site and had recorded an associated regulatory asset for the same amount. Of that amount, $1.5 million was for estimated ground-water remediation and $600,000 was for remaining soil remediation. The $1.5 million represented the low end of the ground-water remediation estimates prepared by an independent consultant and was used because the Company could not, at that time, predict the remedy the EPA might require.
Upon receiving final court approval of the consent decrees, Chesapeake will reduce both the accrued environmental liability and the associated environmental regulatory asset to the amount required to complete its obligations (primarily the final demobilization of the remedial system and final design and construction of the parking lot).
Through December 31, 2001, the Company has incurred approximately $8.9 million in costs relating to environmental testing and remedial action studies at the Dover site. 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 compared 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 makes it unnecessary to file a rate case every year to recover expenses incurred. Through December 31, 2001, the unamortized balance and amount of environmental costs not included in the rider; effective January 1, 2002 were $2,878,000 and $67,000, respectively.
Chesapeake Utilities Corporation Page 13
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 requested approval from the MDE 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 $100,000 for the final year's operating costs and capital costs to shut down the remediation process at the end of the year. Based on these estimated costs, the Company adjusted both its liability and related regulatory asset to $100,000 on December 31, 2001, to cover the Company's projected remediation costs for this site. Through December 31, 2001, the Company has incurred approximately $2.8 million for remedial actions and environmental studies. Of this amount, approximately $1,062,000 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 FDEP approved the RAP on May 4, 2001.
The Company has accrued a liability of $1,000,000 as of December 31, 2001 for the Florida site. The Company has recovered all environmental costs incurred to date, approximately $890,000, 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, 2001, Chesapeake had received $523,000 related to future costs, which are expected to be incurred. There is a regulatory asset recorded at December 31, 2001 of $477,000, which represents the estimated future liability for clean up ($1,000,000), net of the amount received through rates in excess of the costs incurred to date ($523,000).
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
Chesapeake Utilities Corporation Page 14
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS
(H) 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 2001 and
2000 were as follows:
---------------------------------------------------------
DIVIDENDS
DECLARED
QUARTER ENDED HIGH LOW CLOSE PER SHARE
---------------------------------------------------------
2001
MARCH 31 . . $19.1250 $17.3750 $18.2000 $0.2700
JUNE 30. . . 19.5500 17.6000 18.8800 0.2700
SEPTEMBER 30 19.2000 17.7500 18.3500 0.2750
DECEMBER 31. 19.9000 18.1000 19.8000 0.2750
---------------------------------------------------------
2000
March 31 . . $18.8750 $16.2500 $16.9375 $0.2600
June 30. . . 18.5000 16.3750 17.7500 0.2600
September 30 18.1250 16.6250 18.1250 0.2700
December 31. 18.7500 16.7500 18.6250 0.2700
---------------------------------------------------------
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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, 2001, the amounts available for future dividends permitted by the Series I covenant are $19.9 million.
At December 31, 2001, there were approximately 2,171 shareholders of record of the Common Stock.
Chesapeake Utilities Corporation Page 15
10-YEAR FINANCIAL & STATISTICAL INFORMATION
----------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------------
OPERATING (IN THOUSANDS OF DOLLARS)
Revenues
Natural gas distribution and transmission. . $ 108,122 $ 99,750 $ 75,592 $ 68,745 $ 88,105
Propane. . . . . . . . . . . . . . . . . . . 198,124 216,273 138,437 102,063 125,159
Advanced informations systems. . . . . . . . 14,104 12,353 13,531 10,331 7,636
Other. . . . . . . . . . . . . . . . . . . . 9,971 7,037 2,640 1,781 1,589
----------------------------------------------------------------------------------------------------
Total revenues . . . . . . . . . . . . . . . . $ 330,321 $335,413 $230,200 $182,920 $222,489
Gross margin
Natural gas distribution and transmission. . $ 37,374 $ 35,322 $ 32,339 $ 29,516 $ 30,064
Propane. . . . . . . . . . . . . . . . . . . 14,444 15,995 14,099 12,071 12,492
Advanced informations systems. . . . . . . . 6,719 5,656 6,575 5,316 3,856
Other. . . . . . . . . . . . . . . . . . . . 5,429 3,611 1,025 901 737
----------------------------------------------------------------------------------------------------
Total gross margin . . . . . . . . . . . . . . $ 63,966 $ 60,584 $ 54,038 $ 47,804 $ 47,149
Operating income before taxes
Natural gas distribution and transmission. . $ 14,267 $ 12,365 $ 10,300 $ 8,814 $ 9,219
Propane. . . . . . . . . . . . . . . . . . . 1,100 2,319 2,627 971 1,158
Advanced informations systems. . . . . . . . 517 336 1,470 1,316 1,046
Other. . . . . . . . . . . . . . . . . . . . (339) 1,006 452 504 671
----------------------------------------------------------------------------------------------------
Total operating income before taxes. . . . . . $ 15,545 $ 16,026 $ 14,849 $ 11,605 $ 12,094
Net income from continuing operations (2). . . $ 6,722 $ 7,489 $ 8,271 $ 5,303 $ 5,868
----------------------------------------------------------------------------------------------------
ASSETS (in thousands of dollars)
Gross property, plant and equipment. . . . . . $ 216,903 $192,940 $172,088 $152,991 $144,251
Net property, plant and equipment. . . . . . . $ 150,256 $131,466 $117,663 $104,266 $ 99,879
Total assets . . . . . . . . . . . . . . . . . $ 210,054 $210,700 $166,989 $145,234 $145,719
Capital expenditures . . . . . . . . . . . . . $ 29,186 $ 23,056 $ 25,917 $ 12,650 $ 13,471
----------------------------------------------------------------------------------------------------
CAPITALIZATION (in thousands of dollars)
Stockholders' equity . . . . . . . . . . . . . $ 66,850 $ 63,972 $ 60,164 $ 56,356 $ 53,656
Long-term debt, net of current maturities. . . $ 48,408 $ 50,921 $ 33,777 $ 37,597 $ 38,226
Total capital. . . . . . . . . . . . . . . . . $ 115,258 $114,893 $ 93,941 $ 93,953 $ 91,882
Current portion of long-term debt. . . . . . . $ 2,686 $ 2,665 $ 2,665 $ 520 $ 1,051
Short-term debt. . . . . . . . . . . . . . . . $ 42,100 $ 25,400 $ 23,000 $ 11,600 $ 7,600
Total capitalization and short-term financing. $ 160,044 $142,958 $119,606 $106,073 $100,533
----------------------------------------------------------------------------------------------------
(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 year 1992, the Company had net income from discontinued operations included in
earnings of $73,500.
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Chesapeake Utilities Corporation Page 16
10-YEAR FINANCIAL & STATISTICAL INFORMATION
----------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1996 1995 1994 (1) 1993 (1) 1992 (1)
----------------------------------------------------------------------------------------------------
OPERATING (IN THOUSANDS OF DOLLARS)
Revenues
Natural gas distribution and transmission. . $ 90,093 $ 79,105 $ 71,716 $ 64,380 $55,877
Propane. . . . . . . . . . . . . . . . . . . 161,812 147,596 20,684 16,908 16,489
Advanced informations systems. . . . . . . . 6,903 7,307 2,288 1,706 1,122
Other. . . . . . . . . . . . . . . . . . . . 1,294 1,277 3,884 2,879 2,447
----------------------------------------------------------------------------------------------------
Total revenues . . . . . . . . . . . . . . . . $ 260,102 $235,285 $ 98,572 $ 85,873 $75,935
Gross margin
Natural gas distribution and transmission. . $ 29,612 $ 29,094 $ 23,943 $ 22,833 $22,055
Propane. . . . . . . . . . . . . . . . . . . 17,579 13,235 9,359 8,579 7,954
Advanced informations systems. . . . . . . . 2,503 1,823 1,281 955 628
Other. . . . . . . . . . . . . . . . . . . . 915 1,016 1,472 1,078 942
----------------------------------------------------------------------------------------------------
Total gross margin . . . . . . . . . . . . . . $ 50,609 $ 45,168 $ 36,055 $ 33,446 $31,579
Operating income before taxes
Natural gas distribution and transmission. . $ 9,625 $ 10,811 $ 7,715 $ 7,207 $ 7,083
Propane. . . . . . . . . . . . . . . . . . . 2,669 2,128 2,288 1,588 1,440
Advanced informations systems. . . . . . . . 1,017 587 (246) 136 70
Other. . . . . . . . . . . . . . . . . . . . 672 508 0 (631) (705)
----------------------------------------------------------------------------------------------------
Total operating income before taxes. . . . . . $ 13,983 $ 14,034 $ 9,757 $ 8,300 $ 7,888
Net income from continuing operations (2). . . $ 7,782 $ 7,696 $ 4,460 $ 3,972 $ 3,549
----------------------------------------------------------------------------------------------------
ASSETS (in thousands of dollars)
Gross property, plant and equipment. . . . . . $ 134,001 $120,746 $110,023 $100,330 $91,039
Net property, plant and equipment. . . . . . . $ 94,014 $ 85,055 $ 75,313 $ 69,794 $64,596
Total assets . . . . . . . . . . . . . . . . . $ 155,787 $130,998 $108,271 $100,775 $89,214
Capital expenditures . . . . . . . . . . . . . $ 15,399 $ 12,887 $ 10,653 $ 10,064 $ 6,720
----------------------------------------------------------------------------------------------------
CAPITALIZATION (in thousands of dollars)
Stockholders' equity . . . . . . . . . . . . . $ 50,700 $ 45,587 $ 37,063 $ 34,817 $33,105
Long-term debt, net of current maturities. . . $ 28,984 $ 31,619 $ 24,329 $ 25,682 $25,668
Total capital. . . . . . . . . . . . . . . . . $ 79,684 $ 77,206 $ 61,392 $ 60,499 $58,773
Current portion of long-term debt. . . . . . . $ 3,526 $ 1,787 $ 1,348 $ 1,286 $ 5,026
Short-term debt. . . . . . . . . . . . . . . . $ 12,735 $ 5,400 $ 8,000 $ 8,900 $ 0
Total capitalization and short-term financing. $ 95,945 $ 84,393 $ 70,740 $ 70,685 $63,799
----------------------------------------------------------------------------------------------------
(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 year 1992, the Company had net income from discontinued operations included in
earnings of $73,500.
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Chesapeake Utilities Corporation Page 17
10-YEAR FINANCIAL & STATISTICAL INFORMATION
--------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999 1998 1997
--------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA AND RATIOS
Basic earnings per share (2) (3) (4). . . . . . . . . . $ 1.25 $ 1.43 $ 1.61 $ 1.05 $ 1.18
Return on average equity. . . . . . . . . . . . . . . . 10.3% 12.1% 14.2% 9.6% 11.3%
Common equity / total capital . . . . . . . . . . . . . 58.0% 55.7% 64.0% 60.0% 58.4%
Common equity / total capital and short-term financing. 41.8% 44.7% 50.3% 53.1% 53.4%
Book value per share. . . . . . . . . . . . . . . . . . $ 12.32 $ 12.08 $ 11.60 $ 11.06 $ 10.72
--------------------------------------------------------------------------------------------------------------------------
Market price:
High. . . . . . . . . . . . . . . . . . . . . . . . . $ 19.900 $ 18.875 $ 19.813 $ 20.500 $ 21.750
Low . . . . . . . . . . . . . . . . . . . . . . . . . $ 17.375 $ 16.250 $ 14.875 $ 16.500 $ 16.250
Close . . . . . . . . . . . . . . . . . . . . . . . . $ 19.800 $ 18.625 $ 18.375 $ 18.313 $ 20.500
--------------------------------------------------------------------------------------------------------------------------
Average number of shares outstanding. . . . . . . . . . 5,367,433 5,249,439 5,144,449 5,060,328 4,972,086
Shares outstanding end of year. . . . . . . . . . . . . 5,424,962 5,297,443 5,186,546 5,093,788 5,004,078
Registered common shareholders. . . . . . . . . . . . . 2,171 2,166 2,212 2,271 2,178
Cash dividends per share. . . . . . . . . . . . . . . . $ 1.09 $ 1.06 $ 1.02 $ 1.00 $ 0.97
Dividend yield (annualized) . . . . . . . . . . . . . . 5.6% 5.8% 5.7% 5.5% 4.7%
Payout ratio. . . . . . . . . . . . . . . . . . . . . . 87.2% 74.1% 63.4% 95.2% 82.2%
--------------------------------------------------------------------------------------------------------------------------
ADDITIONAL DATA
Customers
Natural gas distribution and transmission . . . . . . 42,741 40,854 39,029 37,128 35,797
Propane distribution. . . . . . . . . . . . . . . . . 34,632 35,345 35,267 34,113 33,123
--------------------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF). . . . . . . . . . . 27,264 30,830 27,383 21,400 23,297
Propane distribution (in thousands of gallons). . . . 23,080 28,469 27,788 25,979 26,682
--------------------------------------------------------------------------------------------------------------------------
Heating degree-days (Delmarva Peninsula). . . . . . . . 4,368 4,730 4,082 3,704 4,430
Propane bulk storage capacity (in thousands of gallons) 1,958 1,928 1,926 1,890 1,866
Total employees . . . . . . . . . . . . . . . . . . . . 580 542 522 456 397
--------------------------------------------------------------------------------------------------------------------------
(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 cumulative effect of change in accounting principle.
(4) 1992 excludes earnings per share of $0.02 for discontinued operations.
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Chesapeake Utilities Corporation Page 18
10-YEAR FINANCIAL & STATISTICAL INFORMATION
--------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1996 1995 1994 (1) 1993 (1) 1992 (1)
--------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA AND RATIOS
Basic earnings per share (2) (3) (4). . . . . . . . . . $ 1.58 $ 1.59 $ 1.23 $ 1.12 $ 1.02
Return on average equity. . . . . . . . . . . . . . . . 16.2% 18.6% 12.4% 11.2% 10.5%
Common equity / total capital . . . . . . . . . . . . . 63.6% 59.0% 60.4% 57.5% 56.3%
Common equity / total capital and short-term financing. 52.8% 54.0% 52.4% 49.3% 51.9%
Book value per share. . . . . . . . . . . . . . . . . . $ 10.26 $ 9.38 $ 10.15 $ 9.76 $ 9.50
--------------------------------------------------------------------------------------------------------------------------
Market price:
High. . . . . . . . . . . . . . . . . . . . . . . . . $ 18.000 $ 15.500 $ 15.250 $ 17.500 $ 15.000
Low . . . . . . . . . . . . . . . . . . . . . . . . . $ 15.125 $ 12.250 $ 12.375 $ 13.000 $ 11.500
Close . . . . . . . . . . . . . . . . . . . . . . . . $ 16.875 $ 14.625 $ 12.750 $ 15.375 $ 13.000
--------------------------------------------------------------------------------------------------------------------------
Average number of shares outstanding. . . . . . . . . . 4,912,136 4,836,430 3,628,056 3,551,932 3,477,244
Shares outstanding end of year. . . . . . . . . . . . . 4,939,515 4,860,588 3,653,182 3,575,068 3,487,778
Registered common shareholders. . . . . . . . . . . . . 2,213 2,098 1,721 1,743 1,674
Cash dividends per share. . . . . . . . . . . . . . . . $ 0.93 $ 0.90 $ 0.88 $ 0.86 $ 0.86
Dividend yield (annualized) . . . . . . . . . . . . . . 5.5% 6.2% 6.9% 5.6% 6.6%
Payout ratio. . . . . . . . . . . . . . . . . . . . . . 58.9% 56.6% 71.5% 76.8% 84.3%
--------------------------------------------------------------------------------------------------------------------------
ADDITIONAL DATA
Customers
Natural gas distribution and transmission . . . . . . 34,713 33,530 32,346 31,270 30,407
Propane distribution. . . . . . . . . . . . . . . . . 31,961 31,115 22,180 21,622 21,132
--------------------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF). . . . . . . . . . . 24,835 29,260 22,728 19,444 17,344
Propane distribution (in thousands of gallons). . . . 29,975 26,184 18,395 17,250 17,125
Heating degree-days (Delmarva Peninsula). . . . . . . . 4,717 4,594 4,398 4,705 4,645
Propane bulk storage capacity (in thousands of gallons) 1,860 1,818 1,230 1,140 1,140
Total employees . . . . . . . . . . . . . . . . . . . . 338 335 320 326 317
--------------------------------------------------------------------------------------------------------------------------
(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 cumulative effect of change in accounting principle.
(4) 1992 excludes earnings per share of $0.02 for discontinued operations.
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Chesapeake Utilities Corporation Page 19
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 2001, net cash provided
by operating activities was $15.5 million, cash used by investing activities was
$29.2 million and cash provided by financing activities was $10.3 million. Based
upon anticipated cash requirements in 2002, Chesapeake expects to refinance its
short-term debt through the issuance of long-term debt. The timing of such an
issuance will depend on the nature of the securities involved, the Company's
financial needs and current market and economic conditions.
The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt from various banks and trust companies. As of December 31, 2001, Chesapeake had three unsecured bank lines of credit with two financial institutions, totaling $65.0 million, for short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. One of the bank lines is committed. The other two lines are subject to the banks' availability of funds. The outstanding balances of short-term borrowing at December 31, 2001 and 2000 were $42.1 million and $25.4 million, respectively. In 2001, Chesapeake used funds provided by operations, short-term borrowing and cash on hand to fund capital expenditures. 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, 2001, the Company had an under-recovered purchased gas cost balance of $6.5 million, a decrease of $829,000 from the $7.3 million balance in 2000.
During 2001, 2000 and 1999, capital expenditures were approximately $29.2, $21.8 and $25.1 million, respectively. Capital expenditures increased in 2001 primarily as a result of Eastern Shore Natural Gas expenditures, totaling $16.2 million, related to system expansion. Natural gas distribution also spent approximately $7.7 million for expansion of facilities to serve new customers and for improvements of facilities. Chesapeake has budgeted $16.8 million for capital expenditures during 2002. This amount includes $11.8 million for natural gas distribution and transmission, $2.3 million for propane distribution and marketing, $200,000 for advanced information services and $2.5 million for other operations. The natural gas distribution and transmission expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth and for the replacement of equipment. The advanced information services expenditures are for computer hardware, software and related equipment. Expenditures for other operations include expenditures to support customer growth and replace equipment for water operations and general plant, computer software and hardware. Financing for the 2002 capital expenditure program is expected to be provided from short-term borrowing, cash provided by operating activities and the expected issuance of long-term debt. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors including acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation, availability of capital and new growth opportunities.
Chesapeake has budgeted $846,000 for environmental-related expenditures during 2002 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.
Chesapeake Utilities Corporation Page 20
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 May 2001, Chesapeake issued a note payable of $300,000 at 8.5 percent, due April 6, 2006, in conjunction with a real estate purchase. In December 2000, Chesapeake completed a private placement of $20.0 million of 7.83 percent Senior Notes due January 1, 2015. The Company used the proceeds to repay short-term borrowing.
Chesapeake repaid approximately $2.7 million of long-term debt in both 2001 and 2000. Chesapeake issued common stock in connection with its Automatic Dividend Reinvestment and Stock Purchase Plan, in the amounts of 43,101 shares in 2001, 41,056 shares in 2000 and 36,319 shares in 1999.
RESULTS OF OPERATIONS
Net income for 2001 was $6.7 million compared to $7.5 million for 2000 and $8.3
million for 1999. The reduction in earnings in 2001 was due to declines in the
propane segment and other businesses' contribution to earnings, partially offset
by increases in natural gas and advanced information services. Propane margins
declined due to a 13 percent drop in sales because of warmer temperatures, a
reduction in sales to poultry customers and the continuation of competitive
pressures in some markets the Company serves on the Delmarva Peninsula. Heating
degree-days on the Delmarva Peninsula indicate that temperatures were 8 percent
warmer than 2000 and 1 percent warmer than normal. The margin decrease was
partially offset by savings in operating expenses resulting from cost
containment measures implemented during 2001. The decrease in other operations
is due principally to a drop in pre-tax operating income for the water
businesses resulting from increased overhead due to the development of a
management infrastructure and expansion to new locations. The natural gas
segment improved over 2000 as a result of enhanced margins in the transmission
segment and from a rate increase in Florida and reductions in operating expenses
in Delaware and Maryland. Interest expense increased $770,000 due to an increase
in long-term debt, partially offset by lower short-term interest rates.
PRE-TAX OPERATING INCOME SUMMARY (IN THOUSANDS)
---------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 (DECREASE) 2000 1999 (DECREASE)
---------------------------------------------------------------------------------------------------
BUSINESS SEGMENT:
Natural gas distribution & transmission $14,267 $12,365 $ 1,902 $12,365 $10,300 $ 2,065
Propane . . . . . . . . . . . . . . . . 1,100 2,319 (1,219) 2,319 2,627 (308)
Advanced information services . . . . . 518 336 182 336 1,470 (1,134)
Other & Eliminations. . . . . . . . . . (339) 1,006 (1,345) 1,006 452 554
---------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME. . . . . $15,546 $16,026 $ (480) $16,026 $14,849 $ 1,177
---------------------------------------------------------------------------------------------------
|
The reduction in net income in 2000 compared to 1999 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
Chesapeake Utilities Corporation Page 21
The $863,000 after-tax gain on the sale of the Company's investment in Florida Public Utilities Company is shown in non-operating income on the Company's financial statements.
NATURAL GAS DISTRIBUTION AND TRANSMISSION
Pre-tax operating income increased $1.9 million from 2000 to 2001. The increase
in pre-tax operating income was due to increases contributed by the Company's
Florida operations and the natural gas transmission subsidiary. The Florida
unit's increase was driven by higher margins due to a rate increase implemented
in August 2000 and increased margins from the marketing operation, partially due
to the expansion of transportation services in Florida. In addition, the
transmission subsidiary's margins increased by approximately $1.1 million due to
an increase in firm transportation services provided to its customers. The
transmission subsidiary increased its capacity to provide firm transportation
services by expanding its system. While the margins in Delaware and Maryland
were down by more than $700,000 primarily due to weather, cost reduction
measures implemented in 2001 enabled the Company to maintain earnings in these
two units. The Delaware Division also implemented an interim rate increase,
subject to refund, on October 1, 2001. Included in the Company's operating
expense reduction is a one-time credit adjustment of approximately $280,000 to
establish a regulatory asset for other post retirement benefits which are being
collected through the Company's rates on a "pay-as-you-go" basis in Delaware.
NATURAL GAS DISTRIBUTION AND TRANSMISSION (IN THOUSANDS)
-------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 (DECREASE) 2000 1999 (DECREASE)
-------------------------------------------------------------------------------------------
Revenue. . . . . . . . . . . . $108,234 $99,870 $8,364 $99,870 $75,653 $24,217
Cost of gas. . . . . . . . . . 70,749 64,429 6,320 64,429 43,253 21,176
-------------------------------------------------------------------------------------------
Gross margin . . . . . . . . . 37,485 35,441 2,044 35,441 32,400 3,041
Operations & maintenance . . . 15,008 15,527 (519) 15,527 14,927 600
Depreciation & amortization. . 5,667 5,253 414 5,253 4,803 450
Other taxes. . . . . . . . . . 2,543 2,296 247 2,296 2,370 (74)
-------------------------------------------------------------------------------------------
Pre-tax operating expenses . . 23,218 23,076 142 23,076 22,100 976
-------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME $ 14,267 $12,365 $1,902 $12,365 $10,300 $ 2,065
-------------------------------------------------------------------------------------------
|
Pre-tax operating income increased $2.1 million from 1999 to 2000. The increase
was the result of a $3.0 million increase in gross margin offset by a $1.0
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.
Chesapeake Utilities Corporation Page 22
PROPANE
Pre-tax operating income declined from $2.3 million in 2000 to $1.1 million in
2001. The Delmarva propane operations pre-tax operating income decreased $1.2
million. In addition, the propane start-ups in Florida lost approximately
$293,000 on a pre-tax basis in 2001. The Company's wholesale marketing
subsidiary continued to contribute earnings above the Company's target
expectations in 2001.
PROPANE (IN THOUSANDS)
----------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 (DECREASE) 2000 1999 (DECREASE)
----------------------------------------------------------------------------------------------
Revenue. . . . . . . . . . . . $198,124 $216,273 $(18,149) $216,273 $138,437 $77,836
Cost of sales. . . . . . . . . 183,680 200,278 (16,598) 200,278 124,338 75,940
----------------------------------------------------------------------------------------------
Gross margin . . . . . . . . . 14,444 15,995 (1,551) 15,995 14,099 1,896
Operations & maintenance . . . 11,181 11,608 (427) 11,608 9,623 1,985
Depreciation & amortization. . 1,437 1,429 8 1,429 1,202 227
Other taxes. . . . . . . . . . 726 639 87 639 647 (8)
----------------------------------------------------------------------------------------------
Pre-tax operating expenses . . 13,344 13,676 (332) 13,676 11,472 2,204
----------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME $ 1,100 $ 2,319 $ (1,219) $ 2,319 $ 2,627 $ (308)
----------------------------------------------------------------------------------------------
|
During 2001, the Company's gross margins on the Delmarva Peninsula declined by approximately $1.75 million due to a 13 percent decline in sales volumes. Cost containment measures taken during the second quarter of 2001 generated a $575,000 reduction in operations and maintenance expenses. However, this was not enough to offset the reduced margins on the lower sales volumes. The decline in margins was due to warmer temperatures, a reduction in sales to poultry customers and the continuation of competitive pressures in some of the markets the Company serves on the Peninsula. The decline in sales to the poultry customers comprised 32 percent of the decline in margins. The decreases in volume have been exacerbated by the decline in wholesale prices over the course of the year. Declines in wholesale prices, which are generally good for the long-term, negatively impact the Company in the short-term by devaluing its inventories and fixed price supply contracts. During 2001, the Company wrote down inventory totaling $850,000 due to wholesale price declines. Increased competition has also affected volumes sold. Over the last couple of years, several independent dealers have entered the propane business with pricing strategies designed to acquire market share. The Company's position as the largest or second largest distributor in several of the markets that it serves makes it particularly vulnerable to these tactics.
In 2000, the Company started up three propane distribution operations in Florida. The operations contributed $238,000 to gross margin in 2001.
Although the margins contributed by the marketing operation declined by four percent in 2001, they were still well above the earnings target established by the Company.
Pre-tax operating income for 2000 was $2.3 million compared to $2.6 million for 1999. This decline of $308,000 was the result of an increase in operating expenses of $2.2 million offset by an increase of $1.9 million in gross margin. Operating expenses were higher due to several initiatives the Company undertook to enhance long-term customer service. The initiatives included the opening of a customer service/marketing office in a location convenient to retail shopping, an increase in merchandise sales and service activities and the extension of customer service hours. The Company expects that the Florida propane start-ups may take up to three years to achieve profitability. Gross margin was higher in
Chesapeake Utilities Corporation Page 23
ADVANCED INFORMATION SERVICES
The advanced information services segment provides consulting, custom
programming, training, development tools and website development for national
and international clients. The segment's contribution to pre-tax operating
income increased $182,000 over the depressed levels in 2000, to $518,000 in
2001. The $1.7 million increase in revenue was partially offset by the increase
in the cost of providing the services and the cost of the marketing program
implemented during the first half of the year. Marketing costs during 2001 were
approximately $400,000 over the normal levels the Company expects. WebProEX
sales and related consulting contributed approximately $450,000 of the increase
in revenues during 2001.
ADVANCED INFORMATION SERVICES (IN THOUSANDS)
------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 (DECREASE) 2000 1999 (DECREASE)
------------------------------------------------------------------------------------------
Revenue. . . . . . . . . . . . $14,104 $12,390 $1,714 $12,390 $13,531 $(1,141)
Cost of sales. . . . . . . . . 7,384 6,696 688 6,696 6,956 (260)
------------------------------------------------------------------------------------------
Gross margin . . . . . . . . . 6,720 5,694 1,026 5,694 6,575 (881)
Operations & maintenance . . . 5,361 4,576 785 4,576 4,353 223
Depreciation & amortization. . 256 280 (24) 280 268 12
Other taxes. . . . . . . . . . 585 502 83 502 484 18
------------------------------------------------------------------------------------------
Pre-tax operating expenses . . 6,202 5,358 844 5,358 5,105 253
------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME $ 518 $ 336 $ 182 $ 336 $ 1,470 $(1,134)
------------------------------------------------------------------------------------------
|
The advanced information services segment's 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 6 percent, primarily in the areas of compensation, marketing and uncollectible accounts.
OTHER OPERATIONS
The pre-tax operating loss for the Company's other operations is primarily due
to the decline in the performance of the water businesses.
OTHER OPERATIONS (IN THOUSANDS)
-----------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 (DECREASE) 2000 1999 (DECREASE)
-----------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . $9,859 $6,881 $ 2,978 $6,881 $2,579 $4,302
Cost of sales . . . . . . . . . . . . 4,542 3,426 1,116 3,426 1,616 1,810
-----------------------------------------------------------------------------------------------
Gross margin. . . . . . . . . . . . . 5,317 3,455 1,862 3,455 963 2,492
Operations & maintenance. . . . . . . 4,284 2,021 2,263 2,021 161 1,860
Depreciation & amortization . . . . . 974 180 794 180 251 (71)
Other taxes . . . . . . . . . . . . . 398 248 150 248 99 149
-----------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . 5,656 2,449 3,207 2,449 511 1,938
-----------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING (LOSS) INCOME $ (339) $1,006 $(1,345) $1,006 $ 452 $ 554
-----------------------------------------------------------------------------------------------
|
The water businesses contribution to pre-tax operating income declined by $915,000 in 2001. Water's contribution declined from $190,000 in 2000 to a loss of $725,000 in 2001. Approximately $574,000 of the decline is due to the cost of establishing a corporate infrastructure for the group. In addition, the Michigan unit's performance declined by $218,000 (net of corporate charges). The decrease resulted from a decline in sales and from an increase in depreciation, primarily related to changing out rental equipment. Finally, the two companies acquired in
Chesapeake Utilities Corporation Page 24
Overall, other operations' margins increased by approximately $1.9 million or 54 percent. However, other operations' pre-tax costs increased by $3.2 million or 131 percent.
INCOME TAXES
Operating income taxes were lower in 2001 than 2000, due to lower operating
income and higher interest expense, partially offset by the utilization of a
higher effective tax rate in 2001. In 2001, the Company accrued income taxes at
a federal tax rate of 35 percent as opposed to a 34 percent rate in 2000.
Operating income taxes were higher in 2000 compared to 1999 due to higher pre-tax operating income and a higher composite income tax rate. The higher composite tax rate in 2000 is the net effect of adjusting the 1999 accumulated deferred tax balances to a 35 percent federal rate, partially offset by a reduction in the tax accrual of $238,000 due to a reassessment of known tax exposures.
OTHER INCOME
Non-operating income net of tax was $483,000, $361,000 and $1,066,000 for the
years 2001, 2000 and 1999, 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 net
of tax for 1999 was $203,000.
INTEREST EXPENSE
Interest expense for 2001 increased due to a higher level of long-term debt,
partially offset by lower interest rates on short-term borrowing. 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 ("FERC").
On August 2, 2001, the Delaware Division filed a general rate increase application. Interim rates, subject to refund, went into effect on October 1, 2001. A proposed settlement agreement was reached that would result in an annual increase in rates of approximately $380,000. The proposed settlement is expected to be submitted to the Delaware Public Service Commission for approval in the second quarter of 2002.
In 1999, the Company requested and received approval from the Delaware Public Service Commission to annually adjust its interruptible margin sharing mechanism 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.
As a result of filing the general rate increase application on August 2, 2001, the Delaware Division's previously approved rate design changes in 1999 to its margin sharing mechanism terminated. The previous rate design changes that addressed the level of recovery of fixed distribution costs from its residential and smaller commercial customers in relation to its margin sharing mechanism and the actual weather experienced, ended upon the implementation of interim rates on October 1, 2001. There was no impact on margins in 2001 due to this mechanism.
Chesapeake Utilities Corporation Page 25
On November 30, 2001, the Commission issued an order, which accepted and suspended the effectiveness of the rates until May 1, 2002 subject to refund and the outcome of a hearing. A pre-hearing conference was held on December 18, 2001 and the hearing was scheduled for September 24, 2002. Discovery related to the rate proceeding began in January 2002 with FERC Staff data requests. The outcome of the proceedings is uncertain.
In January 2000, the Company filed a request for approval of a rate increase with the Florida Public Service Commission. Interim rates subject to refund, went into effect in August 2000. In November 2000, an order was issued approving the rate increase, which became effective in early December 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.
ENVIRONMENTAL MATTERS
The Company continues to work with federal and state environmental agencies to
assess the environmental impact and explore corrective action at three 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 H to the
Consolidated Financial Statements for annual maturities of consolidated
long-term debt). All of Chesapeake's long-term debt is fixed-rate debt and was
not entered into for trading purposes. The carrying value of the Company's
long-term debt was $51.1 million at December 31, 2001 as compared to a fair
value of $56.9 million, based mainly on current market prices or discounted cash
flows using current rates for similar issues with similar terms and remaining
maturities. The Company is exposed to changes in interest rates as a result of
financing through its issuance of fixed-rate long-term debt. The Company
evaluates whether to refinance existing debt or permanently finance existing
short-term borrowing based in part on the fluctuation in interest rates.
The Company's propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. The Company can store up to approximately 4 million gallons of propane during the winter season to meet its customers' peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline.
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
Chesapeake Utilities Corporation Page 26
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, 2001 and 2000 is shown below.
-----------------------------------------------------------------------------
QUANTITY ESTIMATED WEIGHTED AVERAGE
AT DECEMBER 31, 2001 IN GALLONS MARKET PRICES CONTRACT PRICES
-----------------------------------------------------------------------------
FORWARD CONTRACTS
Sale. . . . . . . . . 11,877,600 $0.3275 - $0.3375 $0.3876
Purchase. . . . . . . 9,660,000 $0.3275 - $0.3375 $0.4032
FUTURES CONTRACTS
Sale. . . . . . . . . 840,000 $0.3275 - $0.3300 $0.3325
-----------------------------------------------------------------------------
Estimated market prices and weighted average contract prices are in dollars per
gallon.
All contracts expire in 2002.
|
AT DECEMBER 31, 2000 ----------------------------------------------------------------------------- FORWARD CONTRACTS Sale. . . . . . . . . 33,007,800 $0.6800 - $1.2000 $0.7869 Purchase. . . . . . . 33,419,400 $0.5625 - $1.0200 $0.7597 FUTURES CONTRACTS Sale. . . . . . . . . 2,814,000 $0.6800 - $0.8700 $0.7714 Purchase. . . . . . . 1,260,000 $0.5625 - $0.7700 $0.5397 ----------------------------------------------------------------------------- Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expired in 2001. |
The Company's natural gas distribution operations have entered into agreements with natural gas suppliers to purchase natural gas for resale to their customers. Purchases under these contracts are considered "normal purchases and sales" under Statement of Financial Accounting Standards ("SFAS") No. 133 and are not marked-to-market.
COMPETITION
The Company's natural gas operations compete with other forms of energy
including electricity, oil and propane. The principal competitive factors are
price, and to a lesser extent, accessibility. The Company's natural gas
distribution operations have several large volume industrial customers that have
the capacity to use fuel oil as an alternative to natural gas. When oil prices
decline, these interruptible customers convert to oil to satisfy their fuel
requirements. Lower levels in interruptible sales occur when oil prices are
lower relative to the price of natural gas. Oil prices, as well as the prices of
electricity and other fuels are subject to fluctuation for a variety of reasons;
therefore, future competitive conditions are not predictable. To address this
uncertainty, the Company uses flexible pricing arrangements on both the supply
and sales side of its business to maximize sales volumes. As a result of the
transmission business' conversion to open access, this business has shifted from
providing competitive sales service to providing transportation and contract
storage services.
The Company's natural gas distribution operations located in Maryland, Delaware and Florida began offering transportation services to certain industrial customers during 1998, 1997 and 1994, respectively. In 2001, the Florida operations extended transportation service to commercial customers. With transportation services now available on the Company's distribution systems, the Company is competing with third party suppliers to sell gas to industrial
Chesapeake Utilities Corporation Page 27
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. Some of these competitors have pricing strategies designed to acquire market share.
The Company's advanced information services segment faces competition from a number of competitors, some of which have greater resources available to them than those of the Company. This segment competes on the basis of technological expertise, reputation and price.
The water businesses face competition from a variety of national and local suppliers of water conditioning and treatment services and bottled water.
INFLATION
Inflation affects the cost of labor, products and services required for
operation, maintenance and capital improvements. While the impact of inflation
has remained low in recent years, natural gas and propane prices are subject to
rapid fluctuations. Fluctuations in natural gas prices are passed on to
customers through the gas cost recovery mechanism in the Company's tariffs. To
help cope with the effects of inflation on its capital investments and returns,
the Company seeks rate relief from regulatory commissions for regulated
operations while monitoring the returns of its unregulated business operations.
To compensate for fluctuations in propane gas prices, Chesapeake adjusts its
propane selling prices to the extent allowed by the market.
RECENT PRONOUNCEMENTS
Effective January 1, 2001, the Company adopted Financial Accounting Standards
Board ("FASB") SFAS No. 133 as amended by SFAS No. 137 and 138, which
established accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. Their adoption did not have a material impact on the
Company's financial position or results of operations.
On June 30, 2001, the FASB issued SFAS Nos. 141, 142 and 143. SFAS No. 141, "Business Combinations," eliminates the pooling-of-interest method of accounting for business combinations and requires the use of the purchase method. In addition, the reassessment of intangible assets to determine whether they are appropriately classified either separately or within goodwill is required. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. The Company adopted SFAS No. 141 on July 1, 2001 with no material impact on net income.
SFAS No. 142, "Goodwill and Other Intangible Assets," eliminates the amortization of goodwill and other acquired intangible assets with indefinite economic useful lives. SFAS No. 142 requires an annual impairment test of goodwill and other intangible assets that are not subject to amortization. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001; however, amortization of goodwill for acquisitions completed after June 30, 2001 was prohibited. The impact of adopting SFAS No. 142 has not yet been determined, but could be significant if future results of the new water businesses do not meet expectations.
Chesapeake Utilities Corporation Page 28
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," replaces SFAS No. 121. The statement develops one accounting model for long-lived assets to be disposed of by sale and addresses significant implementation issues. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The effect of implementing SFAS No. 144 has not yet been determined.
CAUTIONARY STATEMENT
Chesapeake has made statements in this report that are considered to be
forward-looking statements. These statements are not matters of historical fact.
Sometimes they contain words such as "believes," "expects," "intends," "plans,"
"will," or "may," and other similar words of a predictive nature. These
statements relate to matters such as customer growth, changes in revenues or
margins, capital expenditures, environmental remediation costs, regulatory
approvals, market risks associated with the Company's propane marketing
operation, competition and other matters. It is important to understand that
these forward-looking statements are not guarantees, but are subject to certain
risks and uncertainties and other important factors that could cause actual
results to differ materially from those in the forward-looking statements. These
factors include, among other things:
- 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 regulatory requirements,
including deregulation;
- 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.
Chesapeake Utilities Corporation Page 29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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/ PRICEWATERHOUSE COOPERS LLP PricewaterhouseCoopers LLP Philadelphia, Pennsylvania February 15, 2002 |
Chesapeake Utilities Corporation Page 30
CONSOLIDATED STATEMENTS OF INCOME
--------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
--------------------------------------------------------------------------------
OPERATING REVENUES . . . . . . . . . $330,320,958 $335,412,844 $230,200,335
COST OF SALES. . . . . . . . . . . . 266,355,278 274,828,371 176,162,693
--------------------------------------------------------------------------------
GROSS MARGIN . . . . . . . . . . . . 63,965,680 60,584,473 54,037,642
--------------------------------------------------------------------------------
OPERATING EXPENSES
Operations . . . . . . . . . . . 34,055,855 31,862,975 27,543,188
Maintenance. . . . . . . . . . . 1,778,760 1,868,260 1,521,302
Depreciation and amortization. . 8,333,482 7,142,611 6,523,669
Other taxes. . . . . . . . . . . 4,251,825 3,684,656 3,600,345
Income taxes . . . . . . . . . . 4,027,543 4,387,925 4,174,896
--------------------------------------------------------------------------------
Total operating expenses . . . . . . 52,447,465 48,946,427 43,363,400
--------------------------------------------------------------------------------
OPERATING INCOME . . . . . . . . . . 11,518,215 11,638,046 10,674,242
--------------------------------------------------------------------------------
OTHER INCOME
Gain on sale of investment . . . 0 0 1,415,343
Interest income. . . . . . . . . 456,240 220,462 99,660
Other income . . . . . . . . . . 251,491 248,748 60,799
Income taxes . . . . . . . . . . (224,731) (108,667) (509,351)
--------------------------------------------------------------------------------
Total other income . . . . . . . . . 483,000 360,543 1,066,451
--------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES . . . 12,001,215 11,998,589 11,740,693
--------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt . . . 3,998,264 2,628,781 2,793,712
Interest on short-term borrowing 1,215,528 1,699,402 551,937
Amortization of debt expense . . 101,183 111,122 117,966
Other. . . . . . . . . . . . . . (35,297) 70,083 6,092
--------------------------------------------------------------------------------
Total interest charges . . . . . . . 5,279,678 4,509,388 3,469,707
--------------------------------------------------------------------------------
NET INCOME . . . . . . . . . . . . . $ 6,721,537 $ 7,489,201 $ 8,270,986
================================================================================
EARNINGS PER SHARE OF COMMON STOCK:
Basic. . . . . . . . . . . . . . $ 1.25 $ 1.43 $ 1.61
Diluted. . . . . . . . . . . . . $ 1.24 $ 1.40 $ 1.57
|
See accompanying notes
Chesapeake Utilities Corporation Page 31
CONSOLIDATED BALANCE SHEETS
ASSETS
----------------------------------------------------------------------------------------------------
AT DECEMBER 31, 2001 2000
----------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Natural gas distribution and transmission . . . . . . . . . . . . . $170,254,892 $149,121,319
Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,877,317 31,630,208
Advanced information services . . . . . . . . . . . . . . . . . . . 1,521,144 1,699,968
Other plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,249,442 10,488,581
----------------------------------------------------------------------------------------------------
Total property, plant and equipment . . . . . . . . . . . . . . . . . . 216,902,795 192,940,076
Less: Accumulated depreciation and amortization. . . . . . . . . . . . (66,646,944) (61,473,757)
----------------------------------------------------------------------------------------------------
Net property, plant and equipment . . . . . . . . . . . . . . . . . . . 150,255,851 131,466,319
----------------------------------------------------------------------------------------------------
INVESTMENTS, AT FAIR MARKET VALUE . . . . . . . . . . . . . . . . . . . 517,901 616,293
----------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . 1,188,335 4,606,316
Accounts receivable (less allowance for uncollectibles of $621,516
and $549,961 in 2001 and 2000, respectively). . . . . . . . . . . 21,266,309 37,941,172
Materials and supplies, at average cost . . . . . . . . . . . . . . 1,106,995 1,566,126
Merchandise inventory, at average cost. . . . . . . . . . . . . . . 1,610,786 1,234,072
Propane inventory, at average cost. . . . . . . . . . . . . . . . . 2,518,871 4,379,599
Storage gas prepayments . . . . . . . . . . . . . . . . . . . . . . 4,326,416 3,500,323
Underrecovered purchased gas costs. . . . . . . . . . . . . . . . . 6,519,754 5,388,725
Income taxes receivable . . . . . . . . . . . . . . . . . . . . . . 675,504 1,159,761
Prepaid expenses and other current assets . . . . . . . . . . . . . 1,932,246 2,015,276
----------------------------------------------------------------------------------------------------
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . 41,145,216 61,791,370
----------------------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Environmental regulatory assets . . . . . . . . . . . . . . . . . . 2,677,010 2,910,000
Environmental expenditures. . . . . . . . . . . . . . . . . . . . . 3,189,156 3,626,475
Underrecovered purchased gas costs. . . . . . . . . . . . . . . . . 0 1,959,562
Other deferred charges and intangible assets. . . . . . . . . . . . 12,342,923 8,329,484
----------------------------------------------------------------------------------------------------
Total deferred charges and other assets . . . . . . . . . . . . . . . . 18,209,089 16,825,521
----------------------------------------------------------------------------------------------------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $210,128,057 $210,699,503
====================================================================================================
|
See accompanying notes
Chesapeake Utilities Corporation Page 32
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
----------------------------------------------------------------------------------------------------
AT DECEMBER 31, 2001 2000
----------------------------------------------------------------------------------------------------
CAPITALIZATION
Stockholders' equity
Common stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,640,060 $ 2,577,992
Additional paid-in capital. . . . . . . . . . . . . . . . . . . . . 29,653,992 27,672,005
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . 34,555,560 33,721,747
----------------------------------------------------------------------------------------------------
Total stockholders' equity. . . . . . . . . . . . . . . . . . . . . . . 66,849,612 63,971,744
Long-term debt, net of current maturities . . . . . . . . . . . . . . . 48,408,596 50,920,818
----------------------------------------------------------------------------------------------------
Total capitalization. . . . . . . . . . . . . . . . . . . . . . . . . . 115,258,208 114,892,562
----------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current maturities of long-term debt. . . . . . . . . . . . . . . . 2,686,145 2,665,091
Short-term borrowing. . . . . . . . . . . . . . . . . . . . . . . . 42,100,000 25,400,000
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . 14,551,621 33,654,718
Refunds payable to customers. . . . . . . . . . . . . . . . . . . . 971,575 1,015,128
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . . 1,758,401 595,175
Dividends payable . . . . . . . . . . . . . . . . . . . . . . . . . 1,491,832 1,429,945
Deferred income taxes payable . . . . . . . . . . . . . . . . . . . 848,271 985,349
Other accrued liabilities . . . . . . . . . . . . . . . . . . . . . 5,327,457 5,674,419
----------------------------------------------------------------------------------------------------
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . 69,735,302 71,419,825
----------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . 15,732,842 15,086,951
Deferred investment tax credits . . . . . . . . . . . . . . . . . . 602,357 657,172
Environmental liability . . . . . . . . . . . . . . . . . . . . . . 3,199,733 2,910,000
Accrued pension costs . . . . . . . . . . . . . . . . . . . . . . . 1,595,650 1,625,128
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . 4,003,965 4,107,865
----------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities. . . . . . . . . . . . . . 25,134,547 24,387,116
----------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
(NOTES L AND M)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . . . . . . . . . $210,128,057 $210,699,503
====================================================================================================
|
See accompanying notes
Chesapeake Utilities Corporation Page 33
CONSOLIDATED STATEMENTS OF CASH FLOWS
------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,721,537 $ 7,489,201 $ 8,270,986
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization. . . . . . . . . . . . . . . . 9,094,068 8,044,315 7,509,841
Investment tax credit adjustments, net . . . . . . . . . . . (54,815) (54,815) (54,815)
Deferred income taxes, net . . . . . . . . . . . . . . . . . 508,813 2,922,815 385,103
Mark-to-market adjustments . . . . . . . . . . . . . . . . . 906,551 (689,032) 65,076
Employee benefits. . . . . . . . . . . . . . . . . . . . . . (29,478) 80,165 8,659
Employee compensation. . . . . . . . . . . . . . . . . . . . 223,255 217,000 298,756
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . (27,897) (816,049) 212,711
Changes in assets and liabilities:
Accounts receivable, net . . . . . . . . . . . . . . . . . . 16,549,829 (16,745,492) (6,814,506)
Inventories, storage gas and materials . . . . . . . . . . . 1,117,052 (3,307,421) (1,704,543)
Prepaid expenses and other current assets. . . . . . . . . . 83,031 217,126 (11,850)
Other deferred charges . . . . . . . . . . . . . . . . . . . (1,725,090) 95,657 1,120,355
Accounts payable, net. . . . . . . . . . . . . . . . . . . . (19,103,098) 16,789,601 5,794,475
Refunds payable to customers . . . . . . . . . . . . . . . . (43,553) 235,620 143,355
Over (under) recovered purchased gas costs . . . . . . . . . 828,533 (6,111,373) 315,351
Other current liabilities. . . . . . . . . . . . . . . . . . 401,860 (688) 1,058,357
------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities. . . . . . . . . . . . 15,450,598 8,366,630 16,597,311
------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant and equipment expenditures . . . . . . . . . . (29,185,807) (21,821,005) (25,128,669)
Sale of investments. . . . . . . . . . . . . . . . . . . . . . 0 0 2,189,312
------------------------------------------------------------------------------------------------------------
Net cash used by investing activities. . . . . . . . . . . . . . (29,185,807) (21,821,005) (22,939,357)
------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Common stock dividends, net of amounts reinvested of $609,793,
$520,712 & $456,962 in 2001, 2000 & 1999, respectively . . . (5,216,044) (5,022,313) (4,774,338)
Issuance of stock:
Dividend Reinvestment Plan optional cash . . . . . . . . . . 191,765 197,797 187,369
Retirement Savings Plan. . . . . . . . . . . . . . . . . . . 1,023,919 916,159 816,306
Net borrowing under line of credit agreements. . . . . . . . . 16,700,000 2,400,000 11,400,000
Proceeds from issuance of long-term debt, net. . . . . . . . . 300,000 19,887,194 0
Repayment of long-term debt. . . . . . . . . . . . . . . . . . (2,682,412) (2,675,319) (1,528,202)
------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities. . . . . . . . . . . . 10,317,228 15,703,518 6,101,135
------------------------------------------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS . . . . . . (3,417,981) 2,249,143 (240,911)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR . . . . . . . . . 4,606,316 2,357,173 2,598,084
------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR . . . . . . . . . . . . $ 1,188,335 $ 4,606,316 $ 2,357,173
============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest . . . . . . . . . . . . . . . . . . . . $ 4,128,477 $ 4,410,230 $ 3,409,070
Cash paid for income taxes . . . . . . . . . . . . . . . . . . $ 3,601,400 $ 3,212,080 $ 4,413,155
|
See accompanying notes
Chesapeake Utilities Corporation Page 34
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
--------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
--------------------------------------------------------------------------------------
COMMON STOCK
Balance beginning of year . . . . . . . . . $ 2,577,992 $ 2,524,018 $ 2,479,019
Dividend Reinvestment Plan. . . . . . . . 20,977 19,983 17,530
Retirement Savings Plan . . . . . . . . . 26,730 25,353 22,489
Conversion of debentures. . . . . . . . . 3,117 5,173 4,201
Performance shares and options exercised. 11,244 3,465 779
--------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . 2,640,060 2,577,992 2,524,018
--------------------------------------------------------------------------------------
ADDITIONAL PAID-IN CAPITAL
Balance beginning of year . . . . . . . . . 27,672,005 25,782,824 24,192,188
Dividend Reinvestment Plan. . . . . . . . 780,582 698,526 626,801
Retirement Savings Plan . . . . . . . . . 997,187 890,806 793,817
Conversion of debentures. . . . . . . . . 105,639 175,599 142,597
Performance shares and options exercised. 98,579 124,250 27,421
--------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . 29,653,992 27,672,005 25,782,824
--------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance beginning of year . . . . . . . . . 33,721,747 31,857,732 28,892,384
Net income. . . . . . . . . . . . . . . . 6,721,537 7,489,201 8,270,986
Cash dividends (1). . . . . . . . . . . . (5,887,724) (5,625,186) (5,305,638)
--------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . 34,555,560 33,721,747 31,857,732
--------------------------------------------------------------------------------------
UNEARNED COMPENSATION
Balance beginning of year . . . . . . . . . 0 0 (71,041)
Amortization of prior years' awards . . . 0 0 71,041
--------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . 0 0 0
--------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY. . . . . . . . . . $66,849,612 $63,971,744 $60,164,574
======================================================================================
(1) Cash dividends per share for 2001, 2000 and 1999 were $1.09, $1.06 and $1.02,
respectively.
|
See accompanying notes
Chesapeake Utilities Corporation Page 35
CONSOLIDATED STATEMENTS OF INCOME TAXES --------------------------------------------------------------------------------------------- FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999 --------------------------------------------------------------------------------------------- CURRENT INCOME TAX EXPENSE Federal . . . . . . . . . . . . . . . . . . . . . . $ 3,194,125 $ 1,598,184 $3,948,746 State . . . . . . . . . . . . . . . . . . . . . . . 602,548 264,294 807,214 Investment tax credit adjustments, net. . . . . . . (54,815) (54,815) (54,815) --------------------------------------------------------------------------------------------- Total current income tax expense. . . . . . . . . . . 3,741,858 1,807,663 4,701,145 --------------------------------------------------------------------------------------------- DEFERRED INCOME TAX EXPENSE (1) Property, plant and equipment . . . . . . . . . . . 769,264 1,071,852 734,765 Deferred gas costs. . . . . . . . . . . . . . . . . (236,971) 2,404,994 (124,576) Pensions and other employee benefits. . . . . . . . (71,089) (115,615) (153,697) Unbilled revenue. . . . . . . . . . . . . . . . . . 303,136 (736,700) (45,290) Contributions in aid of construction. . . . . . . . 0 0 (160,971) Environmental expenditures. . . . . . . . . . . . . (142,362) 879 97,480 Other (2) . . . . . . . . . . . . . . . . . . . . . (111,562) 63,519 (364,609) --------------------------------------------------------------------------------------------- Total deferred income tax expense . . . . . . . . . . 510,416 2,688,929 (16,898) --------------------------------------------------------------------------------------------- TOTAL INCOME TAX EXPENSE. . . . . . . . . . . . . . . $ 4,252,274 $ 4,496,592 $4,684,247 ============================================================================================= RECONCILIATION OF EFFECTIVE INCOME TAX RATES Federal income tax expense (3). . . . . . . . . . . $ 3,840,832 $ 4,075,170 $4,404,779 State income taxes, net of federal benefit. . . . . 492,850 489,831 553,444 Other (2) . . . . . . . . . . . . . . . . . . . . . (81,408) (68,409) (273,976) --------------------------------------------------------------------------------------------- TOTAL INCOME TAX EXPENSE. . . . . . . . . . . . . . . $ 4,252,274 $ 4,496,592 $4,684,247 ============================================================================================= EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 38.7% 37.5% 36.2% |
--------------------------------------------------------------------------------
AT DECEMBER 31, 2001 2000
--------------------------------------------------------------------------------
DEFERRED INCOME TAXES
DEFERRED INCOME TAX LIABILITIES:
Property, plant and equipment . . . . . . . . . . $15,730,682 $15,088,379
Environmental costs . . . . . . . . . . . . . . . 1,286,226 1,478,259
Deferred gas costs. . . . . . . . . . . . . . . . 2,607,170 2,844,140
Other . . . . . . . . . . . . . . . . . . . . . . 935,104 736,255
--------------------------------------------------------------------------------
Total deferred income tax liabilities . . . . . . . 20,559,182 20,147,033
--------------------------------------------------------------------------------
DEFERRED INCOME TAX ASSETS:
Unbilled revenue. . . . . . . . . . . . . . . . . 1,487,428 1,790,563
Pension and other employee benefits . . . . . . . 1,464,878 1,382,628
Self insurance. . . . . . . . . . . . . . . . . . 535,141 502,416
Other . . . . . . . . . . . . . . . . . . . . . . 490,622 399,126
--------------------------------------------------------------------------------
Total deferred income tax assets. . . . . . . . . . 3,978,069 4,074,733
--------------------------------------------------------------------------------
DEFERRED INCOME TAXES PER CONSOLIDATED BALANCE SHEET. $16,581,113 $16,072,300
================================================================================
(1) Includes $102,000, $298,000 and $39,000 of deferred state income taxes for the years
2001, 2000 and 1999, 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 charge to adjust deferred
income taxes to the 35% federal income tax rate.
(3) Federal income taxes for 2001 were recorded at 35%. The years 2000 and 1999 were
recorded at 34%.
|
See accompanying notes
Chesapeake Utilities Corporation Page 36
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. The Company does not have any ownership interests in special
purpose entities. 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, 18 percent for advanced information services and 9 percent for
general plant.
CASH AND CASH EQUIVALENTS
The Company's policy is to invest cash in excess of operating requirements in
overnight income producing accounts. Such amounts are stated at cost, which
approximates market value. Investments with an original maturity of three months
or less are considered cash equivalents.
INVENTORIES
The Company uses the average cost method to value inventory. If the market
prices drop below average cost, inventory balances are adjusted to market
values.
Chesapeake Utilities Corporation Page 37
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. Except for goodwill on acquisitions that were completed after June 30, 2001, intangible assets are amortized on a straight-line basis over a weighted average period of 21 years. Goodwill related to acquisitions completed after June 30, 2001 is not amortized, in accordance with SFAS No. 142. Gross intangibles and the net unamortized balance at December 31, 2001 were $8.7 million and $7.7 million, respectively. Gross intangibles and the net unamortized balance at December 31, 2000 were $7.7 million and $5.9 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, 2001, there was an
unrealized loss of $75,000. At December 31, 2000, there was an unrealized gain
of $831,000. Trading liabilities are recorded in other accrued liabilities.
Trading assets are recorded in prepaid expenses and other current assets.
The Company's natural gas distribution operations have entered into agreements with natural gas suppliers to purchase natural gas for resale to their customers. Purchases under these contracts are considered "normal purchases and sales" under SFAS No. 133 and are not marked-to-market.
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 Utilities Corporation Page 38
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
below. In 2001, the effect of assuming the exercise of the outstanding stock
options would have been anti-dilutive; therefore it was not included in the
calculations.
------------------------------------------------------------------------------- FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999 ------------------------------------------------------------------------------- CALCULATION OF BASIC EARNINGS PER SHARE: Net Income . . . . . . . . . . . . . . . . $6,721,537 $7,489,201 $8,270,986 Weighted Average Shares Outstanding. . . . 5,367,433 5,249,439 5,144,449 ------------------------------------------------------------------------------- BASIC EARNINGS PER SHARE . . . . . . . . . $ 1.25 $ 1.43 $ 1.61 =============================================================================== CALCULATION OF DILUTED EARNINGS PER SHARE: Reconciliation of Numerator: Net Income basic . . . . . . . . . . . . . $6,721,537 $7,489,201 $8,270,986 Effect of 8.25% Convertible debentures . . 171,725 179,701 188,982 ------------------------------------------------------------------------------- Adjusted numerator diluted . . . . . . . . $6,893,262 $7,668,902 $8,459,968 ------------------------------------------------------------------------------- Reconcilation of Denominator: Weighted Shares Outstanding basic. . . . . 5,367,433 5,249,439 5,144,449 Effect of 8.25% Convertible debentures . . 201,125 209,893 220,732 Effect of stock options. . . . . . . . . . 0 11,484 11,875 Effect of stock warrants . . . . . . . . . 849 0 0 ------------------------------------------------------------------------------- Adjusted denominator diluted . . . . . . . 5,569,407 5,470,816 5,377,056 ------------------------------------------------------------------------------- DILUTED EARNINGS PER SHARE . . . . . . . . $ 1.24 $ 1.40 $ 1.57 =============================================================================== |
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
Effective January 1, 2001, the Company adopted Financial Accounting Standards
Board ("FASB") SFAS No. 133 as amended by SFAS No. 137 and 138, which
established accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. Their adoption did not have a material impact on the
Company's financial position or results of operations.
Chesapeake Utilities Corporation Page 39
SFAS No. 142, "Goodwill and Other Intangible Assets," eliminates the amortization of goodwill and other acquired intangible assets with indefinite economic useful lives. SFAS No. 142 requires an annual impairment test of goodwill and other intangible assets that are not subject to amortization. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001; however, amortization of goodwill for acquisitions completed after June 30, 2001 was prohibited. The impact of adopting SFAS No. 142 has not yet been determined but could be material if future results of the new water businesses do not meet expectations.
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides guidance on the accounting for obligations associated with the retirement of long-lived assets. SFAS No. 143 requires a liability to be recognized in the financial statements for retirement obligations meeting specific criteria. Measurement of the initial obligation is to approximate fair value with an equivalent amount recorded as an increase in the value of the capitalized asset. The asset will be depreciable in accordance with normal depreciation policy and the liability will be increased, with a charge to the income statement, until the obligation is settled. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The potential impact of adopting SFAS No. 143 has not yet been determined.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," replaces SFAS No. 121. The statement develops one accounting model for long-lived assets to be disposed of by sale and addresses significant implementation issues. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The effect of implementing SFAS No. 144 has not yet been determined.
RESTATEMENT AND RECLASSIFICATION OF PRIOR YEARS' AMOUNTS
Certain prior years' amounts have been reclassified to conform to the current
year presentation.
B. BUSINESS COMBINATIONS
During 2001, Chesapeake acquired Absolute Water Care, Inc. and selected assets
of Aquarius Systems, Inc. and Automatic Water Conditioning, Inc., three water
conditioning and treatment dealerships operating in Florida. In July 2001,
Chesapeake purchased selected assets of EcoWater Systems of Rochester, located
in Rochester, Minnesota and Intermountain Water, Inc. and Blue Springs Water,
located in Boise, Idaho. These companies provide water treatment, water
conditioning and bottled water to customers in those geographic regions.
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.
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.
These acquisitions were all accounted for as purchases and the Company's financial results include the results of operations from the dates of acquisition.
Chesapeake Utilities Corporation Page 40
--------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
--------------------------------------------------------------------------------------------
OPERATING REVENUES, UNAFFILIATED CUSTOMERS
Natural gas distribution and transmission . . . $108,122,037 $ 99,750,303 $ 75,592,453
Propane . . . . . . . . . . . . . . . . . . . . 198,124,011 216,272,941 138,436,520
Advanced information services . . . . . . . . . 14,103,890 12,353,056 13,531,261
Other . . . . . . . . . . . . . . . . . . . . . 9,971,020 7,036,544 2,640,101
--------------------------------------------------------------------------------------------
Total operating revenues, unaffiliated customers. $330,320,958 $335,412,844 $230,200,335
--------------------------------------------------------------------------------------------
INTERSEGMENT REVENUES (1)
Natural gas distribution and transmission . . . $ 112,006 $ 119,480 $ 61,141
Advanced information services . . . . . . . . . 0 36,535 0
Other . . . . . . . . . . . . . . . . . . . . . 783,051 814,995 659,624
--------------------------------------------------------------------------------------------
Total intersegment revenues . . . . . . . . . . . $ 895,057 $ 971,010 $ 720,765
--------------------------------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES
Natural gas distribution and transmission . . . $ 14,267,044 $ 12,364,535 $ 10,300,455
Propane . . . . . . . . . . . . . . . . . . . . 1,100,440 2,319,461 2,627,123
Advanced information services . . . . . . . . . 517,427 335,849 1,469,958
Other and eliminations. . . . . . . . . . . . . (339,153) 1,006,126 451,602
--------------------------------------------------------------------------------------------
Total operating income before income taxes. . . . $ 15,545,758 $ 16,025,971 $ 14,849,138
--------------------------------------------------------------------------------------------
DEPRECIATION AND AMORTIZATION
Natural gas distribution and transmission . . . $ 5,667,001 $ 4,930,445 $ 4,762,285
Propane . . . . . . . . . . . . . . . . . . . . 1,436,550 1,429,405 1,201,693
Advanced information services . . . . . . . . . 255,760 280,053 268,082
Other . . . . . . . . . . . . . . . . . . . . . 974,171 502,708 291,609
--------------------------------------------------------------------------------------------
Total depreciation and amortization . . . . . . . $ 8,333,482 $ 7,142,611 $ 6,523,669
--------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Natural gas distribution and transmission . . . $ 23,791,057 $ 17,882,724 $ 17,853,885
Propane . . . . . . . . . . . . . . . . . . . . 1,847,913 3,235,288 2,168,269
Advanced information services . . . . . . . . . 252,159 240,727 372,501
Other . . . . . . . . . . . . . . . . . . . . . 3,294,678 1,696,990 5,522,615
--------------------------------------------------------------------------------------------
Total capital expenditures. . . . . . . . . . . . $ 29,185,807 $ 23,055,729 $ 25,917,270
--------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------
AT DECEMBER 31, 2001 2000 1999
--------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Natural gas distribution and transmission . . . $153,576,226 $141,335,457 $117,024,633
Propane . . . . . . . . . . . . . . . . . . . . 32,413,785 47,495,133 31,888,633
Advanced information services . . . . . . . . . 2,583,740 2,372,407 2,854,670
Other . . . . . . . . . . . . . . . . . . . . . 21,554,306 19,496,506 15,220,578
--------------------------------------------------------------------------------------------
Total identifiable assets . . . . . . . . . . . . $210,128,057 $210,699,503 $166,988,514
--------------------------------------------------------------------------------------------
(1) All significant intersegment revenues are billed at market rates and have been
eliminated from consolidated revenues.
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Chesapeake Utilities Corporation Page 41
E. INVESTMENTS
The investment balances at December 31, 2001 and 2000 consisted primarily of a
Rabbi Trust ("the trust") associated with the acquisition of Xeron, Inc. The
Company has classified the underlying investments held by the trust as trading
securities, which require all gains and losses to be recorded into 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.
F. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL
The following is a schedule of changes in the Company's shares of common stock.
-----------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
-----------------------------------------------------------------------------------------
COMMON STOCK: SHARES ISSUED AND OUTSTANDING (1)
Balance beginning of year . . . . . . . . . . . . . . . 5,297,443 5,186,546 5,093,788
Dividend Reinvestment Plan (2). . . . . . . . . . . . 43,101 41,056 36,319
Sale of stock to the Company's Retirement Savings Plan 54,921 52,093 46,208
Conversion of debentures. . . . . . . . . . . . . . . 6,395 10,628 8,631
Performance shares and options exercised. . . . . . . 23,102 7,120 1,600
-----------------------------------------------------------------------------------------
Balance end of year (3) . . . . . . . . . . . . . . . . 5,424,962 5,297,443 5,186,546
-----------------------------------------------------------------------------------------
(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 had 30,446 and 7,442 shares held in Rabbi Trusts at December 31,
2001 and 2000, respectively.
|
In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 shares of Company stock in 2001 at a price of $18.25 per share and 15,000 shares in 2000 at a price of $18.00. The warrants are exercisable during a seven-year period after the date granted. The Company has recognized expenses of $47,500 related to the warrants. No warrants have been exercised.
Chesapeake Utilities Corporation Page 42
H. LONG-TERM DEBT
The outstanding long-term debt, net of current maturities, is as shown below.
-------------------------------------------------------------------- AT DECEMBER 31, 2001 2000 -------------------------------------------------------------------- First mortgage sinking fund bonds: 9.37% Series I, due December 15, 2004 $ 1,512,000 $ 2,268,000 Uncollateralized senior notes: 7.97% note, due February 1, 2008. . . . 6,000,000 7,000,000 6.91% note, due October 1, 2010 . . . . 7,272,727 8,181,818 6.85% note, due January 1, 2012 . . . . 10,000,000 10,000,000 7.83% note, due January 1, 2015 . . . . 20,000,000 20,000,000 Convertible debentures: 8.25% due March 1, 2014. . . . . . . . 3,358,000 3,471,000 Mortgage payable. . . . . . . . . . . . . 265,869 0 -------------------------------------------------------------------- Total long-term debt. . . . . . . . . . . $48,408,596 $50,920,818 -------------------------------------------------------------------- Annual maturities of consolidated long-term debt for the next five years are as follows: $2,686,145 for 2002, $3,688,006 for 2003, $3,690,031 for 2004, $2,936,236 for 2005 and $5,099,959 for 2006. |
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 2001 and 2000, debentures totaling $109,000 and $181,000, 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 2001 and 2000, debentures totaling $4,000 and $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 and the times interest earned ratio must be at least 2.5.
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.
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 $827,000, $652,000 and $357,000 for 2001, 2000 and 1999, respectively.
Future minimum payments under the Company's current lease agreements are
$858,000, $795,000, $693,000, $531,000 and $289,000 for the years of 2002
through 2006, respectively; and $793,000 thereafter, totaling $4.0 million.
Chesapeake Utilities Corporation Page 43
The following schedule sets forth the funded status of the pension plan at December 31, 2001 and 2000:
-------------------------------------------------------------------------- AT DECEMBER 31, 2001 2000 -------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATION: Benefit obligation at beginning of year. . . . $ 8,826,534 $ 8,241,995 Service cost . . . . . . . . . . . . . . . . 347,955 354,031 Interest cost. . . . . . . . . . . . . . . . 646,205 605,185 Change in discount rate. . . . . . . . . . . 659,629 0 Actuarial loss . . . . . . . . . . . . . . . 47,068 8,153 Benefits paid. . . . . . . . . . . . . . . . (407,027) (382,830) -------------------------------------------------------------------------- Benefit obligation at end of year. . . . . . . 10,120,364 8,826,534 -------------------------------------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets at beginning of year 11,738,984 10,185,394 Actual return on plan assets . . . . . . . . 413,617 1,936,420 Benefits paid. . . . . . . . . . . . . . . . (407,027) (382,830) -------------------------------------------------------------------------- Fair value of plan assets at end of year . . . 11,745,574 11,738,984 -------------------------------------------------------------------------- FUNDED STATUS. . . . . . . . . . . . . . . . . 1,625,210 2,912,450 UNRECOGNIZED TRANSITION OBLIGATION . . . . . . (66,059) (81,163) UNRECOGNIZED PRIOR SERVICE COST. . . . . . . . (53,055) (57,754) UNRECOGNIZED NET GAIN. . . . . . . . . . . . . (2,413,816) (3,883,807) -------------------------------------------------------------------------- ACCRUED PENSION COST . . . . . . . . . . . . . $ (907,720) $(1,110,274) -------------------------------------------------------------------------- ASSUMPTIONS: ----------- Discount rate. . . . . . . . . . . . . . . . 7.00% 7.50% Rate of compensation increase. . . . . . . . 4.75% 4.75% Expected return on plan assets . . . . . . . 8.50% 8.50% -------------------------------------------------------------------------- |
Net periodic pension costs for the defined pension benefit plan for 2001, 2000 and 1999 include the components as shown below:
------------------------------------------------------------------------------ FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999 ------------------------------------------------------------------------------ COMPONENTS OF NET PERIODIC PENSION COST: Service cost . . . . . . . . . . . . . . $ 347,955 $ 354,031 $ 400,921 Interest cost. . . . . . . . . . . . . . 646,205 605,185 688,198 Expected return on assets. . . . . . . . (981,882) (859,245) (1,046,254) Amortization of: Transition assets. . . . . . . . . . . (15,104) (15,104) (15,104) Prior service cost . . . . . . . . . . (4,699) (4,699) (4,699) Actuarial gain . . . . . . . . . . . . (195,029) (141,533) (118,142) ------------------------------------------------------------------------------ NET PERIODIC PENSION BENEFIT . . . . . . (202,554) (61,365) (95,080) ------------------------------------------------------------------------------ |
Chesapeake Utilities Corporation Page 44
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. On December 1, 2001, the Company converted the 401(k) fund holding Chesapeake stock to an Employee Stock Ownership Plan.
Effective, January 1, 1999 the Company began offering a non-qualified supplemental employee retirement savings plan open to Company executives over a specific income threshold. Participants receive a cash only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds earn interest income monthly. This Plan is not funded externally.
The Company's contributions to the 401(k) plans totaled $1,352,000, $1,231,000 and $1,066,000 for the years ended December 31, 2001, 2000 and 1999, respectively. As of December 31, 2001, there are 273,333 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 2001, 2000 and 1999 include the following components:
------------------------------------------------------------------------------- FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999 ------------------------------------------------------------------------------- COMPONENTS OF NET PERIODIC POST-RETIREMENT COST: Service cost . . . . . . . . . . . . . . . . . . $ 887 $ 1,803 $ 3,322 Interest cost. . . . . . . . . . . . . . . . . . 49,799 57,584 55,023 Amortization of: Transition obligation. . . . . . . . . . . . . 27,859 27,859 27,859 Actuarial (gain) loss. . . . . . . . . . . . . (1,717) - 3,130 ------------------------------------------------------------------------------- Net periodic post-retirement cost. . . . . . . . 76,828 87,246 89,334 Amounts amortized. . . . . . . . . . . . . . . . 0 25,028 25,254 ------------------------------------------------------------------------------- TOTAL POST-RETIREMENT COST ACCRUALS. . . . . . . $76,828 $112,274 $114,588 ------------------------------------------------------------------------------- |
Chesapeake Utilities Corporation Page 45
--------------------------------------------------------------- AT DECEMBER 31, 2001 2000 --------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATION: Benefit obligation at beginning of year $ 832,535 $ 788,532 Retirees. . . . . . . . . . . . . . . (58,485) 23,708 Fully-eligible active employees . . . (24,453) 48,992 Other active. . . . . . . . . . . . . (25,671) (28,697) --------------------------------------------------------------- Benefit obligation at end of year . . . $ 723,926 $ 832,535 --------------------------------------------------------------- FUNDED STATUS . . . . . . . . . . . . . $(723,926) $(832,535) UNRECOGNIZED TRANSITION OBLIGATION. . . 133,718 161,577 UNRECOGNIZED NET (GAIN) LOSS. . . . . . (73,737) 61,543 --------------------------------------------------------------- ACCRUED POST-RETIREMENT COST. . . . . . $(663,945) $(609,415) --------------------------------------------------------------- ASSUMPTIONS: ------------ Discount rate . . . . . . . . . . . . 7.00% 7.50% --------------------------------------------------------------- |
The health care inflation rate for 2001 is assumed to be 7.5 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 $68,000 as of January 1, 2002, and would increase the aggregate of the service cost and interest cost components of the net periodic post-retirement benefit cost for 2002 by approximately $5,000.
K. EXECUTIVE INCENTIVE PLANS
The Performance Incentive Plan ("the Plan") adopted in 1992 allows for the
granting of stock options, stock appreciation rights and performance shares to
certain officers of the Company over a 10-year period. Stock options granted
under the Plan entitle participants 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 2001 and 2000, the Company granted 10,650 and 13,150 SARs, respectively, 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 $123,000, $118,000 and $131,000 associated with these performance shares in 2001, 2000 and 1999, respectively.
Chesapeake Utilities Corporation Page 46
------------------------------------------------------------------------------------------------------------
2001 2000 1999
NUMBER OPTION NUMBER OPTION NUMBER OPTION
OF SHARES PRICE OF SHARES PRICE OF SHARES PRICE
------------------------------------------------------------------------------------------------------------
Balance beginning of year. . . . . 110,093 $12.75-$20.50 163,637 $12.75-$20.50 163,637 $12.75-$20.50
Options exercised . . . . . . (53,220) $12.75
Options expired . . . . . . . (14,925) $12.75
Options forfeited or replaced (53,544) $20.50
------------------------------------------------------------------------------------------------------------
Balance end of year. . . . . . . . 41,948 $20.50 110,093 $12.75-$20.50 163,637 $12.75-$20.50
------------------------------------------------------------------------------------------------------------
Exercisable. . . . . . . . . . . . 41,948 $20.50 110,093 $12.75-$20.50 85,735 $12.75-$20.50
------------------------------------------------------------------------------------------------------------
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In December 1997, the Company granted stock options to certain executive officers of the Company. SFAS No. 123 requires the disclosure of pro forma net income and earnings per share as if fair value based accounting had been used to account for the stock-based compensation costs. Accordingly, pro forma net income, basic earnings per share and diluted earnings per share for 2000 were $7,475,885, $1.42 and $1.40, respectively. Pro forma net income, basic earnings per share and diluted earnings per share for 1999 were $8,230,868, $1.60 and $1.57, respectively. The assumptions used in calculating the pro forma information were: dividend yield, 4.73 percent; expected volatility, 15.53 percent; risk-free interest rate, 5.89 percent; and an expected life of 4 years. No options have been granted since 1997; therefore, there is no pro forma impact for 2001.
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 the Dover
Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites.
In May 2001, Chesapeake, General Public Utilities Corporation, Inc. ("GPU"), the State of Delaware and the United States Environmental Protection Agency ("EPA") signed a settlement term sheet reflecting the agreement in principle to settle a lawsuit with respect to the Dover Gas Light site. The parties are in the process of memorializing the terms of the final agreement in two consent decrees. The consent decrees will then be published for public comment and submitted to a federal judge for approval.
If the agreement in principle receives final approval, Chesapeake will:
- Design and construct a parking lot on the site and dismantle the soil vapor extraction system that has been erected at the site. - Receive a net payment of $1.15 million from other parties to the agreement. These proceeds will be passed on to Chesapeake's firm customers, in accordance with the environmental rate rider. - Receive a release from liability and covenant not to sue from the EPA and the State of Delaware. This will relieve Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to EPA is received that indicates the remedial action related to the former manufactured gas plant is not sufficiently protective. These contingencies are standard, and are required by the United States in all liability settlements.
At December 31, 2001, the Company had accrued $2.1 million (discounted) of costs associated with the remediation of the Dover site and had recorded an associated regulatory asset for the same amount. Of that amount, $1.5 million was for estimated ground-water remediation and $600,000 was for remaining soil remediation. The $1.5 million represented the low end of the ground-water remediation estimates prepared by an independent consultant and was used because the Company could not, at that time, predict the remedy the EPA might require.
Chesapeake Utilities Corporation Page 47
Upon receiving final court approval of the consent decrees, Chesapeake will reduce both the accrued environmental liability and the associated environmental regulatory asset to the amount required to complete its obligations (primarily the final demobilization of the remedial system and final design and construction of the parking lot).
The second site is the Salisbury Town Gas Light Site in Salisbury, Maryland. In cooperation with the Maryland Department of the Environment ("MDE"), the Company is engaged in remediation that primarily includes the following: (1) operation of an air sparging/soil vapor extraction ("AS/SVE") remedial system; (2) monitoring and recovery of product from recovery wells; and (3) monitoring of ground-water quality. In February 2002, the MDE granted permission to permanently decommission the AS/SVE system and abandon nearly all of the monitoring wells on-site and off-site. The Company is currently seeking a No Further Action ("NFA") for the site. The NFA would be conditional upon the Company performing continued product monitoring and recovery at one well location and implementing land use controls. Evaluation of historical sampling results is currently being performed to determine the level of land use controls that will be required by the MDE for the site. A plan for decommissioning the AS/SVE system and monitoring well network is currently being prepared for approval from the MDE. The final decommissioning and well abandonment is anticipated to occur in the second quarter of 2002.
The Company has adjusted the liability with respect to the Salisbury site to $100,000 at December 31, 2001. The Company had previously accrued $175,000 as of December 31, 2000. This amount is based on the estimated costs to perform limited product monitoring and recovery efforts, abandon the monitoring well network, decommission the remedial system and fulfill ongoing reporting requirements. A corresponding regulatory asset has been recorded, reflecting the Company's belief that costs incurred will be recoverable in base rates.
Through December 31, 2001, the Company has incurred approximately $2.8 million for remedial actions and environmental studies at the Maryland site. Of this amount, approximately $1.7 million has been recovered through insurance proceeds or ratemaking treatment.
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 ("FDEP"). The RAP was approved by the FDEP on May 4, 2001. The current estimate of costs to complete the RAP is $1 million (discounted). Accordingly, at December 31, 2001, the Company accrued a liability of $1 million. Through December 31, 2001, the Company has incurred approximately $80,000 of environmental costs associated with the Florida site. At December 31, 2001, the Company had collected $523,000 in excess of costs incurred. A regulatory asset of $477,000 representing the uncollected portion of the estimated clean up costs has also been recorded. Once the FDEP approves the RAP, the Company will commence with the remediation procedures per the RAP.
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
Chesapeake Utilities Corporation Page 48
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.
--------------------------------------------------------------------------- FOR THE QUARTERS ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 --------------------------------------------------------------------------- 2001 Operating Revenue . $134,039,485 $71,051,256 $55,567,288 $ 69,662,929 Operating Income. . 6,666,331 1,741,229 562,419 2,548,236 Net Income. . . . . 5,365,469 666,726 (674,966) 1,364,308 Earnings per share: Basic . . . . . . $ 1.01 $ 0.12 $ (0.13) $ 0.25 Diluted . . . . . $ 0.98 $ 0.12 $ (0.13) $ 0.25 --------------------------------------------------------------------------- 2000 Operating Revenue . $ 98,509,179 $65,950,982 $59,212,768 $111,739,915 Operating Income. . 6,640,727 1,235,233 (43,959) 3,806,045 Net Income. . . . . 5,669,466 319,548 (1,044,709) 2,544,896 Earnings per share: Basic . . . . . . $ 1.09 $ 0.06 $ (0.20) $ 0.48 Diluted . . . . . $ 1.05 $ 0.06 $ (0.20) $ 0.47 --------------------------------------------------------------------------- |
Chesapeake Utilities Corporation Page 49
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" and Section 16(a) Beneficial Ownership Reporting
Compliance" to be filed not later than April 30, 2002 in connection with the
Company's Annual Meeting to be held on May 21, 2002.
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. EXECUTIVE COMPENSATION
This information is incorporated herein by reference to the portion of the Proxy
Statement captioned "Management Compensation Committee Interlocks and Insider
Participation", in the Proxy Statement to be filed not later than April 30,
2002, in connection with the Company's Annual Meeting to be held on May 21,
2002.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is incorporated herein by reference to the portion of the Proxy
Statement captioned "Beneficial Ownership of the Company's Securities" to be
filed not later than April 30, 2002 in connection with the Company's Annual
Meeting to be held on May 21, 2002.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is incorporated herein by reference to the portion of the Proxy
Statement captioned "Certain Transactions" to be filed not later than April 30,
2002, in connection with the Company's Annual Meeting to be held on May 21,
2002.
Chesapeake Utilities Corporation Page 50
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 15, 2002 of PricewaterhouseCoopers LLP,
Independent Accountants
- Consolidated Statements of Income for each of the three years ended
December 31, 2001, 2000 and 1999
- Consolidated Balance Sheets at December 31, 2001 and December 31, 2000
- Consolidated Statements of Cash Flows for each of the three years ended
December 31, 2001,2000 and 1999
- Consolidated Statements of Common Stockholders' Equity for each of the
three years ended December 31, 2001, 2000 and 1999
- Consolidated Statements of Income Taxes for each of the three years ended
December 31, 2001, 2000 and 1999
- 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:
Exhibit 3(a) Amended Certificate of Incorporation of Chesapeake Utilities
Corporation is incorporated herein by reference to Exhibit
3.1 of the Company's Quarterly Report on Form 10-Q for
the period ended June 30, 1998, File No. 001-11590.
Exhibit 3(b) Amended Bylaws of Chesapeake Utilities Corporation, effective
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,
|
Chesapeake Utilities Corporation Page 51
*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 is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-11590.
*Exhibit 10(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, 2002, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Ralph J. Adkins, John R. Schimkaitis, Michael P. McMasters, William C. Boyles and Stephen C. Thompson, 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 is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-11590.
*Exhibit 10(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 is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-11590.
*Exhibit 10(j) United Systems, Inc. Employee Appreciation Rights Plan dated
December 31, 2000 is incorporated herein by reference
to Exhibit 10 of the Company's Annual Report on Form 10-K
for the year ended December 31, 2000, File No. 001-11590.
Exhibit 12 Computation of Ratio of Earning to Fixed Charges,
filed herewith.
Exhibit 21 Subsidiaries of the Registrant, filed herewith.
Exhibit 23 Consent of Independent Accountants, filed herewith.
* Management contract or compensatory plan or agreement.
|
Chesapeake Utilities Corporation Page 52
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.
By: /s/ John R. Schimkaitis
--------------------------
John R. Schimkaitis
President and Chief
Executive Officer
Date: March 15, 2002
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ Ralph J. Adkins /s/ John R. Schimkaitis
---------------------- --------------------------
Ralph J. Adkins, Chairman of John R. Schimkaitis, President,
the Board and Director Chief Executive Officer
and Director
Date: March 15, 2002 Date: March 15, 2002
/s/ Michael P. McMasters /s/ Richard Bernstein
--------------------------- -----------------------
Michael P. McMasters, Richard Bernstein, Director
Vice President, Chief
Financial Officer and Treasurer
(Principal Financial and
Accounting Officer)
Date: March 15, 2002 Date: March 15, 2002
/s/ Thomas J. Bresnan /s/ Walter J. Coleman
------------------------ ------------------------
Thomas J. Bresnan, Director Walter J. Coleman
Date: March 15, 2002 Date: March 15, 2002
/s/ John W. Jardine, Jr. /s/ J. Peter Martin
---------------------------- ----------------------
John W. Jardine, Jr., Director J. Peter Martin, Director
Date: March 15, 2002 Date: March 15, 2002
/s/ Joseph E. Moore, Esq. /s/ Calvert A. Morgan, Jr.
----------------------------- ------------------------------
Joseph E. Moore, Esq., Director Calvert A. Morgan, Jr., Director
Date: March 15, 2002 Date: March 15, 2002
/s/ Rudolph M. Peins, Jr. /s/ Robert F. Rider
----------------------------- ----------------------
Rudolph M. Peins, Jr., Director Robert F. Rider, Director
Date: March 15, 2002 Date: March 15, 2002
/s/ Jeremiah P. Shea
-----------------------
Jeremiah P. Shea, Director
Date: March 15, 2002
|
Chesapeake Utilities Corporation Page 53
--------------------------------------------------------------------------------------------------
ADDITIONS
BALANCE AT ----------------------- BALANCE AT
BEGINNING CHARGED TO OTHER END OF
FOR THE YEAR ENDED DECEMBER 31, OF YEAR INCOME ACCOUNTS (1) DEDUCTIONS (2) YEAR
--------------------------------------------------------------------------------------------------
RESERVE DEDUCTED FROM RELATED ASSETS
RESERVE FOR UNCOLLECTIBLE ACCOUNTS
2001 . . . . . . . . . . . . . . . . $549,961 $592,590 $488,895 $(1,009,930) $621,516
--------------------------------------------------------------------------------------------------
2000 . . . . . . . . . . . . . . . . $475,592 $342,407 $ 63,741 $ (331,779) $549,961
--------------------------------------------------------------------------------------------------
1999 . . . . . . . . . . . . . . . . $302,513 $457,367 $ 74,877 $ (359,165) $475,592
--------------------------------------------------------------------------------------------------
(1) Recoveries.
(2) Uncollectible accounts charged off.
|
Chesapeake Utilities Corporation Page 54
----------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
----------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS . . . . . . . . . . . $ 6,721,537 $ 7,489,201 $ 8,270,986
Add:
Income taxes . . . . . . . . . . . . . . . . . . . 4,252,275 4,496,592 4,684,247
Portion of rents representative of interest factor 275,773 156,680 162,278
Interest on indebtedness . . . . . . . . . . . . . 5,178,495 4,398,266 3,348,231
Amortization of debt discount and expense. . . . . 101,183 111,122 117,966
----------------------------------------------------------------------------------------------
EARNINGS AS ADJUSTED. . . . . . . . . . . . . . . . . . $16,529,263 $16,651,861 $16,583,708
==============================================================================================
FIXED CHARGES
Portion of rents representative of interest factor $ 275,773 $ 156,680 $ 162,278
Interest on indebtedness . . . . . . . . . . . . . 5,178,495 4,398,266 3,348,231
Amortization of debt discount and expense. . . . . 101,183 111,122 117,966
----------------------------------------------------------------------------------------------
FIXED CHARGES . . . . . . . . . . . . . . . . . . . . . $ 5,555,451 $ 4,666,068 $ 3,628,475
==============================================================================================
RATIO OF EARNINGS TO FIXED CHARGES. . . . . . . . . . . 2.98 3.57 4.57
==============================================================================================
|
Chesapeake Utilities Corporation Page 55
SUBSIDIARIES STATE INCORPORATED
------------ -------------------
Eastern Shore Natural Gas Company Delaware
Sharp Energy, Inc. Delaware
Chesapeake Service Company Delaware
Xeron, Inc. Mississippi
Sam Shannahan Well Company, Inc. Maryland
Sharp Water, Inc. Delaware
SUBSIDIARIES OF SHARP ENERGY, INC. STATE INCORPORATED
-------------------------------------- -------------------
Sharpgas, Inc. Delaware
Tri-County Gas Co., Incorporated Maryland
SUBSIDIARIES OF CHESAPEAKE SERVICE COMPANY STATE INCORPORATED
---------------------------------------------- -------------------
Skipjack, Inc. Delaware
BravePoint, Inc. Georgia
Chesapeake Investment Company Delaware
Eastern Shore Real Estate Maryland
SUBSIDIARIES OF SHARP WATER, INC. STATE INCORPORATED
------------------------------------- -------------------
EcoWater Systems of Michigan, Inc. Michigan
Carroll Water Systems, Inc. Maryland
Absolute Water Care, Inc. Florida
Sharp Water of Florida, Inc. Delaware
Sharp Water of Idaho, Inc. Delaware
Sharp Water of Minnesota, Inc. Delaware
Sharp Water of Nevada, Inc. Delaware
|
Chesapeake Utilities Corporation Page 56
We hereby consent to the incorporation by reference in the Registration Statement on Form S-2 (No. 33-26582), Form S-3 (Nos. 33-28391, 33-64671, 333-63381 and 333-94159) and Form S-8 (No. 33-301175) of Chesapeake Utilities Corporation of our report dated February 15, 2002 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
/S/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Philadelphia, Pennsylvania March 29, 2002 |
Chesapeake Utilities Corporation Page 57
AGREEMENT dated as of January 1, 2002, and entered into, in duplicate, by and between Chesapeake Utilities Corporation, a Delaware corporation (the "Company"), and [Ralph J. Adkins / John R. Schimkaitis / Michael P. McMasters / Stephen C. Thompson / William Boyles] (the "Grantee") who resides at [ADDRESS].
WITNESSETH that:
WHEREAS, the Chesapeake Utilities Corporation Performance Incentive Plan (the "Plan") has been duly adopted by action of the Company's Board of Directors (the "Board") as of January 1, 1992; and
WHEREAS, the Committee of the Board of Directors of the Company referred to in the Plan (the "Committee") has determined that it is in the best interests of the Company to grant the Performance Share Award described herein pursuant to the Plan; and
WHEREAS, the shares of the Common Stock of the Company that are subject to this Agreement, when added to the other shares of Common Stock that are subject to awards granted under the Plan, do not exceed the total number of shares of Common Stock with respect to which awards are authorized to be granted under the Plan;
NOW, THEREFORE, it is hereby covenanted and agreed by and between the Company and the Grantee as follows:
Section 1. Performance Share Award
The Company hereby grants to the Grantee a Performance Share Award for the year ending December 31, 2002 (the "Award Year"). As more fully described herein, the Grantee may earn a maximum total of [XXXX] shares (the "Contingent Performance Shares") upon the Company's achievement of the Performance Goals set forth in Section 2. Alternatively, the Grantee may elect to receive [XXXX] shares (the "Forfeitable Performance Shares"), as detailed in Section 3, in lieu of receiving any Contingent Performance Shares. The Forfeitable Performance Shares shall be subject to forfeiture conditions, as set forth in Section 3(c).
Section 2. Contingent Performance Shares
(a) As soon as practicable after the Company's independent auditors
have certified the Company's financial statements for the Award Year, the
Committee shall determine for purposes of this Agreement the Company's (1)
earnings growth ("EG"), (2) growth in non-regulated investments ("NRIG"), and
(3) Shareholder Value as of the end of the Award Year. The EG, NRIG and
Shareholder Value shall be determined by the Committee based on financial
results reported to shareholders in the Company's annual reports and shall be
subject to adjustment by the Committee for extraordinary events, including, but
not limited to, temperature fluctuation during the Award Year. The Committee
shall promptly notify the Grantee of its determination.
(b) The Grantee may earn up to [XXXX] Contingent Performance Shares (the "Maximum Award"), as follows:
(1) If the Grantee for the Award Year exceeds the Earning's Growth measured as a return on equity or alternatively, an income target in excess of budgets for the Award Year, the Grantee will be eligible to earn up to 35% of the maximum award. If the Earnings Growth is at or below the target, the Grantee shall not earn any Contingent Performance Shares under this paragraph (1).
(2) If the Non-Regulated Investment increased from 23% to 28% of the Company's total capitalization in the Award Year, or alternatively the non-regulated investment growth may be stated as a dollar amount, the Grantee shall earn 30% of the maximum award. If the Non-Regulated Investment does not hit the target of 28% of total capitalization of the Company or the investment growth dollar target, the Grantee shall not earn any Contingent Performance Shares under is paragraph (2); and
(3) The performance measured for Shareholder Value will be the value of $10,000 invested in the Company stock compared to a Utility Index. If the Company's performance exceeds the Utility Index, the Grantee will be eligible to earn up to 30% of the maximum award. If the value of $10,000 invested for the Award Year does not exceed the Industry Index for the Award Year, the Grantee shall not earn any Contingent Performance Shares under this paragraph (3).
(c) Contingent Performance Shares that are earned by the Grantee pursuant to this Section 2 shall be issued promptly, without payment of consideration by the Grantee. The Grantee shall have the right to vote the Contingent Performance Shares and to receive the dividends distributable with respect to such shares on and after, but not before, the date on which the Grantee is recorded on the Company's ledger as holder of record of the Contingent Performance Shares (the "Issue Date"). If, however, the Grantee receives shares of Common Stock as part of any dividend or other distribution with respect to the Contingent Performance Shares, such shares shall be treated as if they are Contingent Performance Shares, and such shares shall be subject to all of the terms and conditions imposed by this Section 2.
(d) Sale, transfer, pledge, or hypothecation of the Contingent
Performance Shares shall be prohibited for a period of three (3) years after the
Issue Date (the "Limitation Period"), and the Performance Shares shall bear a
restrictive legend to that effect. Any attempt to dispose of Contingent
Performance Shares in contravention of this Agreement shall be ineffective.
Upon expiration of the Limitation Period, the transfer restrictions imposed by
this Section shall expire, and new certificates representing the Contingent
Performance Shares, without the restrictive legend described in this paragraph
(d), shall be issued, subject to the provisions of paragraph (e) of this Section
2.
(e) The Performance Shares will be not registered for resale under the Securities Act of 1933 or the laws of any state except when and to the extent determined by the Board pursuant to a resolution. Until a registration statement is filed and becomes effective, however, transfer of the Contingent Performance Shares after expiration of the Limitation Period shall require the availability of an exemption from such registration, and prior to the issuance of new certificates, the Company shall be entitled to take such measures as it deems appropriate (including but not limited to obtaining from the Grantee an investment representation letter and/or further legending the new certificates) to ensure that the Contingent Performance Shares are not transferred in the absence of such exemption.
(f) In the event of a Change in Control, as defined in the Plan, during the Award Year, the Grantee shall earn at least the Maximum Award of Contingent Performance Shares set forth in this Section 2, as if all employment and performance criteria were satisfied, pro rated based on the proportion of the Award Year that has expired as of the date of such Change in Control.
(g) If, during the Award Year, the Grantee is separated from employment, Contingent Performance Shares shall be deemed earned or forfeited as follows:
(1) Upon voluntary termination by the Grantee (other than for retirement at age 65 or as accepted by the Committee) or termination by the Company for failure of job performance or other just cause as determined by the Committee, all unearned Contingent Performance Shares shall be forfeited immediately;
(2) If the Grantee separates from employment by reason of death or total and permanent disability (as determined by the Committee), the number of Contingent Performance Shares that would otherwise have been earned at the end of the Award Year shall be reduced by pro rating such Contingent Performance Shares based on the proportion of the Award Year during which the Grantee was employed by the Company, unless the Committee determines that the Contingent Performance Shares shall not be so reduced;
(3) Retirement of the Grantee at age 65 or as accepted by the Committee shall not affect the Contingent Performance Shares, which shall continue to be earned through the remainder of the Award Year, as set forth above.
(h) The Grantee shall be solely responsible for any federal, state and local income taxes imposed in connection with the delivery of Contingent Performance Shares. Prior to the transfer of any Contingent Performance Shares to the Grantee, the Grantee shall remit to the Company an amount sufficient to satisfy any federal, state, local and other withholding tax requirements. The Grantee may elect to have all or part of any withholding tax obligation satisfied by having the Company withhold shares otherwise deliverable to the Grantee as Contingent Performance Shares, unless the Committee determines otherwise by resolution. If the Grantee fails to make such payments or election, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required by law to be withheld with respect to the Contingent Performance Shares.
Section 3. Forfeitable Performance Shares
(a) In lieu of earning Contingent Performance Shares, the Grantee may elect to receive [XXXX] Forfeitable Performance Shares, irrespective of whether the Company meets any Performance Goals. The Grantee must make any such election on or before September 30, 2002, and the election must be made in writing, in a manner prescribed by the Committee. Once made, the election is irrevocable. If a Grantee makes such an election, he shall not receive any Contingent Performance Shares under this Agreement.
(b) Any Forfeitable Performance Shares received by the Grantee pursuant to this Section 3 shall be issued as promptly as possible after December 31, 2002, without payment of consideration by the Grantee. The Grantee shall have the right to vote the Forfeitable Performance Shares and to receive the dividends distributable with respect to such shares on and after, but not before, the date on which the Grantee is recorded on the Company's ledger as holder of record of the Forfeitable Performance Shares (the "Issue Date"). If, however, the Grantee receives shares of Common Stock as part of any dividend or distribution with respect to the Forfeitable Performance Shares, such shares shall be treated as if they are Forfeitable Performance Shares, and such shares shall be subject to all of the terms and conditions imposed by this Section 3.
(c) The Forfeitable Performance Shares shall be subject to the following restrictions:
(1) Sale, transfer, pledge or hypothecation of the Forfeitable Performance Shares shall be prohibited for a period of three (3) years after the Issue Date (the "Restriction Period"), and the certificates evidencing the Forfeitable Performance Shares shall bear an appropriate restrictive legend that refers to the terms, conditions, and restrictions set forth in this Agreement. Any attempt to dispose of Forfeitable Performance Shares in contravention of this Agreement shall be ineffective. Upon expiration of the Restriction Period, the transfer restrictions imposed by this Section shall expire, and new certificates representing the Forfeitable Performance Shares, without the restrictive legend described in this paragraph (c)(1), shall be issued, subject to the provisions of paragraph (f) of this Section 3.
(2) If, during the Restriction Period, the Grantee separates from employment for any reason other than death, normal retirement, total and permanent disability (as determined by the Committee), or involuntary termination without cause (as determined by the Committee), all Forfeitable Performance Shares shall be forfeited immediately.
(d) All restrictions under paragraph (c) of this Section 3 shall immediately expire on the earliest of: (A) the Grantee's separation from employment because of death, total and permanent disability (as determined by the Committee), or involuntary termination without cause (as determined by the Committee), (B) a Change in Control, as defined in the Plan, or (C) the end of the Restriction Period.
(e) If, after the Grantee has made an election to receive Forfeitable Performance Shares pursuant to Section 3(a), a Change in Control, as defined in the Plan, occurs during the Award Year, the Grantee shall receive at least the total number of Forfeitable Performance Shares due under this Agreement, pro rated based on the proportion of the Award Year that has expired as of the date of such Change in Control. Pursuant to Section 3(d), such Shares shall not be subject to any of the restrictions imposed by this Section.
(f) The Forfeitable Performance Shares shall be not registered for resale under the Securities Act of 1933 or the laws of any state except when and to the extent determined by the Board pursuant to a resolution. Until a registration statement is filed and becomes effective, however, transfer of the Forfeitable Performance Shares after expiration of the Restriction Period shall require the availability of an exemption from such registration, and prior to the issuance of new certificates, the Company shall be entitled to take such measures as it deems appropriate (including but not limited to obtaining from the Grantee an investment representation letter and/or further legending the new certificates) to ensure that the Forfeitable Performance Shares are not transferred in the absence of such exemption.
(g) The Grantee shall be solely responsible for any federal, state and local income taxes imposed in connection with receipt of the Forfeitable Performance Shares:
(1) The Grantee agrees that, no later than the date that the restrictions set forth in Section 3(c) lapse, he shall remit to the Company an amount sufficient to satisfy any federal, state, local and other withholding tax requirements.
(2) The Grantee may elect to have all or part of any withholding tax obligation satisfied by having the Company withhold shares otherwise deliverable to the Grantee in connection with the Award of Restricted Stock, unless the Committee determines otherwise by resolution.
(3) If the Grantee properly elects, within 30 days of the Issue Date, to include in gross income for federal income tax purposes an amount equal to the fair market value of the Forfeitable Performance Shares, he shall make arrangements satisfactory to the Committee to remit in the year of issue an amount sufficient to satisfy any federal, state, local and other withholding tax requirements with respect to such Forfeitable Performance Shares.
(4) If the Grantee fails to make satisfactory arrangements to meet all withholding tax obligations, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required by law to be withheld with respect to the Forfeitable Performance Shares.
Section 4. Additional Conditions to Issuance of Shares
Each transfer of Contingent Performance Shares or Forfeitable Performance
Shares (together, the "Award Shares") shall be subject to the condition that if
at any time the Committee shall determine, in its sole discretion, that it is
necessary or desirable as a condition of, or in connection with, transfer of
Award Shares (i) to satisfy withholding tax or other withholding liabilities,
(ii) to effect the listing, registration or qualification on any securities
exchange or under any state or federal law of any Shares deliverable in
connection with such exercise, or (iii) to obtain the consent or approval of any
regulatory body, then in any such event such transfer shall not be effective
unless such withholding, listing, registration, qualification, consent or
approval shall have been effected or obtained free of any conditions not
acceptable to the Company.
Section 5. Adjustment of Shares
(a) If the Company shall become involved in a merger, consolidation or other reorganization, whether or not the Company is the surviving corporation, any right to earn Contingent Performance Shares or to elect to receive Forfeitable Performance Shares shall be deemed a right to earn or to elect to receive the consideration into which the shares of Common Stock represented by the Contingent Performance Shares or by the Forfeitable Performance Shares would have been converted under the terms of the merger, consolidation or other reorganization. If the Company is not the surviving corporation, the surviving corporation (the "Successor") shall succeed to the rights and obligations of the Company under this Agreement.
(b) If any subdivision or combination of shares of Common Stock or any stock dividend, capital reorganization or recapitalization occurs after the adoption of the Plan, the Committee shall make such proportionate adjustments as are appropriate to the number of Contingent Performance Shares to be earned and/or to the number of Forfeitable Performance Shares to be received in order to prevent the dilution or enlargement of the rights of the Grantee.
Section 6. No Right to Employment
Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.
Section 7. Notice
Any notice to be given hereunder by the Grantee shall be sent by mail addressed to Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, Delaware 19904, for the attention of the Committee, c/o the Secretary, and any notice by the Company to the Grantee shall be sent by mail addressed to the Grantee at the address of the Grantee shown on the first page hereof. Either party may, by notice given to the other in accordance with the provisions of this Section, change the address to which subsequent notices shall be sent.
Section 8. Assumption of Risk
It is expressly understood and agreed that the Grantee assumes all risks incident to any change hereafter in the applicable laws or regulations or incident to any change in the market value of the Award Shares.
Section 9. Terms of Plan
This Agreement is entered into pursuant to the Plan (a copy of which has been delivered to the Grantee). This Agreement is subject to all of the terms and provisions of the Plan, which are incorporated into this Agreement by reference, and the actions taken by the Committee pursuant to the Plan. In the event of a conflict between this Agreement and the Plan, the provisions of the Plan shall govern. All determinations by the Committee shall be in its sole discretion and shall be binding on the Company and the Grantee.
Section 10. Governing Law; Amendment
This Agreement shall be governed by, and shall be construed and administered in accordance with, the laws of the State of Delaware (without regard to its choice of law rules) and the requirements of any applicable federal law. This Agreement may be modified or amended only by a writing signed by the parties hereto.
Section 11. Terms of Agreement
This Agreement shall remain in full force and effect and shall be binding on the parties hereto for so long as any Award Shares issued to the Grantee under this Agreement continue to be held by the Grantee.
IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its corporate name, and the Grantee has executed the same in evidence of the Grantee's acceptance hereof, upon the terms and conditions herein set forth, as of the day and year first above written.
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FOR THE YEARS ENDED DECEMBER 31, 2001 2000 1999
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INCOME FROM CONTINUING OPERATIONS . . . . . . . . . . . $ 6,721,537 $ 7,489,201 $ 8,270,986
Add:
Income taxes . . . . . . . . . . . . . . . . . . . 4,252,275 4,496,592 4,684,247
Portion of rents representative of interest factor 275,773 156,680 162,278
Interest on indebtedness . . . . . . . . . . . . . 5,178,495 4,398,266 3,348,231
Amortization of debt discount and expense. . . . . 101,183 111,122 117,966
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EARNINGS AS ADJUSTED. . . . . . . . . . . . . . . . . . $16,529,263 $16,651,861 $16,583,708
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FIXED CHARGES
Portion of rents representative of interest factor $ 275,773 $ 156,680 $ 162,278
Interest on indebtedness . . . . . . . . . . . . . 5,178,495 4,398,266 3,348,231
Amortization of debt discount and expense. . . . . 101,183 111,122 117,966
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FIXED CHARGES . . . . . . . . . . . . . . . . . . . . . $ 5,555,451 $ 4,666,068 $ 3,628,475
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RATIO OF EARNINGS TO FIXED CHARGES. . . . . . . . . . . 2.98 3.57 4.57
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Eastern Shore Natural Gas Company Delaware
Sharp Energy, Inc. Delaware
Chesapeake Service Company Delaware
Xeron, Inc. Mississippi
Sam Shannahan Well Company, Inc. Maryland
Sharp Water, Inc. Delaware
SUBSIDIARIES OF SHARP ENERGY, INC. STATE INCORPORATED
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Sharpgas, Inc. Delaware
Tri-County Gas Co., Incorporated Maryland
SUBSIDIARIES OF CHESAPEAKE SERVICE COMPANY STATE INCORPORATED
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Skipjack, Inc. Delaware
BravePoint, Inc. Georgia
Chesapeake Investment Company Delaware
Eastern Shore Real Estate Maryland
SUBSIDIARIES OF SHARP WATER, INC. STATE INCORPORATED
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EcoWater Systems of Michigan, Inc. Michigan
Carroll Water Systems, Inc. Maryland
Absolute Water Care, Inc. Florida
Sharp Water of Florida, Inc. Delaware
Sharp Water of Idaho, Inc. Delaware
Sharp Water of Minnesota, Inc. Delaware
Sharp Water of Nevada, Inc. Delaware
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We hereby consent to the incorporation by reference in the Registration Statement on Form S-2 (No. 33-26582), Form S-3 (Nos. 33-28391, 33-64671, 333-63381 and 333-94159) and Form S-8 (No. 33-301175) of Chesapeake Utilities Corporation of our report dated February 15, 2002 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
/S/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Philadelphia, Pennsylvania March 29, 2002 |