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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED: DECEMBER 31, 2002
COMMISSION FILE NUMBER: 001-11590
CHESAPEAKE UTILITIES CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
STATE OF DELAWARE 51-0064146
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(STATE OR OTHER (I.R.S. EMPLOYER
JURISDICTION OF IDENTIFICATION NO.)
INCORPORATION OR
ORGANIZATION)
909 SILVER LAKE BOULEVARD, DOVER, DELAWARE 19904
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(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES, INCLUDING ZIP CODE)
302-734-6799
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(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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COMMON STOCK - PAR NEW YORK STOCK EXCHANGE, INC.
VALUE PER SHARE $.4867
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
8.25% CONVERTIBLE DEBENTURES DUE 2014
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(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X]. No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendments to
this Form 10-K. [ ]
Indicate by checkmark whether the registrant is an accelerated filer (as defined
by Exchange Act Rule 12b-2). Yes [X]. No [ ].
As of March 24, 2003, 5,576,414 shares of common stock were outstanding. The
aggregate market value of the common shares held by non-affiliates of Chesapeake
Utilities Corporation as of June 28, 2002, the last business day of its most
recently completed second fiscal quarter, based on the last trade price on that
date, as reported by the New York Stock Exchange, was approximately $104
million.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2002 Annual Meeting of Stockholders are
incorporated by reference in Part III.
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CHESAPEAKE UTILITIES CORPORATION
FORM 10-K
YEAR ENDED DECEMBER 31, 2002
TABLE OF CONTENTS
PAGE
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PART I.......................................................................1
Item 1. Business.........................................................1
Item 2. Properties......................................................11
Item 3. Legal Proceedings..............................................11
Item 4. Submission of Matters to a Vote of Security Holders.....15
PART II.....................................................................16
Item 5. Market for the Registrant's Common Stock and
Related Security Holder Matters.................................16
Item 6. Selected Financial Data.......................................18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................22
Item 7a. Quantitative and Qualitative Disclosures About Market Risk....36
Item 8. Financial Statements and Supplemental Data..................36
Consolidated Statements of Income...............................37
Consolidated Balance Sheets.....................................38
Consolidated Statements of Cash Flows...........................40
Consolidated Statements of Stockholders' Equity.................41
Consolidated Statements of Income Taxes.........................42
A. Summary of Accounting Policies...............................43
B. Business Combinations........................................47
C. Segment Information..........................................48
D. Fair Value of Financial Instruments..........................49
E. Investments..................................................49
F. Goodwill and Other Intangible Assets.........................49
G. Common Stock and Additional Paid-in Capital..................50
H. Long-term Debt...............................................51
I. Short-term Borrowing.........................................51
J. Lease Obligations............................................52
K. Employee Benefit Plans.......................................52
L. Executive Incentive Plans....................................54
M. Environmental Commitments and Contingencies..................55
N. Other Commitments and Contingencies..........................57
O. Quarterly Financial Data (Unaudited).........................58
Item 9. Changes In and Disagreements With Accountants
on Accounting and Financial Disclosure........................59
PART III....................................................................59
Item 10. Directors and Executive Officers of the Registrant.......59
Item 11. Executive Compensation........................................59
Item 12. Security Ownership of Certain Beneficial Owners
and Management.................................................59
Item 13. Certain Relationships and Related Transactions.............59
PART IV.....................................................................60
Item 14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K............................60
SIGNATURES...................................................................63
CERTIFICATIONS...............................................................64
PART I
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 operations, the
competitive position of the Company and other matters. It is important to
understand that these forward-looking statements are not guarantees, but are
subject to certain risks and uncertainties and other important factors that
could cause actual results to differ materially from those in the
forward-looking statements. See Item 7 under the heading "Management's
Discussion and Analysis - Cautionary Statement."
As a public company, Chesapeake files annual, quarterly and other reports, as
well as its annual proxy statement and other information, with the Securities
and Exchange Commission ("the SEC"). Chesapeake makes available, free of charge,
on its Internet website its Annual Report on Form 10-K, Quarterly Reports on
Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon
as reasonably practicable after such reports are electronically filed with or
furnished to the SEC.
(A) GENERAL DEVELOPMENT OF BUSINESS
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a
diversified utility company engaged in natural gas distribution and
transmission, propane distribution and wholesale marketing, advanced information
services, water conditioning and treatment ("water services") and other related
businesses. The address of Chesapeake's Internet website is www.chpk.com. The
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content of this website is not part of this report.
Chesapeake's three natural gas distribution divisions serve approximately 45,100
residential, commercial and industrial customers in Delaware's Kent and Sussex
counties, Maryland's Eastern Shore and parts of Florida. The Company's natural
gas transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern
Shore"), operates a 304-mile interstate pipeline system that transports gas from
various points in Pennsylvania to the Company's Delaware and Maryland
distribution divisions, as well as to other utilities and industrial customers
in southern Pennsylvania, Delaware and on the Eastern Shore of Maryland. The
Company's propane distribution operation serves approximately 34,600 customers
in central and southern Delaware, the Eastern Shore of both Maryland and
Virginia and parts of Florida. The advanced information services segment
provides consulting, staffing, product development, implementation and
web-related services 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 four primary business activities: natural gas
distribution and transmission, propane distribution and wholesale marketing,
advanced information services and water services. In addition to the primary
groups, Chesapeake has subsidiaries in other related businesses.
(I) (A) NATURAL GAS DISTRIBUTION AND TRANSMISSION
GENERAL
Chesapeake distributes natural gas to approximately 45,100 residential,
commercial and industrial customers in Delaware's Kent and Sussex counties,
the Salisbury and Cambridge, Maryland areas on Maryland's Eastern Shore and
parts of Florida. These activities are conducted through three utility
divisions, one division in Delaware, another in Maryland and a third
division in Florida. The Company also offers natural gas supply and supply
management services in the state of Florida under the name of Peninsula
Energy Services Company ("PESCO").
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions
("Delaware," "Maryland" or "the divisions") serve an average of
approximately 34,350 customers, of which approximately 34,190 are
residential and commercial customers purchasing gas primarily for heating
purposes. The remainder are industrial customers. For the year 2002,
residential and commercial customers accounted for approximately 55% of the
volume delivered by the divisions and 70% of the divisions' revenue. The
divisions' industrial customers purchase gas, primarily on an interruptible
basis, for a variety of manufacturing, agricultural and other uses. Most of
Chesapeake's customer growth in these divisions comes from new residential
construction using gas-heating equipment.
Florida. The Florida division distributes natural gas to approximately
11,000 residential and commercial and 90 industrial customers in Polk,
Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto,
Suwannee and Citrus Counties. Currently the 90 industrial customers, which
purchase and transport gas on a firm basis, account for approximately 97%
of the volume delivered by the Florida division and 64% of the revenues.
These customers are primarily engaged in the citrus and phosphate
industries and in electric cogeneration. The Company's Florida division,
through Peninsula Energy Services Company, provides natural gas supply
management services to 250 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
swing transportation service and contract storage services for system
balancing purposes. 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. This gas is
transported by the upstream pipelines and delivered to the divisions'
interconnects with Eastern Shore. The divisions also have the capability to
use propane-air peak-shaving to supplement or displace the spot market
purchases. The Company believes that the availability of gas supply and
transportation to the Delaware and Maryland divisions is adequate under
existing arrangements to meet the anticipated needs of their customers.
Delaware. 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 transportation capacity of
366 Dt per day, which expires in 2005; and (d) firm storage service,
providing a total capacity of 142,830 Dt, with provisions to continue from
year to year, subject to six (6) months notice for termination.
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.
Delaware's contracts with Eastern Shore include: (a) firm transportation
capacity of 32,087 Dt per day for the period December through February,
30,865 Dt per day for the months of November, March and April, and 21,789
Dt per day for the period May through October, with various expiration
dates ranging from 2004 to 2017; (b) firm storage capacity under Eastern
Shore's Rate Schedule GSS providing a peak day entitlement of 2,655 Dt and
a total capacity of 131,370 Dt, which expires in 2013; (c) firm storage
capacity under Eastern Shore's Rate Schedule LSS providing a peak day
entitlement of 580 Dt and a total capacity of 29,000 Dt, which expires in
2013; and (d) firm storage capacity under Eastern Shore's Rate Schedule LGA
providing a peak day entitlement of 911 Dt and a total capacity of 5,708
Dt, which expires in 2006. Delaware's firm transportation contracts with
Eastern Shore also include Eastern Shore's provision of swing
transportation service. This service includes: (a) firm transportation
capacity of 1,846 Dt per day on Transco's pipeline system, retained by
Eastern Shore, in addition to Delaware's Transco capacity referenced
earlier and (b) an interruptible storage service under Transco's Rate
Schedule ESS that supports a swing supply service provided under Transco's
Rate Schedule FS.
Delaware currently has contracts for the purchase of firm natural gas
supply with several suppliers. These supply contracts provide the
availability of a maximum firm daily entitlement of 20,600 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 Transco, Columbia, Gulf and Eastern Shore under
Maryland's transportation contracts. The gas purchase contracts have
various expiration dates and daily quantities may vary from day to day and
month to month.
Florida. The Florida division receives transportation service from Florida
Gas Transmission Company ("FGT"), a major interstate pipeline. Chesapeake
has contracts with FGT for: (a) daily firm transportation capacity of
27,579 Dt in November through April, 21,200 Dt in May through September,
and 27,416 Dt in October under FGT's firm transportation service FTS-1 rate
schedule; (b) daily firm transportation capacity of 1,000 Dt daily under
FGT's firm transportation service FTS-2 rate schedule. The firm
transportation contract FTS-1 expires on July 31, 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
requested a turnback of all but 1,000 Dt per day year round of its FTS-2
capacity. This turnback coincided with the in service dates of FGT's Phase
5 Project in the second quarter of 2002.
The Florida division also began receiving transportation service from
Gulfstream Natural Gas System ("Gulfstream"), beginning in June 2002.
Chesapeake has a contract with Gulfstream for daily firm transportation
capacity of 10,200 Dt daily. The contract with Gulfstream expires May 31,
2022.
The Florida division received its gas supply from various suppliers. If
needed, some supply was bought on the spot market; however, the majority
was bought under the terms of two firm supply contacts. On November 5,
2002, the Florida Public Service Commission authorized the Florida division
to convert all remaining sales customers to transportation service and exit
the gas supply function.
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.
REGULATORY PROCEEDINGS
Delaware. In September 1998, Chesapeake's Delaware division filed an
application with the Delaware Public Service Commission ("DPSC") to propose
certain rate design changes to its existing margin sharing mechanism, which
was approved in Chesapeake's last rate case.
The Company proposed certain rate design changes to its existing margin
sharing mechanism in order to address the level of recovery of fixed
distribution costs from the residential heating service customers and
smaller commercial heating customers. The Company also proposed to change
the existing margin sharing mechanism to take into consideration the
appropriate treatment of margins achieved by the addition of new
interruptible customers on the distribution system for which the Company
makes additional capital investments.
In March 1999, the Company, DPSC Staff and the Division of the Public
Advocate settled all the issues in this matter and executed a proposed
settlement agreement. The settlement allows the Company to increase or
decrease the current margin sharing thresholds based on the actual level of
recovery of fixed distribution costs from residential service heating and
general service heating customers as compared to the level at which the
base tariff rates were designed to recover in the last rate case. Per the
settlement, the Company can implement an adjustment to the margin sharing
thresholds if the weather is at least 6.5% warmer or colder than normal;
however, the total increase or decrease in the amount of additional gross
margin that the Company will retain or credit to the firm ratepayers cannot
exceed a $500,000 cap.
Also 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. The Delaware Public Service Commission approved a settlement
agreement for Phase I of the Rate Increase Application in April 2002. Phase
I should result in an increase in rates of approximately $380,000 per year.
The Company, the Commission staff and the Division of the Public Advocate
have reached a settlement agreement for Phase II. The Delaware Public
Service Commission approved the agreement in November 2002. The impact of
Phase II should result in an additional increase in rates of approximately
$90,000 per year. Phase II also reduced the Company's sensitivity to warmer
than normal weather by changing the minimum customer charge and the margin
sharing arrangement for interruptible sales, off system sales and capacity
release income.
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.
On January 12, 2000, the Maryland Public Service Commission ("MPSC") issued
an order requiring the Company to file new tariff sheets, with an effective
date of January 12, 2000, to increase its natural gas delivery service
rates by $82,763 on an annual basis to recover the estimated impact of the
state corporate income tax. Also as part of the MPSC order, the Company was
directed to recover the new distribution franchise tax of $0.0042 per Ccf
as a separate line item charge on the customers' bills. On January 14,
2000, the Company filed new natural gas tariff sheets in compliance with
the MPSC order.
Florida. On 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,
excluding "market price" customers, of any variances between tariff rates
and actual revenue derived from those customers who are provided service
under the flexible rate tariff.
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.
On November 5, 2002, the Florida Public Service Commission authorized the
Florida division to convert all remaining sales customers to transportation
service and exit the gas supply function. Implementation of Phase One of
the Transitional Transportation Service ("TTS") program is underway and all
remaining sales customers have been assigned to a gas marketer selected to
manage the TTS customer pool.
Eastern Shore. On December 9, 1999, Eastern Shore filed an application
before the FERC requesting authorization for the following: (1)
construction and operation of 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) construction and operation of approximately ten miles of 6-inch
mainline extension in Delaware, (4) construction and operation of five
delivery points on the new 6-inch mainline extension in Delaware, and (5)
installation 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 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) construction and operation
of six miles of 16-inch pipeline looping in Pennsylvania and Maryland, (2)
installation of 3,330 horsepower of additional capacity at the existing
Daleville compressor station and (3) construction and operation of a new
delivery point in Chester County, Pennsylvania. The purpose of the
construction was to enable Eastern Shore to provide 19,800 Dt 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 - construction
and operation of 1.5 miles of 16-inch mainline looping in Pennsylvania on
Eastern Shore's existing right-of-way; and (2) Segment 2 - construction and
operation of 1.0 mile of 16-inch mainline looping in Maryland and Delaware
on, or adjacent to, Eastern Shore's existing right-of-way. The purpose of
the construction was to enable Eastern Shore to provide 4,500 Dt of
additional daily firm capacity on Eastern Shore's system. The expansion was
completed and placed into service during the fourth quarter of 2002.
On October 31, 2001, Eastern Shore Natural Gas Company, the Company's
natural gas transmission subsidiary, filed a rate change with the FERC
pursuant to the requirements of the Stipulation and Agreement dated August
1, 1997. Following settlement conferences held in May 2002, the parties
reached a settlement in principle on or about May 23, 2002 to resolve all
issues related to its rate case.
The Offer of Settlement and the Stipulation and Agreement were finalized
and filed with the FERC on August 2, 2002. The agreement provides that
Eastern Shore's rates will be based on a cost of service of $12.9 million
per year. Cost savings estimated at $456,000 will be passed on to firm
transportation customers. Initial comments supporting the settlement
agreement were filed by the FERC staff and by Eastern Shore. No adverse
comments were filed. The Presiding Judge certified the Offer of Settlement
to the FERC as uncontested on August 27, 2002. On October 10, 2002, the
FERC issued an Order approving the Offer of Settlement and the Stipulation
and Agreement. The settlement rates went into effect December 1, 2002.
During October 2002, Eastern Shore filed for recovery of gas supply
realignment costs associated with the implementation of FERC Order No. 636.
The costs totaled $196,000 (including interest). On November 14, 2002, the
FERC issued an Order requiring Eastern Shore to fulfill certain
requirements prior to FERC's review of Eastern Shore's application. It is
anticipated Eastern Shore will refile for recovery of these costs during
the second quarter of 2003. It is uncertain at this time when the FERC will
consider this matter or the ultimate outcome.
(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.
Propane is a form of liquefied petroleum gas, which is typically extracted
from natural gas or separated during the crude oil refining process.
Although propane is a gas at normal pressure, it is easily compressed into
liquid form for storage and transportation. Propane is a clean-burning
fuel, gaining increased recognition for its environmental superiority,
safety, efficiency, transportability and ease of use relative to
alternative forms of energy. Propane is sold primarily in suburban and
rural areas, which are not served by natural gas pipelines. Demand is
typically much higher in the winter months and is significantly affected by
seasonal variations, particularly the relative severity of winter
temperatures, because of its use in residential and commercial heating.
The Company's propane distribution operations served approximately 34,600
propane customers on the Delmarva Peninsula and delivered approximately 21
million retail and wholesale gallons of propane during 2002.
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.
ADEQUACY OF RESOURCES
The Company's propane distribution operations purchase propane primarily
from suppliers, including major domestic oil companies and independent
producers of gas liquids and oil. Supplies of propane from these and other
sources are readily available for purchase by the Company. Supply contracts
generally include minimum (not subject to take-or-pay premiums) and maximum
purchase provisions.
The Company's propane distribution operations use trucks and railroad cars
to transport propane from refineries, natural gas processing plants or
pipeline terminals to the Company's bulk storage facilities. From these
facilities, propane is delivered in portable cylinders or by "bobtail"
trucks, owned and operated by the Company, to tanks located at the
customer's premises.
Xeron does not own physical storage facilities or equipment to transport
propane; however, it contracts for storage and pipeline capacity to
facilitate the sale of propane on a wholesale basis.
COMPETITION
The Company's propane distribution operations compete with several other
propane distributors in their service territories, primarily on the basis
of service and price, emphasizing reliability of service and
responsiveness. Competition is generally from local outlets of national
distribution companies and local businesses, because distributors located
in close proximity to customers incur lower costs of providing service.
Propane competes with electricity as an energy source, because it is
typically less expensive than electricity, based on equivalent BTU value.
Propane also competes with home heating oil as an energy source. Since
natural gas has historically been less expensive than propane, propane is
generally not distributed in geographic areas serviced by natural gas
pipeline or distribution systems.
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 $35 million, but there is no assurance that such insurance
will be adequate.
(I) (C) ADVANCED INFORMATION SERVICES
GENERAL
Chesapeake's advanced information services segment consists of BravePoint,
Inc. ("BravePoint"), a wholly owned subsidiary of the Company. The Company
changed its name from United Systems, Inc. in 2001 to reflect a change in
service offerings.
BravePoint 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, staffing, product development, implementation and
web-related services for its client base, which includes many large
domestic and international corporations.
COMPETITION
The advanced information services business faces significant competition
from a number of larger competitors having substantially greater resources
available to them than does the Company. In addition, changes in the
advanced information services business are occurring rapidly, which could
adversely impact the markets for the products and services offered by these
businesses.
(I) (D) WATER SERVICES
GENERAL
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 EcoWater Systems of Stuart), 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.
COMPETITION
The water operations serve central and southern Delaware; the eastern shore
of Virginia; Maryland; central Michigan; Rochester, Minnesota; Boise and
Moscow, 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.
(I) (E) 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.
(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, 2002, Chesapeake had 582 employees, including 196 in
natural gas, 138 in propane, 90 in advanced information services and 127 in
water conditioning. The remaining 31 employees are considered general and
administrative and include officers of the Company, treasury, accounting,
information technology, human resources and other administrative personnel.
(V) EXECUTIVE OFFICERS OF THE REGISTRANT
Information pertaining to the executive officers of the Company is as
follows:
Ralph J. Adkins (age 60) 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 55) Mr. Schimkaitis assumed the role of Chief
Executive Officer on January 1, 1999. He has served as President since
1997. His present term expires on May 20, 2003. Prior to his new post, Mr.
Schimkaitis has also served as President and Chief Operating Officer,
Executive Vice President and Chief Operating Officer, Senior Vice President
and Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer
and Assistant Secretary of Chesapeake. He has been a director of Chesapeake
since 1996.
Michael P. McMasters (age 44) 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 42) 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 45) 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 and Ocean View, Delaware; Jupiter,
Lecanto, Venice and Stuart, Florida; Chincoteague and Belle Haven, Virginia;
Easton, Salisbury, Westminster, Severna Park 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 712 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 304 miles of transmission pipelines extending
from three supply interconnects at Parkesburg, Pennsylvania; Daleville,
Pennsylvania and Hockessin, Delaware to over seventy-five delivery points in
southeastern Pennsylvania, the eastern shore of Maryland and Delaware. Eastern
Shore also owns three compressor stations located in Delaware City, Delaware;
Daleville, Pennsylvania and Bridgeville, Delaware. The compressor stations are
used to increase pressures as necessary to meet system demands.
(D) PROPANE DISTRIBUTION AND MARKETING
The company's Delmarva-based propane distribution operation owns bulk propane
storage facilities with an aggregate capacity of approximately 2.2 million
gallons at 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 three bulk propane storage facilities with a total
capacity of 66,000 gallons. Xeron does not own physical storage facilities or
equipment to transport propane.
(E) WATER SERVICES
The Company owns and operates a resin regeneration facility in Salisbury,
Maryland to serve exchange tank and metered water customers and a sales office
in Fenton, Michigan. The other water operations operate out of rented
facilities.
ITEM 3. LEGAL PROCEEDINGS
(A) GENERAL
The Company and its subsidiaries are involved in certain legal actions and
claims arising in the normal course of business. The Company is also involved in
certain legal and administrative proceedings before various governmental
agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings will not have a material effect on the
consolidated financial position of the Company.
(B) ENVIRONMENTAL
DOVER GAS LIGHT SITE
In 1984, the State of Delaware notified the Company that they had discovered
contamination on a parcel of land it purchased in 1949 from Dover Gas Light
Company, a predecessor gas company. The State also asserted that the Company was
the responsible party for any clean-up and prospective environmental monitoring
of the site. The Delaware Department of Natural Resources and Environmental
Control ("DNREC") and Chesapeake conducted subsequent investigations and studies
beginning 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 fulfilled its remedial action obligation under the EPA Order.
The Company performed field studies and investigations during 1995 and 1996 to
further characterize the extent of contamination at the site. In April 1997, the
EPA issued a fact sheet stating that the EPA was considering a modification to
the soil remedy that would take into account the site's future land use
restrictions, which prohibited future development on the site. The EPA proposed
a soil remediation that included some on-site excavation of contaminated soils
and use of institutional controls; EPA estimated the cost of its proposed soil
remedy at $5.7 million. Additionally, the fact sheet acknowledged that the soil
remedy described in the ROD would cost $10.5 million, instead of the $3.3
million estimated in the ROD, making the overall remedy cost $13.2 million
($10.5 million to perform the soil remedy and $2.7 million to perform the
ground-water remediation).
In June 1997, the Company 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. In March 2001, the EPA approved discontinuation of the SVE system
and certified that the performance standards were met. The SVE decommissioning
and well abandonment were completed in June of 2001.
The parking lot construction (the remaining component of the soil remediation)
was completed in August 2002. It was constructed on the former manufactured gas
plant property, which is currently the location of the State of Delaware's
Johnson Victrola Museum. A final inspection of the parking lot was conducted on
August 19, 2002 at which time the USEPA and the State of Delaware gave its final
approval of the work.
A Remedial Action ("RA") Report was submitted to the EPA in September 2002 as
part of a request to close out the soil remedial program completed on the
property. The Remedial Action Report included a summary documentation of the
soil remediation (soil vapor extraction, holder remediation and parking lot
construction activities) completed on the property. Pending approval of the
consent decrees and EPA's final approval of the RA report, close out of the soil
remediation conducted on the property will fulfill Chesapeake's remedial action
obligations for the site.
Discussions regarding an appropriate ground-water remedy for the site have
continued. The Company's independent consultants 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 EPA is working with another responsible party to further
investigate the viability of monitored natural attenuation as the ground-water
remedy.
In March 1995, the Company commenced litigation against the State of Delaware
for contribution to the remedial costs being incurred to implement the ROD. In
December of 1995, this case was dismissed without prejudice based on a
settlement agreement between the parties (the "Settlement"). Under the
Settlement, the State agreed to: reaffirm the 1986 Agreement with Chesapeake not
to construct on the MGP property and support the Company's proposal to reduce
the soil remedy for the site; contribute $600,000 toward the cost of
implementing the ROD and reimburse the EPA for $400,000 in oversight costs. The
Settlement is contingent upon a formal settlement agreement between EPA and the
State of Delaware. Upon satisfaction of all conditions of the Settlement, the
litigation will be dismissed with prejudice.
In June 1996, the Company initiated litigation against GPU (now First Energy)
for response costs incurred by Chesapeake and a declaratory judgment as to GPU's
liability for future costs at the site. In August 1997, the United States
Department of Justice also filed a lawsuit against GPU seeking a Court Order to
require GPU to participate in the site clean-up, pay penalties for GPU's failure
to comply with the EPA Order, pay EPA's past costs and a declaratory judgment as
to GPU's liability for future costs at the site. In November 1998, Chesapeake's
case was consolidated with the United States' case against GPU. A case
management order scheduled the trial for February 2001. In early February 2001,
the Company and GPU reached a tentative settlement agreement that is subject to
approval of the courts.
In May 2001, Chesapeake, GPU, the State of Delaware and the EPA signed a
settlement term sheet reflecting the agreement in principle to settle a lawsuit
with respect to the Dover Gas Light site. The terms of the final agreement have
been memorialized in two consent decrees and have now been approved by all
parties. The consent decrees have been presented by the Department of Justice to
its highest level of management for final approval. 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:
o 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.
o 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 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 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.
Through December 31, 2002, the Company has incurred approximately $9.2 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,
2002, the unamortized balance and amount of environmental costs not included in
the rider were $2,243,000 and $24,000, respectively. With the rider mechanism
established, it is management's opinion that these costs and any future costs,
net of the deferred income tax benefit, will be recoverable in rates.
SALISBURY TOWN GAS LIGHT SITE
In cooperation with the Maryland Department of the Environment ("MDE"), the
Company completed assessment of the Salisbury manufactured gas plant site,
determining that there was localized ground-water contamination. During 1996,
the Company completed construction and began Air Sparging and Soil-Vapor
Extraction remediation procedures. Chesapeake has been reporting the remediation
and monitoring results to the MDE on an ongoing basis since 1996. In February
2002, the MDE granted permission to permanently decommission the
air-sparging/soil-vapor extraction system and abandon all of the monitoring
wells on-site and off-site, except one being maintained for continued product
monitoring and recovery. This work was completed in March 2002. In November
2002, a letter was submitted to the MDE requesting No Further Action ("NFA"). In
December 2002, the MDE recommended that the Company submit work plans to MDE and
place deed restrictions on the property as conditions prior to receiving an NFA.
Once these items are completed, it is expected that MDE will issue an NFA. The
Company is currently preparing the necessary work plans for submittal to MDE.
The estimated cost of the remaining remediation is approximately $21,000 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 $21,000 on December
31, 2002, to cover the Company's projected remediation costs for this site.
Through December 31, 2002, the Company has incurred approximately $2.9 million
for remedial actions and environmental studies. Of this amount, approximately
$1.1 million 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 ground-water in the northern portion of
the site. The FDEP approved the RAP on May 4, 2001.
Construction of the AS/SVE system was completed in the fourth quarter of 2002
and the system is now fully operational.
The Company has accrued a liability of $681,000 as of December 31, 2002 for the
Florida site. Through December 31, 2002, the Company has incurred approximately
$319,000 of environmental costs associated with the Florida site. A regulatory
asset of $406,000, representing the uncollected portion of the estimated
clean-up costs, had also been recorded.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS
(A) COMMON STOCK PRICE RANGES, COMMON STOCK DIVIDENDS AND SHAREHOLDER
INFORMATION:
The Company's Common Stock is listed on the New York Stock Exchange under the
symbol "CPK." The high, low and closing prices of Chesapeake's Common Stock and
dividends declared per share for each calendar quarter during the years 2002 and
2001 were as follows:
- ---------------------------------------------------------
DIVIDENDS
DECLARED
QUARTER ENDED HIGH LOW CLOSE PER SHARE
- ---------------------------------------------------------
2002
MARCH 31 . . $19.8500 $18.8000 $19.2000 $0.2750
JUNE 30. . . 21.9900 18.7500 19.0100 0.2750
SEPTEMBER 30 19.8500 17.3900 18.8600 0.2750
DECEMBER 31. 19.1100 16.5000 18.3000 0.2750
- ---------------------------------------------------------
2001
MARCH 31 . . $19.1250 $17.3750 $18.2000 $0.2700
JUNE 30. . . 19.5500 17.6000 18.8800 0.2750
SEPTEMBER 30 19.2000 17.7500 18.3500 0.2750
DECEMBER 31. 19.9000 18.1000 19.8000 0.2750
- ---------------------------------------------------------
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. Additionally, under the terms
of the 6.64 percent Senior Note, the Company cannot, until the retirement of the
Senior Note, pay any dividends after October 31, 2002 which exceed the sub of
$10 million plus consolidated net income recognized after January 1, 2003. As of
December 31, 2002, the amounts available for future dividends under this
covenant are $8.5 million.
At December 31, 2002, there were approximately 2,130 shareholders of record of
the Common Stock.
Securities authorized for issuance under equity compensation plans at December
31, 2002 were as follows:
- -------------------------------------------------------------------------------------------------------------------
(a) (b) (c)
Number of securities
remaining available for future
Number of securities to issuance under equity
be issued upon exercise Weighted-average exercise compensation plans
of outstanding options, price of outstanding (excluding securities
warrants and rights options, warrants and rights reflected in column (a))
- -------------------------------------------------------------------------------------------------------------------
Equity compensation
plans approved by
security holders. . . . . . 65,748 (1) $19.772 347,656 (2)
- -------------------------------------------------------------------------------------------------------------------
Equity compensation
plans not approved by
security holders. . . . . . 30,000 (3) $18.125 0
- -------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . 95,748 $19.256 347,656
- -------------------------------------------------------------------------------------------------------------------
<FN>
(1) Consists of options to purchase 41,948 shares and stock appreciation rights for 23,800 shares under the 1992
Performance Incentive Plan.
(2) Includes 19,800 shares under the 1995 Directors Stock Compensation Plan and 327,856 shares under the 1992
Performance Incentive Plan. The 327,856 shares excludes 8,385 shares issued in February of 2003 related to
2002 performance. The corresponding expense for the 8,385 shares was recognized in 2002.
(3) In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying
acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to
purchase 15,000 shares of Chesapeake stock in 2001 at a price of $18.25 per share and 15,000 shares in 2000
at a price of $18.00. The warrants are exercisable during a seven-year period after the date granted.
</FN>
ITEM 6. SELECTED FINANCIAL DATA
- -------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 1999 1998
- -------------------------------------------------------------------------------------------------------
OPERATING (IN THOUSANDS OF DOLLARS)
Revenues
Natural gas distribution and transmission. . $ 93,546 $107,937 $ 99,736 $ 75,603 $ 68,770
Propane. . . . . . . . . . . . . . . . . . . 24,522 27,613 31,780 25,199 23,377
Advanced informations systems. . . . . . . . 12,764 14,104 12,390 13,531 10,331
Water services . . . . . . . . . . . . . . . 11,731 9,971 7,011 2,593 1,737
Other & eliminations . . . . . . . . . . . . (333) (113) (131) (14) (15)
- -------------------------------------------------------------------------------------------------------
Total revenues . . . . . . . . . . . . . . . . $142,230 $159,512 $150,786 $116,912 $104,200
Gross margin
Natural gas distribution and transmission. . $ 40,866 $ 37,355 $ 35,384 $ 32,370 $ 29,677
Propane. . . . . . . . . . . . . . . . . . . 14,451 14,574 16,052 14,129 12,091
Advanced informations systems. . . . . . . . 6,064 6,719 5,693 6,575 5,316
Water services . . . . . . . . . . . . . . . 6,920 5,429 3,585 977 734
Other & eliminations . . . . . . . . . . . . (225) (111) (130) (13) (14)
- -------------------------------------------------------------------------------------------------------
Total gross margin . . . . . . . . . . . . . . $ 68,076 $ 63,966 $ 60,584 $ 54,038 $ 47,804
Operating income before taxes
Natural gas distribution and transmission. . $ 14,987 $ 14,455 $ 12,549 $ 10,306 $ 8,820
Propane. . . . . . . . . . . . . . . . . . . 1,052 913 2,135 2,622 965
Advanced informations systems. . . . . . . . 343 517 336 1,470 1,316
Water services . . . . . . . . . . . . . . . (2,786) (725) 190 (45) 19
Other & eliminations . . . . . . . . . . . . 236 386 816 496 485
- -------------------------------------------------------------------------------------------------------
Total operating income before taxes. . . . . . $ 13,832 $ 15,546 $ 16,026 $ 14,849 $ 11,605
Net income from continuing operations. . . . . $ 5,645 $ 6,722 $ 7,489 $ 8,271 $ 5,303
- -------------------------------------------------------------------------------------------------------
ASSETS (in thousands of dollars)
Gross property, plant and equipment. . . . . . $229,128 $216,903 $192,940 $172,088 $152,991
Net property, plant and equipment. . . . . . . $154,779 $150,256 $131,466 $117,663 $104,266
Total assets . . . . . . . . . . . . . . . . . $210,944 $210,335 $210,665 $166,789 $145,029
Capital expenditures . . . . . . . . . . . . . $ 15,040 $ 29,186 $ 23,056 $ 25,917 $ 12,650
- -------------------------------------------------------------------------------------------------------
CAPITALIZATION (in thousands of dollars)
Stockholders' equity . . . . . . . . . . . . . $ 66,690 $ 66,850 $ 63,972 $ 60,164 $ 56,356
Long-term debt, net of current maturities. . . $ 73,408 $ 48,408 $ 50,921 $ 33,777 $ 37,597
- -------------------------------------------------------------------------------------------------------
Total capital. . . . . . . . . . . . . . . . . $140,098 $115,258 $114,893 $ 93,941 $ 93,953
Current portion of long-term debt. . . . . . . $ 3,938 $ 2,686 $ 2,665 $ 2,665 $ 520
Short-term debt. . . . . . . . . . . . . . . . $ 10,900 $ 42,100 $ 25,400 $ 23,000 $ 11,600
- -------------------------------------------------------------------------------------------------------
Total capitalization and short-term financing. $154,936 $160,044 $142,958 $119,606 $106,073
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1997 1996 1995 1994 (1) 1993 (1)
- -------------------------------------------------------------------------------------------------------
OPERATING (IN THOUSANDS OF DOLLARS)
Revenues
Natural gas distribution and transmission. . $ 88,108 $ 90,044 $ 79,110 $ 71,781 $ 64,385
Propane. . . . . . . . . . . . . . . . . . . 28,614 36,727 26,806 20,770 16,957
Advanced informations systems. . . . . . . . 7,786 7,230 8,862 8,311 6,755
Water services . . . . . . . . . . . . . . . 1,550 1,256 1,239 0 0
Other & eliminations . . . . . . . . . . . . (182) (243) (1,662) (2,290) (2,224)
- -------------------------------------------------------------------------------------------------------
Total revenues . . . . . . . . . . . . . . . . $125,876 $135,014 $114,355 $ 98,572 $ 85,873
Gross margin
Natural gas distribution and transmission. . $ 30,086 $ 29,628 $ 29,102 $ 24,008 $ 22,838
Propane. . . . . . . . . . . . . . . . . . . 12,501 17,579 13,235 9,444 8,627
Advanced informations systems. . . . . . . . 4,065 4,554 6,687 8,311 6,755
Water services . . . . . . . . . . . . . . . 737 915 1,017 0 0
Other & eliminations . . . . . . . . . . . . (91) (230) (1,524) (2,204) (2,186)
- -------------------------------------------------------------------------------------------------------
Total gross margin . . . . . . . . . . . . . . $ 47,298 $ 52,446 $ 48,517 $ 39,559 $ 36,034
Operating income before taxes
Natural gas distribution and transmission. . $ 9,240 $ 9,627 $ 10,812 $ 7,820 $ 7,254
Propane. . . . . . . . . . . . . . . . . . . 1,137 2,668 2,128 2,288 1,588
Advanced informations systems. . . . . . . . 1,046 1,056 1,061 105 86
Water services . . . . . . . . . . . . . . . 113 72 67 0 0
Other & eliminations . . . . . . . . . . . . 558 560 (34) (456) (628)
- -------------------------------------------------------------------------------------------------------
Total operating income before taxes. . . . . . $ 12,094 $ 13,983 $ 14,034 $ 9,757 $ 8,300
Net income from continuing operations. . . . . $ 5,868 $ 7,782 $ 7,696 $ 4,460 $ 3,914
- -------------------------------------------------------------------------------------------------------
ASSETS (in thousands of dollars)
Gross property, plant and equipment. . . . . . $144,251 $134,001 $120,746 $110,023 $100,330
Net property, plant and equipment. . . . . . . $ 99,879 $ 94,014 $ 85,055 $ 75,313 $ 69,794
Total assets . . . . . . . . . . . . . . . . . $145,719 $155,787 $130,998 $108,271 $100,775
Capital expenditures . . . . . . . . . . . . . $ 13,471 $ 15,399 $ 12,887 $ 10,653 $ 10,064
- -------------------------------------------------------------------------------------------------------
CAPITALIZATION (in thousands of dollars)
Stockholders' equity . . . . . . . . . . . . . $ 53,656 $ 50,700 $ 45,587 $ 37,063 $ 34,817
Long-term debt, net of current maturities. . . $ 38,226 $ 28,984 $ 31,619 $ 24,329 $ 25,682
- -------------------------------------------------------------------------------------------------------
Total capital. . . . . . . . . . . . . . . . . $ 91,882 $ 79,684 $ 77,206 $ 61,392 $ 60,499
Current portion of long-term debt. . . . . . . $ 1,051 $ 3,526 $ 1,787 $ 1,348 $ 1,286
Short-term debt. . . . . . . . . . . . . . . . $ 7,600 $ 12,735 $ 5,400 $ 8,000 $ 8,900
- -------------------------------------------------------------------------------------------------------
Total capitalization and short-term financing. $100,533 $ 95,945 $ 84,393 $ 70,740 $ 70,685
- -------------------------------------------------------------------------------------------------------
<FN>
(1) The years 1994 and 1993 have not been restated to include the business
combinations with Tri-County Gas Company, Inc., Tolan Water Service
and Xeron, Inc.
</FN>
- --------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA AND RATIOS
Basic earnings per share before change in
accounting principle (2) (3) . . . . . . . . . . . . $ 1.21 $ 1.25 $ 1.43 $ 1.61 $ 1.05
Return on average equity before change in
accounting principle . . . . . . . . . . . . . . . . 8.5% 10.3% 12.1% 14.2% 9.6%
Common equity / total capital . . . . . . . . . . . . . 47.6% 58.0% 55.7% 64.0% 60.0%
Common equity / total capital and short-term financing. 43.0% 41.8% 44.7% 50.3% 53.1%
Book value per share. . . . . . . . . . . . . . . . . . $ 12.04 $ 12.32 $ 12.08 $ 11.60 $ 11.06
- --------------------------------------------------------------------------------------------------------------------------
Market price:
High. . . . . . . . . . . . . . . . . . . . . . . . . $ 21.990 $ 19.900 $ 18.875 $ 19.813 $ 20.500
Low . . . . . . . . . . . . . . . . . . . . . . . . . $ 16.500 $ 17.375 $ 16.250 $ 14.875 $ 16.500
Close . . . . . . . . . . . . . . . . . . . . . . . . $ 18.300 $ 19.800 $ 18.625 $ 18.375 $ 18.313
- --------------------------------------------------------------------------------------------------------------------------
Average number of shares outstanding. . . . . . . . . . 5,489,424 5,367,433 5,249,439 5,144,449 5,060,328
Shares outstanding end of year. . . . . . . . . . . . . 5,537,710 5,424,962 5,297,443 5,186,546 5,093,788
Registered common shareholders. . . . . . . . . . . . . 2,130 2,171 2,166 2,212 2,271
Cash dividends declared per share . . . . . . . . . . . $ 1.10 $ 1.10 $ 1.07 $ 1.03 $ 1.00
Dividend yield (annualized) . . . . . . . . . . . . . . 6.0% 5.6% 5.7% 5.6% 5.5%
Payout ratio before change in accounting principle. . . 90.9% 88.0% 74.8% 64.0% 95.2%
- --------------------------------------------------------------------------------------------------------------------------
ADDITIONAL DATA
Customers
Natural gas distribution and transmission . . . . . . 45,133 42,741 40,854 39,029 37,128
Propane distribution. . . . . . . . . . . . . . . . . 34,566 35,530 35,563 35,267 34,113
- --------------------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF). . . . . . . . . . . 27,935 27,264 30,830 27,383 21,400
Propane distribution (in thousands of gallons). . . . 21,185 23,080 28,469 27,788 25,979
- --------------------------------------------------------------------------------------------------------------------------
Heating degree-days (Delmarva Peninsula). . . . . . . . 4,161 4,368 4,730 4,082 3,704
Propane bulk storage capacity (in thousands of gallons) 2,151 1,958 1,928 1,926 1,890
Total employees . . . . . . . . . . . . . . . . . . . . 582 580 542 522 456
- --------------------------------------------------------------------------------------------------------------------------
<FN>
(2) Earnings per share amounts prior to 1995 represent primary earnings
per share.
(3) In 2002, the change in accounting principle reduced earnings per share
by $0.35. In 1993, the change increased earnings per share by $0.02.
</FN>
- --------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1997 1996 1995 1994 (1) 1993 (1)
- --------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA AND RATIOS
Basic earnings per share before change in
accounting principle (2) (3) . . . . . . . . . . . . $ 1.18 $ 1.58 $ 1.59 $ 1.23 $ 1.10
Return on average equity before change in
accounting principle . . . . . . . . . . . . . . . . 11.3% 16.2% 18.6% 12.4% 11.5%
Common equity / total capital . . . . . . . . . . . . . 58.4% 63.6% 59.0% 60.4% 57.5%
Common equity / total capital and short-term financing. 53.4% 52.8% 54.0% 52.4% 49.3%
Book value per share. . . . . . . . . . . . . . . . . . $ 10.72 $ 10.26 $ 9.38 $ 10.15 $ 9.76
- --------------------------------------------------------------------------------------------------------------------------
Market price:
High. . . . . . . . . . . . . . . . . . . . . . . . . $ 21.750 $ 18.000 $ 15.500 $ 15.250 $ 17.500
Low . . . . . . . . . . . . . . . . . . . . . . . . . $ 16.250 $ 15.125 $ 12.250 $ 12.375 $ 13.000
Close . . . . . . . . . . . . . . . . . . . . . . . . $ 20.500 $ 16.875 $ 14.625 $ 12.750 $ 15.375
- --------------------------------------------------------------------------------------------------------------------------
Average number of shares outstanding. . . . . . . . . . 4,972,086 4,912,136 4,836,430 3,628,056 3,551,932
Shares outstanding end of year. . . . . . . . . . . . . 5,004,078 4,939,515 4,860,588 3,653,182 3,575,068
Registered common shareholders. . . . . . . . . . . . . 2,178 2,213 2,098 1,721 1,743
Cash dividends declared per share . . . . . . . . . . . $ 0.97 $ 0.93 $ 0.90 $ 0.88 $ 0.86
Dividend yield (annualized) . . . . . . . . . . . . . . 4.7% 5.5% 6.2% 6.9% 5.6%
Payout ratio before change in accounting principle. . . 82.2% 58.9% 56.6% 71.5% 78.2%
- --------------------------------------------------------------------------------------------------------------------------
ADDITIONAL DATA
Customers
Natural gas distribution and transmission . . . . . . 35,797 34,713 33,530 32,346 31,270
Propane distribution. . . . . . . . . . . . . . . . . 33,123 31,961 31,115 22,180 21,622
- --------------------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF). . . . . . . . . . . 23,297 24,835 29,260 22,728 19,444
Propane distribution (in thousands of gallons). . . . 26,682 29,975 26,184 18,395 17,250
- --------------------------------------------------------------------------------------------------------------------------
Heating degree-days (Delmarva Peninsula). . . . . . . . 4,430 4,717 4,594 4,398 4,705
Propane bulk storage capacity (in thousands of gallons) 1,866 1,860 1,818 1,230 1,140
Total employees . . . . . . . . . . . . . . . . . . . . 397 338 335 320 326
- --------------------------------------------------------------------------------------------------------------------------
<FN>
(1) The years 1994 and 1993 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 prior to 1995 represent primary earnings
per share.
(3) In 2002, the change in accounting principle reduced earnings per share
by $0.35. In 1993, the change increased earnings per share by $0.02.
</FN>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
BUSINESS DESCRIPTION
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a
diversified utility company engaged in natural gas distribution and
transmission, propane distribution and wholesale marketing, advanced information
services, water conditioning and treatment 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 2002, net cash provided
by operating activities was $24.4 million, cash used by investing activities was
$14.1 million and cash used by financing activities was $9.1 million. Cash
provided by operations was up $8.9 million over 2001 due primarily to a
reduction in the underrecovered purchased gas cost balance of $3.6 million, an
increase in accounts payable, partially caused by liabilities for capital
improvements totaling $1.9 million, and an increase of $1.4 million in
depreciation.
The Company completed a private placement of $30.0 million of long-term debt and
drew down the funds on October 31, 2002. The debt has a fixed interest rate of
6.64 percent and is due October 31, 2017. The funds were used to repay
short-term borrowing.
As of December 31, 2002 the Board of Directors has authorized the Company to
borrow up to $35.0 million of short-term debt from various banks and trust
companies. On December 31, 2002, Chesapeake had four unsecured bank lines of
credit with three financial institutions, totaling $75.0 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, totaling $15.0
million, is committed. The other three lines are subject to the banks'
availability of funds. Prior to the issuance of the $30.0 million long-term debt
on October 31, 2002, the Board had authorized the Company to borrow up to $55.0
million of short-term debt. The outstanding balances of short-term borrowing at
December 31, 2002 and 2001 were $10.9 million and $42.1 million, respectively.
In 2002, Chesapeake used funds provided by operations to fund capital
expenditures and repay debt. In 2001, Chesapeake used funds provided from
operations, short-term borrowing and cash on hand to fund capital expenditures.
During 2002, 2001 and 2000, investing activities totaled approximately $14.1,
$29.2 and $21.8 million, respectively. The property, plant and equipment
expenditures for 2002 were primarily for natural gas distribution ($8.1 million)
and natural gas transmission ($4.0 million). Natural gas distribution utilized
funds to improve facilities and expand facilities to serve new customers.
Natural gas transmission spending related primarily to expanding its system.
Capital expenditures increased in 2001 over 2000 primarily as a result of
Eastern Shore Natural Gas expenditures, totaling $16.0 million, related to
system expansion. Natural gas distribution also spent approximately $7.2 million
in 2001 for expansion of facilities to serve new customers and for improvements
of facilities. The purchases of intangibles were related to acquisitions of
water companies.
Chesapeake has budgeted $16.5 million for capital expenditures during 2003. This
amount includes $12.1 million for natural gas distribution and transmission,
$2.3 million for propane distribution and marketing, $237,000 for advanced
information services, $1.2 million for water services and $451,000 for other
operations. The natural gas distribution and transmission expenditures are for
expansion and improvement of facilities. The propane expenditures are to support
customer growth and for the replacement of equipment. The advanced information
services expenditures are for computer hardware, software and related equipment.
Expenditures for water services include expenditures to support customer growth
and replace equipment. The other category includes general plant, computer
software and hardware. Financing for the 2003 capital expenditure program is
expected to be provided from short-term borrowing and cash provided by operating
activities. The capital expenditure program is subject to continuous review and
modification. Actual capital requirements may vary from the above estimates due
to a number of factors, including acquisition opportunities, changing economic
conditions, customer growth in existing areas, regulation, new growth
opportunities and availability of capital.
Chesapeake has budgeted $202,000 for environmental-related expenditures during
2003 and expects to incur additional expenditures in future years (see Note M to
the Consolidated Financial Statements). Management does not expect financing of
future environmental-related expenditures to have a material adverse effect on
the financial position or capital resources of the Company.
CAPITAL STRUCTURE
As of December 31, 2002, common equity represented 47.6 percent of total
permanent capitalization, compared to 58.0 percent in 2001. Including short-term
borrowing and the current portion of long-term debt, the equity component of the
Company's capitalization would have been 43.0 percent and 41.8 percent,
respectively. Chesapeake remains committed to maintaining a sound capital
structure and strong credit ratings to provide the financial flexibility needed
to access the capital markets when required. This commitment, along with
adequate and timely rate relief for the Company's regulated operations, is
intended to ensure that Chesapeake will be able to attract capital from outside
sources at a reasonable cost. The Company believes that the achievement of these
objectives will provide benefits to customers and creditors, as well as to the
Company's investors.
FINANCING ACTIVITIES
During the past two years, the Company has utilized debt and equity financing
for the purpose of funding capital expenditures and acquisitions.
As noted above, on October 31, 2002, Chesapeake completed a private placement of
$30.0 million of 6.64 percent Senior Notes due October 31, 2017. The Company
used the proceeds to repay short-term debt.
In May 2001, Chesapeake issued a note payable of $300,000 at 8.5 percent, due
April 6, 2006, in conjunction with a real estate purchase. This note was repaid
in full on January 6, 2003. 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 $3.7 million and $2.7 million of long-term debt
in 2002 and 2001, respectively. Chesapeake issued common stock in connection
with its Automatic Dividend Reinvestment and Stock Purchase Plan in the amounts
of 49,782 shares in 2002, 43,101 shares in 2001 and 41,056 shares in 2000.
Chesapeake also issued shares of common stock totaling 52,740, 54,921 and 52,093
in 2002, 2001 and 2000, respectively, for matching contributions for the
Retirement Savings Plan.
RESULTS OF OPERATIONS
Net income before the change in accounting principle for 2002 was $5.6 million
compared to $6.7 million for 2001 and $7.5 million for 2000. Net income, after
the change in accounting principle for 2002 was $3.7 million or $0.68 per share.
Chesapeake adopted Statement of Financial Accounting Standards No. 142 "Goodwill
and Other Intangible Assets" in 2002. This resulted in a non-cash charge for
goodwill impairment recorded in the first quarter, as the cumulative effect of a
change in accounting principle.
NET INCOME & BASIC EARNINGS PER SHARE SUMMARY
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
BEFORE CHANGE IN ACCOUNTING PRINCIPLE
Net income *. . . . . . . . . . . . . $ 5,645 $ 6,722 ($1,077) $ 6,722 $ 7,489 ($767)
Earnings per share. . . . . . . . . . $ 1.03 $ 1.25 ($0.22) $ 1.25 $ 1.43 ($0.18)
AFTER CHANGE IN ACCOUNTING PRINCIPLE
Net income *. . . . . . . . . . . . . $ 3,729 $ 6,722 (2,993) 6,722 $ 7,489 (767)
Earnings per share. . . . . . . . . . $ 0.68 $ 1.25 ($0.57) $ 1.25 $ 1.43 ($0.18)
- -------------------------------------------------------------------------------------------------------------
* Dollars in thousands.
Pre-tax operating income increased for the natural gas and propane segments,
despite temperatures in the Delmarva region that were 5 percent warmer than both
the 10-year average and 2001. Those increases were more than offset by declines
in the advanced information services, water services and other segments.
Advanced information services was adversely affected by a slowdown in the
information technology services sector. The decline in water services was
primarily the result of a goodwill impairment charge and a restructuring charge.
PRE-TAX OPERATING INCOME SUMMARY (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
BUSINESS SEGMENT:
Natural gas distribution &
transmission. . . . . . . . . . . . $ 14,987 $ 14,455 $ 532 $ 14,455 $12,549 $ 1,906
Propane . . . . . . . . . . . . . . . 1,052 913 139 913 2,135 (1,222)
Advanced information services . . . . 343 517 (174) 517 336 181
Water services. . . . . . . . . . . . (2,786) (725) (2,061) (725) 190 (915)
Other & eliminations. . . . . . . . . 236 386 (150) 386 816 (430)
- -------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME. . . . . $ 13,832 $ 15,546 ($1,714) $ 15,546 $16,026 ($480)
- -------------------------------------------------------------------------------------------------------------
The reduction in earnings in 2001 compared to 2000 was due to declines in the
propane segment, water services 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 the
ten-year average. The margin decrease was partially offset by savings in
operating expenses resulting from cost containment measures implemented during
2001. The decrease in water services was due principally to increased overhead
related 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, from a rate increase in Florida and
reductions in operating expenses in Delaware and Maryland.
NATURAL GAS DISTRIBUTION AND TRANSMISSION
The natural gas distribution and transmission segment increased pre-tax
operating income to $15.0 million for 2002 compared to $14.5 million for
2001, an increase of $532,000.
NATURAL GAS DISTRIBUTION AND TRANSMISSION (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 93,546 $ 107,937 ($14,391) $107,937 $99,736 $ 8,201
Cost of gas . . . . . . . . . . . . . . 52,680 70,582 (17,902) 70,582 64,352 6,230
- -------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 40,866 37,355 3,511 37,355 35,384 1,971
Operations & maintenance. . . . . . . . 16,667 14,730 1,937 14,730 15,312 (582)
Depreciation & amortization . . . . . . 6,429 5,638 791 5,638 5,236 402
Other taxes . . . . . . . . . . . . . . 2,783 2,532 251 2,532 2,287 245
- -------------------------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . . 25,879 22,900 2,979 22,900 22,835 65
- -------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME. . . . . $ 14,987 $ 14,455 $ 532 $ 14,455 $12,549 $ 1,906
- -------------------------------------------------------------------------------------------------------------
Revenue and cost of gas decreased due to lower natural gas commodity costs
in 2002 compared to 2001. Commodity cost changes are passed on to the
ratepayers through a gas cost recovery or purchased gas cost adjustment in
all jurisdictions; therefore, they have no impact on the Company's
profitability. Revenue and cost of gas were also down in part because of
the unbundling of services that took effect in 2001 for all nonresidential
customers of the Florida division and in November 2002 for residential
customers. As a result, all Florida customers have switched from sales
service, where they purchase both the commodity and transportation service
from the Company, to purchasing transportation service only.
Gross margin increased $3.5 million over the same period in 2001 due to
increases in the margins for the transmission operation and the Delaware
and Florida distribution operations. Transmission margins were up due to
the completion of a major system expansion in November of 2001. The Company
expects this system expansion to increase margins by approximately $2.2
million per year. A second expansion, completed in November 2002, is
expected to increase margins by approximately $500,000 per year. As
discussed more fully in the regulatory matters section, the Company's
transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern
Shore"), reached an agreement with the Federal Energy Regulatory Commission
("FERC") on October 10, 2002. That agreement is expected to lower annual
margins by an estimated $456,000. The new rates took effect December 1,
2002. As a result of these two offsetting factors, management expects
transmission margins in 2003 to be approximately equal to 2002. Margins in
Delaware and Maryland were adversely impacted by temperatures that were 4.7
percent warmer (207 heating degree-days) than 2001 and 5.2 percent (232
heating degree-days) warmer than the 10-year average. Management estimates
that on an annual basis, margins will fluctuate by $1,730 for each heating
degree-day. This decline was more than offset by residential customer
growth of 1,838, or 6.5 percent, and a rate increase in Delaware.
Chesapeake estimates that for each residential customer added, an
additional $260 per year will be added to earnings before interest, taxes,
depreciation and amortization. The margin increases were partially offset
by higher operating expenses, primarily administrative and general and
depreciation. The increase in depreciation reflects completion of recent
capital projects that increased the transmission capacity and various
expansion projects in Florida.
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 operation 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
service 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 warmer 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 was a one-time credit adjustment of
approximately $280,000 to establish a regulatory asset for other
post-retirement benefits that are being collected through the Company's
rates on a "pay-as-you-go" basis in Delaware.
PROPANE
Pre-tax operating income for the propane segment increased from $913,000 in
2001 to $1.1 million in 2002. Reductions in operating expenses of $262,000
more than offset a decrease of $123,000 in gross margin.
PROPANE (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 24,522 $ 27,613 ($3,091) $ 27,613 $31,780 ($4,167)
Cost of sales . . . . . . . . . . . . . 10,071 13,039 (2,968) 13,039 15,728 (2,689)
- -------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 14,451 14,574 (123) 14,574 16,052 (1,478)
Operations & maintenance. . . . . . . . 11,053 11,459 (406) 11,459 11,823 (364)
Depreciation & amortization . . . . . . 1,603 1,465 138 1,465 1,446 19
Other taxes . . . . . . . . . . . . . . 743 737 6 737 648 89
- -------------------------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . . 13,399 13,661 (262) 13,661 13,917 (256)
- -------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME. . . . . $ 1,052 $ 913 $ 139 $ 913 $ 2,135 ($1,222)
- -------------------------------------------------------------------------------------------------------------
A retroactive reclassification was made in the third quarter due to a
consensus that was reached by the Financial Accounting Standards Board
("FASB") Emerging Issues Task Force ("EITF") in June 2002 to revise Issue
No. EITF 02-03 and disallow gross reporting of revenue and cost of sales
for energy trading contracts. The Company's propane wholesale marketing
operation previously used the gross method for certain energy trading
contracts. The requirement that all energy trading contracts be reported
net reduced both the revenue and cost of sales by $96.5 million in 2002 and
$170.8 million in 2001. There was no impact on the gross margin, net
income, earnings per share or the financial position of the Company.
Propane distribution revenues and costs were lower by $6.5 million and $7.6
million, respectively, due to a drop in propane commodity prices and volume
decreases. Both increases and decreases in commodity costs, are generally
passed on to the distribution customers subject to competitive market
conditions.
Propane wholesale marketing margins declined by $1.1 million in 2002
compared to 2001 and were partially offset by a reduction of $258,000 in
operating expenses. The 2001 results reflected increased opportunities due
to the extreme price volatility in the propane wholesale market. The same
level of price fluctuations was not experienced in 2002. Additionally,
there was a decrease in the number of suitable trading partners due to a
decision by some companies to exit energy trading activities and the
decreased credit-worthiness of other parties. The 2002 results reflected
increased margins of approximately $650,000 that resulted from a bankrupt
vendor defaulting on supply contracts during the first quarter of 2002. The
supply was replaced by purchasing from different vendors at a lower cost
than the original contract. The propane wholesale marketing operation
remains profitable, despite the decline in earnings.
The Delmarva distribution operations experienced an increase of $624,000 in
gross margin. Although volumes sold were down 8 percent, higher margins per
gallon and stable wholesale propane prices resulted in increased margin
dollars. Volumes were negatively impacted by temperatures that were 4.7
percent warmer than 2001 (207 heating degree-days) and 5.2 percent warmer
than the 10-year average (232 heating degree-days), increased competition
and lower volume sales to the poultry industry. Management estimates that
on an annual basis, margins increase or decrease by $1,566 for each heating
degree-day colder or warmer than the 10-year average. Operating expenses
decreased by $249,000 resulting from cost containment efforts that began in
April 2001 and remain in effect. These efforts have reduced customer
accounting, sales and marketing costs. Other costs, such as delivery
expenses, decreased due to the lower volumes sold. The pre-tax operating
income of the Florida propane operation increased by $195,000 in 2002.
Margins increased $441,000, but were partially offset by an increase if
$246,000 in operating expenses.
During 2001, the Company's gross margins on the Delmarva Peninsula declined
by approximately $1.7 million compared to 2000, due to a 13 percent decline
in bulk and metered 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 poultry customers
comprised 32 percent of the decline in margins. The decreases in volume
were exacerbated by the decline in wholesale prices over the course of
2001. 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 also affected volumes sold in 2001. In recent years,
several independent dealers entered the propane business with pricing
strategies designed to acquire market share. The Company's position as a
top distributor in several of the markets that it serves makes it
particularly vulnerable to these tactics.
In 2000, the Company started three propane distribution operations in
Florida. The operations contributed $238,000 to gross margin in 2001.
Although the margins contributed by the propane marketing operation
declined by four percent in 2001 compared to 2000, they were still well
above the earnings target established by the Company.
ADVANCED INFORMATION SERVICES
The advanced information services segment provides consulting, custom
programming, training, development tools and website development for
national and international clients. The advanced information services
business earned pre-tax operating income of $343,000 in 2002 compared to
income of $517,000 for 2001. The decrease is the result of decreased
revenue partially offset by decreased operating expenses.
ADVANCED INFORMATION SERVICES (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 12,764 $ 14,104 ($1,340) $ 14,104 $12,390 $ 1,714
Cost of sales . . . . . . . . . . . . . 6,700 7,385 (685) 7,385 6,697 688
- -------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 6,064 6,719 (655) 6,719 5,693 1,026
Operations & maintenance. . . . . . . . 4,940 5,361 (421) 5,361 4,575 786
Depreciation & amortization . . . . . . 208 256 (48) 256 280 (24)
Other taxes . . . . . . . . . . . . . . 573 585 (12) 585 502 83
- -------------------------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . . 5,721 6,202 (481) 6,202 5,357 845
- -------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME. . . . . $ 343 $ 517 ($174) $ 517 $ 336 $ 181
- -------------------------------------------------------------------------------------------------------------
This segment was adversely affected by the nation's economic slowdown as
discretionary consulting projects have been postponed or cancelled. This
was partially offset by a reduction in operating expenses, principally
sales and marketing.
In 2001, the segment's contribution to pre-tax operating income increased
$181,000 over the depressed levels in 2000, to $517,000. 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.
WATER SERVICES
Water services experienced a pre-tax operating loss of $2.8 million for
2002 compared to a loss of $725,000 for 2001. The pre-tax operating loss is
primarily due to a $1.5 million goodwill impairment charge and a
restructuring charge of $138,000. The results for 2002 include a full year
of operations for the four water businesses that were purchased between
April and July of 2001.
WATER SERVICES (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 11,731 $ 9,971 $ 1,760 $ 9,971 $ 7,011 $ 2,960
Cost of sales . . . . . . . . . . . . . 4,811 4,542 269 4,542 3,426 1,116
- -------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 6,920 5,429 1,491 5,429 3,585 1,844
Operations & maintenance. . . . . . . . 6,938 5,072 1,866 5,072 2,827 2,245
Depreciation & amortization . . . . . . 843 742 101 742 375 367
Goodwill impairment . . . . . . . . . . 1,474 0 1,474 0 0 0
Other taxes . . . . . . . . . . . . . . 451 340 111 340 193 147
- -------------------------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . . 9,706 6,154 3,552 6,154 3,395 2,759
- -------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING (LOSS) INCOME . ($2,786) ($725) ($2,061) ($725) $ 190 ($915)
- -------------------------------------------------------------------------------------------------------------
The increases in all categories of revenue and expenses reflect the
acquisition of the new water businesses. As noted above, pre-tax operating
losses increased $2.1 million primarily due to a non-cash charge of $1.5
million for goodwill impairment. Statement of Financial Accounting
Standards ("SFAS") No. 142 requires an annual assessment of goodwill for
possible impairment. The Company's assessment performed in December
indicated the charge was necessary. At December 31, 2002, the balance of
goodwill related to the water services business was reduced to $195,000.
Results for 2002 were also affected by increased expenses associated with
the water corporate infrastructure. In the fourth quarter of 2002, a charge
of $138,000 for restructuring costs and penalties associated with closing a
water management office were incurred. This action was taken to reduce
future overhead costs associated with the water services business.
Water services' contribution to pre-tax operating income declined by
$915,000 in 2001 compared to 2000. 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 Florida during 2001
experienced a pre-tax loss of $177,000 (net of corporate charges) during
2001. Transition costs were incurred after the acquisition, primarily the
relocation of offices and related expenses.
OTHER OPERATIONS
Other operations consists of subsidiaries that own real estate leased to
other Chesapeake subsidiaries.
OTHER OPERATIONS (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
- -------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 717 $ 783 ($66) $ 783 $ 841 ($58)
Cost of sales . . . . . . . . . . . . . 0 0 0 0 0 0
- -------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 717 783 (66) 783 841 (58)
Operations & maintenance. . . . . . . . 84 108 (24) 108 165 (57)
Depreciation & amortization . . . . . . 233 233 0 233 127 106
Other taxes . . . . . . . . . . . . . . 57 57 0 57 55 2
- -------------------------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . . 374 398 (24) 398 347 51
- -------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME. . . . . $ 343 $ 385 ($42) $ 385 $ 494 ($109)
- -------------------------------------------------------------------------------------------------------------
INCOME TAXES
Operating income taxes were lower due to the decrease in operating income and a
lowering of the effective federal income tax rate from 35 percent to 34 percent
in 2002. Additionally, during 2002 the Company benefited from a change in the
tax law that allows tax deductions for dividends paid on Company stock held in
Employee Stock Ownership Plans ("ESOP").
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.
OTHER INCOME
Non-operating income, net of tax, was $334,000, $483,000 and $361,000 for the
years 2002, 2001 and 2000, respectively. This includes interest income, earned
primarily on regulatory assets and gains from the sale of plant assets.
INTEREST EXPENSE
Interest expense for 2002 decreased approximately $222,000, or 4 percent, over
the same period in 2001. The decrease was due primarily to a reduction in the
average interest rate for short-term borrowing from 4.43 percent on an average
balance of $26.9 million in 2001 to 2.35 percent on an average balance of $29.4
million for the same period in 2002. Interest on long-term debt partially offset
the short-term savings, due to an increase in the average balance outstanding
from $52.4 million in 2001 to $57.1 million in 2002. However, the average
long-term interest rate declined from 7.64 percent to 7.19 percent, offsetting a
portion of the increase related to higher balances.
Interest expense for 2001 increased over 2000 due to a higher level of long-term
debt, partially offset by lower interest rates on short-term borrowing.
CRITICAL ACCOUNTING POLICIES
Chesapeake's financial condition and results of operations are impacted by the
accounting methods, assumptions and estimates used in critical accounting
policies. However, because most of Chesapeake's businesses are regulated, the
accounting methods used by Chesapeake must comply with the requirements of the
regulatory bodies; therefore, the choices are limited. Management believes that
the following policies require significant estimates or other judgments of
matters that are inherently uncertain. These policies have been discussed with
the Audit Committee of Chesapeake.
REGULATORY ASSETS AND LIABILITIES
Chesapeake records certain assets and liabilities in accordance with SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation." Costs
are deferred when there is a probable expectation that they will be
recovered in future revenues as a result of the regulatory process. At
December 31, 2002. Chesapeake had recorded regulatory assets of $8.9
million, including $3.0 million for underrecovered purchased gas costs and
$5.1 million for environmental costs. There is also a liability of $2.8
million for environmental costs. If the Company were required to terminate
application of SFAS No. 71, all such deferred amounts would be recognized
in the income statement. This would result in a charge to earnings, net of
applicable income taxes, that could be material.
GOODWILL IMPAIRMENT
In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets",
Chesapeake no longer amortized goodwill during 2002. Instead, goodwill was
tested for impairment upon adoption of SFAS No. 142 on January 1, 2002, and
again at the end of the year. These tests are based on subjective
measurements, including discounted cash flows of expected future operating
results and market valuations of similar businesses. Those tests indicated
that the goodwill associated with the water business was impaired and
charges totaling $4.7 million (pre-tax) were recorded. The remaining water
goodwill balance was $195,000 at December 31, 2002.
ENVIRONMENTAL
As more fully described in Note M to the Financial Statements, Chesapeake
is currently participating in the investigation, assessment or remediation
of three former gas manufacturing plant sites. Amounts have been recorded
as environmental liabilities and associated environmental regulatory assets
based on estimates of future costs provided by independent consultants.
There is uncertainty in these amounts because the Environmental Protection
Agency ("EPA") or state authority may not have selected the final
remediation methods. Additionally, there is uncertainty due to the outcome
of legal remedies sought from other potentially responsible parties. At
December 31, 2002, Chesapeake had recorded environmental regulatory assets
of $5.1 million and a liability for environmental costs of $2.8 million.
PROPANE WHOLESALE MARKETING CONTRACTS
Chesapeake's propane wholesale marketing operation enters into forward and
futures contracts that are considered derivatives under SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." In
accordance with the pronouncement, open positions are marked-to-market
prices at the end of each reporting period and unrealized gains or losses
are recorded in the Statement of Income. The contracts all mature within
one year, and are almost exclusively for propane commodities with delivery
points of Mt. Belvieu, Texas and Hattiesburg, Mississippi. Management
estimates the market valuation based on reference to exchange-traded
futures prices, historical differentials and actual trading activity at the
end of the reporting period. At December 31, 2002, there was an unrealized
gain of $630,000 compared to an unrealized loss of $75,000 at December 31,
2001.
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. However, the regulatory authorities have granted the
Company's regulated natural gas distribution operations the ability to
negotiate rates with customers that have competitive alternatives using
approved methodologies. In addition, the natural gas transmission
operations can negotiate rates above or below the FERC approved tariff
rates. With the exception of the Company's Florida division, the Company
recognizes revenues from meters read on a monthly cycle basis. This
practice results in unbilled and unrecorded revenue from the cycle date
through the end of the month. The Florida division recognizes revenues
based on services rendered and records an amount for gas delivered but not
yet billed.
Chesapeake's natural gas distribution operations each have a gas cost
recovery mechanism that provides for the adjustment of rates charged to
customers as gas costs fluctuate. These amounts are collected or refunded
through adjustments to rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution's
industrial interruptible customers to make them competitive with
alternative types of fuel. Based on pricing, these customers can choose
natural gas or alternative types of supply. Neither the Company nor the
interruptible 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 records trading activity net, on a mark-to-market basis
for open contracts.
The advanced information services, water services and other segments record
revenue in the period the products are delivered and/or services are
rendered.
REGULATORY ACTIVITIES
The Company's natural gas distribution operations are subject to regulation by
the Delaware, Maryland and Florida Public Service Commissions. The natural gas
transmission operation is subject to regulation by the FERC.
On August 2, 2001, the Delaware division filed a general rate increase
application with the Delaware Public Service Commission ("PSC"). Interim rates,
subject to refund, went into effect on October 1, 2001. The PSC approved a
settlement agreement for Phase I of the Rate Increase Application in April 2002.
Phase I should result in an increase in rates of approximately $380,000 per
year. Phase II of the filing was approved by the Delaware PSC in November 2002.
It should result in an additional increase in rates of approximately $90,000.
Phase II also reduces the Company's sensitivity to weather by changing the
minimum customer charge and the margin sharing arrangement for interruptible
sales, off system sales and capacity release income.
In 1999, the Company requested and received approval from the Delaware PSC 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 ran 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. This mechanism automatically
terminated when the Delaware division filed a general rate increase application
on August 2, 2001. There was no impact on margins in 2001 due to this mechanism.
On October 31, 2001, Eastern Shore filed a rate change with the FERC pursuant to
the requirements of the Stipulation and Agreement dated August 1, 1997.
Following settlement conferences held in May 2002, the parties reached a
settlement in principle on or about May 23, 2002, to resolve all issues related
to its rate case.
The Offer of Settlement and the Stipulation and Agreement were finalized and
filed with the FERC on August 2, 2002. The agreement provides that Eastern
Shore's rates will be based on a cost of service of $12.9 million per year. Cost
savings estimated at $456,000 will be passed on to firm transportation
customers. Initial comments supporting the settlement agreement were filed by
the FERC staff and by Eastern Shore. No adverse comments were filed. The
Presiding Judge certified the Offer of Settlement to the FERC as uncontested on
August 27, 2002. On October 10, 2002, the FERC issued an Order approving the
Offer of Settlement and the Stipulation and Agreement. Settlement rates went
into effect on December 1, 2002.
During October 2002, Eastern Shore filed for recovery of gas supply realignment
costs associated with the implementation of FERC Order No. 636. The costs
totaled $196,000 (including interest). It is uncertain at this time when the
FERC will consider this matter or the ultimate outcome.
On March 29, 2002, the Florida division filed tariff revisions with the Florida
PSC to complete the unbundling process by requiring all customers, including
residential, to migrate to transportation service and authorized the Florida
division to exit the merchant function. Transportation services were already
available to all nonresidential customers. On November 5, 2002, the Florida PSC
approved the Company's request for the first phase of the unbundling process as
a pilot program for a minimum two-year period. The Company is implementing the
program immediately and must submit an interim report for review by the Florida
PSC after one year. As a part of this pilot program, the Company expects to
submit several filings over the first six months of 2003 to address transition
costs, the disposition of the unrecovered gas cost balances, the implementation
of the operational balancing account and the level of base rates.
In January 2000, the Company filed a request for approval of a rate increase
with the Florida PSC. 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 four
environmental sites (see Note M 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 $77.3 million at December 31, 2002, as compared to a fair
value of $88.0 million, based mainly on current market prices or discounted cash
flows using current rates for similar issues with similar terms and remaining
maturities. The Company is exposed to changes in interest rates as a result of
financing through its issuance of fixed-rate long-term debt. The Company
evaluates whether to refinance existing debt or permanently finance existing
short-term borrowing based in part on the fluctuation in interest rates.
The Company's propane distribution business is exposed to market risk as a
result of propane storage activities and entering into fixed price contracts for
supply. The Company can store up to approximately four million gallons of
propane (including leased storage) 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 or booking
out the transaction (booking out is a procedure for financially settling a
contract in lieu of the physical delivery of energy). The wholesale propane
marketing operation also enters into futures contracts that are traded on the
New York Mercantile Exchange. In certain cases, the futures contracts are
settled by the payment of a net amount equal to the difference between the
current market price of the futures contract and the original contract price.
The forward and futures contracts are entered into for trading and wholesale
marketing purposes. The propane marketing operation is subject to commodity
price risk on its open positions to the extent that market prices for NGL
deviate from fixed contract settlement amounts. Market risk associated with the
trading of futures and forward contracts are monitored daily for compliance with
Chesapeake's Risk Management Policy, which includes volumetric limits for open
positions. To manage exposures to changing market prices, open positions are
marked up or down to market prices and reviewed by oversight officials on a
daily basis. Additionally, the Risk Management Committee reviews periodic
reports on market and credit risk, approves any exceptions to the Risk
Management Policy (within the limits established by the Board of Directors) and
authorizes the use of any new types of contracts. Quantitative information on
the forward and futures contracts at December 31, 2002 and 2001 is shown below.
- -------------------------------------------------------------------------
QUANTITY ESTIMATED WEIGHTED AVERAGE
AT DECEMBER 31, 2002 IN GALLONS MARKET PRICES CONTRACT PRICES
- -------------------------------------------------------------------------
FORWARD CONTRACTS
Sale . . . . . . . . 7,291,200 $ 0.5200 - $0.5700 $ 0.5349
Purchase . . . . . . 4,515,000 $ 0.5200 - $0.5700 $ 0.5001
FUTURES CONTRACTS
Sale . . . . . . . . 1,764,000 $ 0.5200 - $0.5400 $ 0.5449
- -------------------------------------------------------------------------
<FN>
Estimated market prices and weighted average contract prices
are in dollars per gallon.
All contracts expire in 2003.
</FN>
- -------------------------------------------------------------------------
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
- -------------------------------------------------------------------------
<FN>
Estimated market prices and weighted average contract prices
are in dollars per gallon.
All contracts expired in 2002.
</FN>
The Company's natural gas distribution operations have entered into agreements
with natural gas suppliers to purchase natural gas for resale to their
customers. Purchases under these contracts are considered "normal purchases and
sales" under SFAS No. 133 and are not marked-to-market.
COMPETITION
The Company's natural gas operations compete with other forms of energy
including electricity, oil and propane. The principal competitive factors are
price, and to a lesser extent, accessibility. The Company's natural gas
distribution operations have several large volume industrial customers that have
the capacity to use fuel oil as an alternative to natural gas. When oil prices
decline, these interruptible customers convert to oil to satisfy their fuel
requirements. Lower levels in interruptible sales occur when oil prices are
lower relative to the price of natural gas. Oil prices, as well as the prices of
electricity and other fuels are subject to fluctuation for a variety of reasons;
therefore, future competitive conditions are not predictable. To address this
uncertainty, the Company uses flexible pricing arrangements on both the supply
and sales side of its business to maximize sales volumes. As a result of the
transmission business' conversion to open access, this business has shifted from
providing competitive sales service to providing transportation and contract
storage services.
The Company's natural gas distribution operations located in Maryland, Delaware
and Florida offer transportation services to certain industrial customers. In
2001, the Florida operation extended transportation service to commercial
customers and, in 2002, to residential customers. With transportation service
now available on the Company's distribution systems, the Company is competing
with third party suppliers to sell gas to industrial customers. The Company's
competitors include the interstate transmission company if the distribution
customer is located close enough to the transmission company's pipeline to make
a connection economically feasible. The customers at risk are usually large
volume commercial and industrial customers with the financial resources and
capability to bypass the distribution operations in this manner. In certain
situations, the distribution operations may adjust services and rates for these
customers to retain their business. The Company expects to continue to expand
the availability of transportation service to additional classes of distribution
customers in the future. The Company established a natural gas sales and supply
operation in Florida in 1994 to compete for customers eligible for
transportation services.
The Company's propane distribution operations compete with several other propane
distributors in their service territories, primarily on the basis of service and
price. 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 services segment faces 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
See Note A to the Consolidated Financial Statements for information on recent
accounting and authoritative pronouncements.
CAUTIONARY STATEMENT
Chesapeake has made statements in this report that are considered to be
forward-looking statements. These statements are not matters of historical fact.
Sometimes they contain words such as "believes," "expects," "intends," "plans,"
"will," or "may," and other similar words of a predictive nature. These
statements relate to matters such as customer growth, changes in revenues or
margins, capital expenditures, environmental remediation costs, regulatory
approvals, market risks associated with the Company's propane marketing
operation, competition and other matters. It is important to understand that
these forward-looking statements are not guarantees but are subject to certain
risks and uncertainties and other important factors that could cause actual
results to differ materially from those in the forward-looking statements. These
factors include, among other things:
o the temperature sensitivity of the natural gas and propane businesses;
o the effect of spot and futures market prices of natural gas and propane on
the Company's distribution, wholesale marketing and energy trading
businesses;
o the effects of competition on the Company's unregulated and regulated
businesses;
o the effect of changes in federal, state or local regulatory and tax
requirements, including deregulation;
o the ability of the Company's new and planned facilities and acquisitions to
generate expected revenues; and
o the Company's ability to obtain the rate relief and cost recovery requested
from utility regulators and the timing of the requested regulatory actions.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information concerning quantitative and qualitative disclosure about market risk
is included in Item 7 under the heading "Management's Discussion and Analysis -
Market Risk."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
REPORT OF INDEPENDENT ACCOUNTANTS
________
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, 2002 and 2001, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2002 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.
These 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
accounting standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Note F to the Consolidated Financial Statements, the Company
adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets," in 2002.
/S/PRICEWATERHOUSECOOPERS LLP
- -----------------------------
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 20, 2003
CONSOLIDATED STATEMENTS OF INCOME
- ----------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . $142,229,535 $159,512,240 $150,785,986
COST OF SALES . . . . . . . . . . . . . . . . . . . . . . . . 74,153,193 95,546,560 90,201,513
- ----------------------------------------------------------------------------------------------------------
GROSS MARGIN. . . . . . . . . . . . . . . . . . . . . . . . . 68,076,342 63,965,680 60,584,473
- ----------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations. . . . . . . . . . . . . . . . . . . . . . . . 36,881,267 34,055,855 31,862,975
Maintenance . . . . . . . . . . . . . . . . . . . . . . . 1,969,562 1,778,760 1,868,260
Depreciation and amortization . . . . . . . . . . . . . . 9,311,483 8,333,482 7,142,611
Goodwill impairment . . . . . . . . . . . . . . . . . . . 1,474,000 0 0
Other taxes . . . . . . . . . . . . . . . . . . . . . . . 4,607,660 4,251,825 3,684,656
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 3,462,692 4,027,543 4,387,925
- ----------------------------------------------------------------------------------------------------------
Total operating expenses. . . . . . . . . . . . . . . . . . 57,706,664 52,447,465 48,946,427
- ----------------------------------------------------------------------------------------------------------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . 10,369,678 11,518,215 11,638,046
- ----------------------------------------------------------------------------------------------------------
OTHER INCOME
Interest income . . . . . . . . . . . . . . . . . . . . . 238,233 456,240 220,462
Other income. . . . . . . . . . . . . . . . . . . . . . . 282,743 251,491 248,748
Income taxes. . . . . . . . . . . . . . . . . . . . . . . (187,462) (224,731) (108,667)
- ----------------------------------------------------------------------------------------------------------
Total other income. . . . . . . . . . . . . . . . . . . . . 333,514 483,000 360,543
- ----------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . . . . 10,703,192 12,001,215 11,998,589
- ----------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt. . . . . . . . . . . . . . . . 4,103,189 3,998,264 2,628,781
Interest on short-term borrowing. . . . . . . . . . . . . 698,578 1,215,528 1,699,402
Amortization of debt expense. . . . . . . . . . . . . . . 89,387 101,183 111,122
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 166,885 (35,297) 70,083
- ----------------------------------------------------------------------------------------------------------
Total interest charges. . . . . . . . . . . . . . . . . . . 5,058,039 5,279,678 4,509,388
- ----------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Change in Accounting Principle. . . . . . . . . . . . . . . 5,645,153 6,721,537 7,489,201
Cumulative Effect of Change in Accounting
Principle, net of tax . . . . . . . . . . . . . . . . . . . (1,916,000) 0 0
- ----------------------------------------------------------------------------------------------------------
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,729,153 $ 6,721,537 $ 7,489,201
==========================================================================================================
EARNINGS PER SHARE OF COMMON STOCK:
Basic
Before efffect of change in accounting principle. . . . . $ 1.03 $ 1.25 $ 1.43
Effect of change in accounting principle. . . . . . . . . (0.35) 0.00 0.00
- ----------------------------------------------------------------------------------------------------------
Net Income. . . . . . . . . . . . . . . . . . . . . . . . . $ 0.68 $ 1.25 $ 1.43
==========================================================================================================
Diluted
Before efffect of change in accounting principle. . . . . $ 1.03 $ 1.24 $ 1.40
Effect of change in accounting principle. . . . . . . . . (0.35) 0.00 0.00
- ----------------------------------------------------------------------------------------------------------
Net Income. . . . . . . . . . . . . . . . . . . . . . . . . $ 0.68 $ 1.24 $ 1.40
==========================================================================================================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEETS
ASSETS
- -------------------------------------------------------------------------------------------
AT DECEMBER 31, 2002 2001
- -------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Natural gas distribution and transmission. . . . . . . . . $179,487,574 $168,436,347
Propane. . . . . . . . . . . . . . . . . . . . . . . . . . 34,479,798 34,695,862
Advanced information services. . . . . . . . . . . . . . . 1,475,060 1,521,144
Water services . . . . . . . . . . . . . . . . . . . . . . 4,619,703 3,344,751
Other plant. . . . . . . . . . . . . . . . . . . . . . . . 9,065,440 8,904,691
- -------------------------------------------------------------------------------------------
Total property, plant and equipment. . . . . . . . . . . . . 229,127,575 216,902,795
Less: Accumulated depreciation and amortization . . . . . . (74,348,909) (66,646,944)
- -------------------------------------------------------------------------------------------
Net property, plant and equipment. . . . . . . . . . . . . . 154,778,666 150,255,851
- -------------------------------------------------------------------------------------------
INVESTMENTS. . . . . . . . . . . . . . . . . . . . . . . . . 362,855 517,901
- -------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . . . . . . 2,458,276 1,188,335
Accounts receivable (less allowance for uncollectibles
of $659,628 and $621,516, respectively) . . . . . . . . 24,045,853 21,266,309
Materials and supplies, at average cost. . . . . . . . . . 995,165 1,106,995
Merchandise inventory, at FIFO . . . . . . . . . . . . . . 1,193,585 1,610,786
Propane inventory, at average cost . . . . . . . . . . . . 4,028,878 2,518,871
Storage gas prepayments. . . . . . . . . . . . . . . . . . 3,033,772 4,326,416
Underrecovered purchased gas costs . . . . . . . . . . . . 2,968,931 6,519,754
Income taxes receivable. . . . . . . . . . . . . . . . . . 488,339 675,504
Deferred income taxes receivable . . . . . . . . . . . . . 417,665 0
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . 2,833,314 1,932,245
Other current assets . . . . . . . . . . . . . . . . . . . 755,683 276,781
- -------------------------------------------------------------------------------------------
Total current assets . . . . . . . . . . . . . . . . . . . . 43,219,461 41,421,996
- -------------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Environmental regulatory assets. . . . . . . . . . . . . . 2,527,251 2,677,010
Environmental expenditures . . . . . . . . . . . . . . . . 2,557,406 3,189,156
Goodwill, net. . . . . . . . . . . . . . . . . . . . . . . 869,519 5,543,519
Other intangible assets, net . . . . . . . . . . . . . . . 1,927,622 2,180,764
Other deferred charges . . . . . . . . . . . . . . . . . . 4,701,394 4,548,829
- -------------------------------------------------------------------------------------------
Total deferred charges and other assets. . . . . . . . . . . 12,583,192 18,139,278
- -------------------------------------------------------------------------------------------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . $210,944,174 $210,335,026
===========================================================================================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
- -------------------------------------------------------------------------------------------
AT DECEMBER 31, 2002 2001
- -------------------------------------------------------------------------------------------
CAPITALIZATION
Stockholders' equity
Common Stock, par value $.4867 per share;
(authorized 12,000,000 shares; issued and
outstanding 5,537,710 and 5,424,962 shares,
for 2002 and 2001, respectively) . . . . . . . . . . . . $ 2,694,935 $ 2,640,060
Additional paid-in capital . . . . . . . . . . . . . . . . 31,756,983 29,653,992
Retained earnings. . . . . . . . . . . . . . . . . . . . . 32,238,510 34,555,560
- -------------------------------------------------------------------------------------------
Total stockholders' equity . . . . . . . . . . . . . . . . . 66,690,428 66,849,612
Long-term debt, net of current maturities. . . . . . . . . . 73,407,684 48,408,596
- -------------------------------------------------------------------------------------------
Total capitalization . . . . . . . . . . . . . . . . . . . . 140,098,112 115,258,208
- -------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt. . . . . . . . . . . . . 3,938,006 2,686,145
Short-term borrowing . . . . . . . . . . . . . . . . . . . 10,900,000 42,100,000
Accounts payable . . . . . . . . . . . . . . . . . . . . . 21,141,996 14,551,621
Refunds payable to customers . . . . . . . . . . . . . . . 497,842 971,575
Customer deposits. . . . . . . . . . . . . . . . . . . . . 2,007,983 1,730,354
Accrued interest . . . . . . . . . . . . . . . . . . . . . 699,831 1,758,401
Dividends payable. . . . . . . . . . . . . . . . . . . . . 1,521,982 1,491,832
Deferred income taxes payable. . . . . . . . . . . . . . . 0 848,271
Accrued compensation . . . . . . . . . . . . . . . . . . . 1,777,544 1,867,743
Other accrued liabilities. . . . . . . . . . . . . . . . . 2,052,442 2,006,140
- -------------------------------------------------------------------------------------------
Total current liabilities. . . . . . . . . . . . . . . . . . 44,537,626 70,012,082
- -------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes. . . . . . . . . . . . . . . . . . . 17,263,501 15,732,842
Deferred income tax credits. . . . . . . . . . . . . . . . 547,541 602,357
Environmental liability. . . . . . . . . . . . . . . . . . 2,802,424 3,199,733
Accrued pension costs. . . . . . . . . . . . . . . . . . . 1,619,456 1,595,650
Other liabilities. . . . . . . . . . . . . . . . . . . . . 4,075,514 3,934,154
- -------------------------------------------------------------------------------------------
Total deferred credits and other liabilities . . . . . . . . 26,308,436 25,064,736
- -------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTES M AND N)
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . . . . $210,944,174 $210,335,026
===========================================================================================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income. . . . . . . . . . . . . . . . . . . . . . . . . $ 3,729,153 $ 6,721,537 $ 7,489,201
Adjustments to reconcile net income to net operating cash:
Goodwill impairment . . . . . . . . . . . . . . . . . . . 4,674,000 0 0
Depreciation and amortization . . . . . . . . . . . . . . 9,311,483 8,333,482 7,142,611
Depreciation included in other costs. . . . . . . . . . . 1,111,662 659,576 789,516
Deferred income taxes, net. . . . . . . . . . . . . . . . 264,723 508,813 2,922,815
Mark-to-market adjustments. . . . . . . . . . . . . . . . (704,906) 906,551 (689,032)
Employee benefits and compensation. . . . . . . . . . . . 188,616 193,777 297,165
Other, net. . . . . . . . . . . . . . . . . . . . . . . . 34,570 18,298 (759,742)
Changes in assets and liabilities:
Accounts receivable, net. . . . . . . . . . . . . . . . . (2,779,544) 16,549,829 (16,745,492)
Inventories, storage gas and materials. . . . . . . . . . 311,668 1,117,052 (3,307,421)
Prepaid expenses and other current assets . . . . . . . . (196,163) 83,031 217,126
Other deferred charges. . . . . . . . . . . . . . . . . . (347,671) (1,725,090) 95,657
Accounts payable, net . . . . . . . . . . . . . . . . . . 6,590,375 (19,103,097) 16,789,600
Refunds payable to customers. . . . . . . . . . . . . . . (473,733) (43,553) 235,620
Accrued income taxes. . . . . . . . . . . . . . . . . . . 187,165 484,257 (1,085,989)
Accrued interest. . . . . . . . . . . . . . . . . . . . . (1,058,570) 1,163,226 13,526
Over (under) recovered purchased gas costs. . . . . . . . 3,550,823 828,533 (6,111,373)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . (4,550) (1,245,624) 1,072,842
- ----------------------------------------------------------------------------------------------------------
Net cash provided by operating activities . . . . . . . . . . 24,389,101 15,450,598 8,366,630
- ----------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant and equipment expenditures, net . . . . . . (14,705,244) (27,414,426) (21,150,059)
Purchase of intangibles . . . . . . . . . . . . . . . . . . 12,427 (2,208,700) (619,359)
Environmental recoveries, net of expenditures . . . . . . . 631,750 437,319 (51,587)
- ----------------------------------------------------------------------------------------------------------
Net cash used by investing activities . . . . . . . . . . . . (14,061,067) (29,185,807) (21,821,005)
- ----------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Common stock dividends, net of amounts
reinvested of $693,583, $609,793 & $520,712
in 2002, 2001 & 2000, respectively. . . . . . . . . . . . (5,322,195) (5,216,044) (5,022,313)
Issuance of stock:
Dividend Reinvestment Plan optional cash. . . . . . . . . 266,638 191,765 197,797
Retirement Savings Plan . . . . . . . . . . . . . . . . . 1,011,515 1,023,919 916,159
Net (repayments) borrowing under line of credit agreements. (31,200,000) 16,700,000 2,400,000
Proceeds from issuance of long-term debt. . . . . . . . . . 29,918,850 300,000 19,887,194
Repayment of long-term debt . . . . . . . . . . . . . . . . (3,732,901) (2,682,412) (2,675,319)
- ----------------------------------------------------------------------------------------------------------
Net cash (used) provided by financing activities. . . . . . . (9,058,093) 10,317,228 15,703,518
- ----------------------------------------------------------------------------------------------------------
NET INCRASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . 1,269,941 (3,417,981) 2,249,143
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . . . . 1,188,335 4,606,316 2,357,173
- ----------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . . . . $ 2,458,276 $ 1,188,335 $ 4,606,316
==========================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest. . . . . . . . . . . . . . . . . . . $ 6,255,193 $ 4,128,477 $ 4,410,230
Cash paid for income taxes. . . . . . . . . . . . . . . . . $ 2,160,750 $ 3,601,400 $ 3,212,080
- ----------------------------------------------------------------------------------------------------------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- ----------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------
COMMON STOCK
Balance - beginning of year . . . . . . . . . . . . . . . . $ 2,640,060 $ 2,577,992 $ 2,524,018
Dividend Reinvestment Plan. . . . . . . . . . . . . . . . 24,229 20,977 19,983
Retirement Savings Plan . . . . . . . . . . . . . . . . . 25,669 26,730 25,353
Conversion of debentures. . . . . . . . . . . . . . . . . 2,199 3,117 5,173
Performance shares and options exercised. . . . . . . . . 2,778 11,244 3,465
- ----------------------------------------------------------------------------------------------------------
Balance - end of year . . . . . . . . . . . . . . . . . . . 2,694,935 2,640,060 2,577,992
- ----------------------------------------------------------------------------------------------------------
ADDITIONAL PAID-IN CAPITAL
Balance - beginning of year . . . . . . . . . . . . . . . . 29,653,992 27,672,005 25,782,824
Dividend Reinvestment Plan. . . . . . . . . . . . . . . . 936,268 780,582 698,526
Retirement Savings Plan . . . . . . . . . . . . . . . . . 985,846 997,187 890,806
Conversion of debentures. . . . . . . . . . . . . . . . . 74,632 105,639 175,599
Performance shares and options exercised. . . . . . . . . 106,245 98,579 124,250
- ----------------------------------------------------------------------------------------------------------
Balance - end of year . . . . . . . . . . . . . . . . . . . 31,756,983 29,653,992 27,672,005
- ----------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance - beginning of year . . . . . . . . . . . . . . . . 34,555,560 33,721,747 31,857,732
Net income. . . . . . . . . . . . . . . . . . . . . . . . 3,729,153 6,721,537 7,489,201
Cash dividends (1). . . . . . . . . . . . . . . . . . . . (6,046,203) (5,887,724) (5,625,186)
- ----------------------------------------------------------------------------------------------------------
Balance - end of year . . . . . . . . . . . . . . . . . . . 32,238,510 34,555,560 33,721,747
- ----------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY. . . . . . . . . . . . . . . . . . $ 66,690,428 $ 66,849,612 $ 63,971,744
==========================================================================================================
<FN>
(1) Cash dividends declared per share for 2002, 2001 and 2000 were
$1.10, $1.10, and $1.07, respectively.
</FN>
- ----------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------
COMMON STOCK SHARES ISSUED AND OUTSTANDING (2)
Balance - beginning of year . . . . . . . . . . . . . . . . 5,424,962 5,297,443 5,186,546
Dividend Reinvestment Plan (3). . . . . . . . . . . . . . 49,782 43,101 41,056
Sale of stock to the Company's Retirement Savings Plan. . 52,740 54,921 52,093
Conversion of debentures. . . . . . . . . . . . . . . . . 4,518 6,395 10,628
Performance shares and options exercised. . . . . . . . . 5,708 23,102 7,120
- ----------------------------------------------------------------------------------------------------------
Balance - end of year (4) . . . . . . . . . . . . . . . . . 5,537,710 5,424,962 5,297,443
==========================================================================================================
<FN>
(2) 12,000,000 shares are authorized at a par value of $0.4867 per share.
(3) Includes dividends reinvested and optional cash payments.
(4) The Company had 37,353, 30,446, and 7,442 shares held in Rabbi Trusts
at December 31, 2002, 2001 and 2000, respectively.
</FN>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF INCOME TAXES
- ----------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------
CURRENT INCOME TAX EXPENSE
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,628,267 $ 3,194,125 $ 1,598,184
State . . . . . . . . . . . . . . . . . . . . . . . . . . . 572,545 602,548 264,294
Investment tax credit adjustments, net. . . . . . . . . . . (54,816) (54,815) (54,815)
- ----------------------------------------------------------------------------------------------------------
Total current income tax expense. . . . . . . . . . . . . . . 2,145,996 3,741,858 1,807,663
- ----------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAX EXPENSE (1)
Property, plant and equipment . . . . . . . . . . . . . . . 3,742,415 769,264 1,071,852
Deferred gas costs. . . . . . . . . . . . . . . . . . . . . (1,678,946) (236,971) 2,404,994
Pensions and other employee benefits. . . . . . . . . . . . (139,861) (71,089) (115,615)
Unbilled revenue. . . . . . . . . . . . . . . . . . . . . . (67,231) 303,136 (736,700)
Goodwill impairment . . . . . . . . . . . . . . . . . . . . (1,785,160) 0 0
Environmental expenditures. . . . . . . . . . . . . . . . . (404,659) (142,362) 879
Other (2) . . . . . . . . . . . . . . . . . . . . . . . . . 553,600 (111,562) 63,519
- ----------------------------------------------------------------------------------------------------------
Total deferred income tax expense . . . . . . . . . . . . . . 220,158 510,416 2,688,929
- ----------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE. . . . . . . . . . . . . . . . . . . $ 2,366,154 $ 4,252,274 $ 4,496,592
==========================================================================================================
RECONCILIATION OF EFFECTIVE INCOME TAX RATES
Federal income tax expense (2). . . . . . . . . . . . . . . $ 2,072,404 $ 3,840,832 $ 4,075,170
State income taxes, net of federal benefit. . . . . . . . . 583,564 492,850 489,831
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . (289,814) (81,408) (68,409)
- ----------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE. . . . . . . . . . . . . . . . . . . $ 2,366,154 $ 4,252,274 $ 4,496,592
==========================================================================================================
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . . 38.8% 38.7% 37.5%
- -------------------------------------------------------------------------------------------
AT DECEMBER 31, 2002 2001
- -------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES
DEFERRED INCOME TAX LIABILITIES:
Property, plant and equipment . . . . . . . . . . . . . . $ 19,568,426 $ 15,730,682
Environmental costs . . . . . . . . . . . . . . . . . . . 881,567 1,286,226
Deferred gas costs. . . . . . . . . . . . . . . . . . . . 960,321 2,607,170
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1,307,081 935,104
- -------------------------------------------------------------------------------------------
Total deferred income tax liabilities . . . . . . . . . . . 22,717,395 20,559,182
- -------------------------------------------------------------------------------------------
DEFERRED INCOME TAX ASSETS:
Unbilled revenue. . . . . . . . . . . . . . . . . . . . . 1,554,659 1,487,428
Pension and other employee benefits . . . . . . . . . . . 1,505,008 1,464,878
Goodwill impairment . . . . . . . . . . . . . . . . . . . 1,785,160 0
Self insurance. . . . . . . . . . . . . . . . . . . . . . 547,349 535,141
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 479,383 490,622
- -------------------------------------------------------------------------------------------
Total deferred income tax assets. . . . . . . . . . . . . . 5,871,559 3,978,069
- -------------------------------------------------------------------------------------------
Deferred Income Taxes Per Consolidated Balance Sheet. . . . . $ 16,845,836 $ 16,581,113
===========================================================================================
<FN>
(1) Includes $107,000, $102,000 and $298,000 of deferred state income
taxes for the years 2002, 2001 and 2000, respectively.
(2) Federal income taxes for the years 2002 and 2000 were recorded at
34%. The year 2001 was recorded at 35%.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
</FN>
A. SUMMARY OF ACCOUNTING POLICIES
NATURE OF BUSINESS
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is engaged in
natural gas distribution to approximately 45,100 customers located in central
and southern Delaware, Maryland's Eastern Shore and Florida. The Company's
natural gas transmission subsidiary operates a pipeline from various points in
Pennsylvania and northern Delaware to the Company's Delaware and Maryland
distribution divisions, as well as other utility and industrial customers in
Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company's propane
distribution and wholesale marketing segment provides distribution service to
approximately 34,600 customers in central and southern Delaware, the Eastern
Shore of Maryland, Florida and Virginia, and markets propane to a number of
large independent oil and petrochemical companies, resellers and propane
distribution companies in the southeastern United States. The advanced
information services segment provides consulting, custom programming, training,
development tools and website development for national and international
clients. The water services segment provides water conditioning and treatment
products and services and bottled water.
PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements include the accounts of the Company and
its wholly owned subsidiaries. The Company does not have any ownership interests
in investments accounted for using the equity method or in any 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 PSCs with
respect to their rates for service, maintenance of their accounting records and
various other matters. Eastern Shore Natural Gas Company is an open access
pipeline and is subject to regulation by the Federal Energy Regulatory
Commission. The Company's financial statements are prepared in accordance with
generally accepted accounting principles, which give appropriate recognition to
the ratemaking and accounting practices and policies of the various commissions.
The propane distribution and marketing, advanced information services and water
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 remaining useful
life of the asset. Depreciation and amortization expenses are provided at an
annual rate for each segment. Average rates for the past three years were 4
percent for natural gas distribution and transmission, 6 percent for propane
distribution and marketing, 16 percent for advanced information services, 15
percent for water 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 propane and materials and
supplies inventory. The appliance inventory is valued at first-in first-out
("FIFO"). If the market prices drop below cost, inventory balances are adjusted
to market values.
ENVIRONMENTAL REGULATORY ASSETS, LIABILITIES AND EXPENDITURES
Environmental regulatory assets represent amounts related to environmental
liabilities for which cash expenditures have not been made. As expenditures are
incurred, the environmental liability is reduced along with the environmental
regulatory asset. These amounts, awaiting ratemaking treatment, are recorded to
either environmental expenditures as an asset or accumulated depreciation as
cost of removal. Environmental expenditures are amortized and/or recovered
through a rider to base rates in accordance with the ratemaking treatment
granted in each jurisdiction.
GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill and other intangible assets are associated with the acquisition of
non-utility companies. In accordance with SFAS No. 142, goodwill is not
amortized, but is tested for impairment on an annual basis. Other intangible
assets are amortized on a straight-line basis over their estimated economic
useful lives.
OTHER DEFERRED CHARGES
Other deferred charges include discount, premium and issuance costs associated
with long-term debt and rate case expenses. Debt costs are deferred, then
amortized over the original lives of the respective debt issuances. 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.
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
income statement in the period of change. The resulting unrealized gains and
losses are recorded as assets or liabilities, respectively. At December 31,
2002, there was an unrealized gain of $630,000. At December 31, 2001, there was
an unrealized loss of $75,000. Trading liabilities are recorded in other accrued
liabilities. Trading assets are recorded in prepaid expenses and other current
assets.
The Company's natural gas and propane distribution operations have entered into
agreements with natural gas and propane suppliers to purchase gas for resale to
their customers. Purchases under these contracts are considered "normal
purchases and sales" under SFAS No. 133 and are not marked-to-market.
EARNINGS PER SHARE
The calculations of both basic and diluted earnings per share are presented
below. In 2002, the impact of assuming the conversion of debentures would have
been anti-dilutive; therefore, it was not included in the calculation.
Additionally, in both 2002 and 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, 2002 2001 2000
- --------------------------------------------------------------------------------------------
CALCULATION OF BASIC EARNINGS PER SHARE BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
Net income before cumulative effect of
change in accounting principle . . . . . . . . $5,645,153 $6,721,537 $7,489,201
Weighted average shares outstanding . . . . . . . 5,489,424 5,367,433 5,249,439
- --------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE . . . . . . $ 1.03 $ 1.25 $ 1.43
- --------------------------------------------------------------------------------------------
CALCULATION OF DILUTED EARNINGS PER SHARE BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
RECONCILIATION OF NUMERATOR:
Net income before cumulative effect of
change in accounting principle -- Basic. . . . $5,645,153 $6,721,537 $7,489,201
Effect of 8.25% Convertible debentures. . . . . . 0 171,725 179,701
- --------------------------------------------------------------------------------------------
Adjusted numerator -- Diluted. . . . . . . . . . . . $5,645,153 $6,893,262 $7,668,902
- --------------------------------------------------------------------------------------------
RECONCILIATION OF DENOMINATOR:
Weighted shares outstanding -- Basic. . . . . . . 5,489,424 5,367,433 5,249,439
Effect of dilutive securities
Stock options. . . . . . . . . . . . . . . . . 0 0 11,484
Warrants . . . . . . . . . . . . . . . . . . . 1,649 849 0
8.25% Convertible debentures . . . . . . . . . 0 201,125 209,893
- --------------------------------------------------------------------------------------------
Adjusted denominator -- Diluted . . . . . . . . . 5,491,073 5,569,407 5,470,816
- --------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE . . . . . . $ 1.03 $ 1.24 $ 1.40
============================================================================================
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.
However, the regulatory authorities have granted the Company's regulated natural
gas distribution operations the ability to negotiate rates with customers that
have competitive alternatives using approved methodologies. In addition, the
natural gas transmission operation can negotiate rates above or below the
FERC-approved tariff rates. With the exception of the Company's Florida
division, the Company recognizes revenues from meters read on a monthly cycle
basis. This practice results in unbilled and unrecorded revenue from the cycle
date through the end of the month. The Florida division recognizes revenues
based on services rendered and records an amount for gas delivered but not yet
billed.
Chesapeake's natural gas distribution operations each have a gas cost recovery
mechanism that provides for the adjustment of rates charged to customers as gas
costs fluctuate. These amounts are collected or refunded through adjustments to
rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution's industrial
interruptible customers to make them competitive with alternative types of fuel.
Based on pricing, these customers can choose natural gas or alternative types of
supply. Neither the Company nor the interruptible 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 records trading activity net, on a mark-to-market basis for open
contracts.
The advanced information services, water services and other segments record
revenue in the period the products are delivered and/or services are rendered.
CERTAIN RISKS AND UNCERTAINTIES
The financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates in measuring
assets and liabilities and related revenues and expenses (see Notes M and N to
the Consolidated Financial Statements for significant estimates). These
estimates involve judgments with respect to, among other things, various future
economic factors that are difficult to predict and are beyond the control of the
Company. Therefore, actual results could differ from those estimates.
The Company records certain assets and liabilities in accordance with SFAS No.
71. If the Company were required to terminate application of SFAS No. 71 for its
regulated operations, all such deferred amounts would be recognized in the
income statement at that time. This would result in a charge to earnings, net of
applicable income taxes, which could be material.
FASB STATEMENTS AND OTHER AUTHORITATIVE PRONOUNCEMENTS
During the third quarter, the Company implemented the provisions of a recent
consensus reached by the EITF of the FASB that reconsidered certain provisions
in EITF Issue No. 02-03 "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities." EITF 02-03 addresses the presentation of revenue
and expense associated with energy trading contracts on a gross versus net
basis. Previously, the EITF concluded that gross presentation was acceptable.
However, during deliberations held in June 2002, a consensus was reached that
net presentation should be required. This consensus also indicated that
implementation would be effective for the third quarter 2002 reporting cycle and
that prior periods should also be reclassified.
Under prior standards, the Company classified certain energy trading contracts
entered into by its propane wholesale marketing operations on a gross basis.
Recording the energy trading contracts on a net basis did not change the gross
margin, net income, earnings per share or the financial position of the Company.
For the years ended December 31, 2002 and 2001, both revenues and cost of sales
were reduced by $96.5 million and $170.8 million, respectively. As stated above,
there was no impact on gross margin, net income, earnings per share or the
financial position of the Company.
On June 30, 2001, the FASB issued SFAS Nos. 142 and 143. SFAS No. 142, "Goodwill
and Other Intangible Assets," eliminates the amortization of goodwill and other
acquired intangible assets with indefinite economic useful lives. The
pronouncement 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. This pronouncement was adopted in the first quarter of 2002. See
Note F to the Consolidated Financial Statements for a description of its impact
on the financial statements and additional disclosures required by the
pronouncement.
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides guidance
on the accounting for obligations associated with the retirement of long-lived
assets. The pronouncement 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 Company's initial review of the impact of adopting SFAS No. 143 has
been completed, and it is not expected to have a material impact on the
Company's income. The Company may be required to reclassify amounts representing
negative salvage value on its utility property out of accumulated depreciation
and establish a liability account.
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 was adopted in the first quarter of 2002, as
required. Its adoption did not have a material impact on the Company's financial
position or results of operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No.
4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. "SFAS No. 145 covers the reporting of gains and losses on
extinguishment of debt. This pronouncement is not expected to have a material
impact on the Company's financial position or results of operations.
The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities" in June 2002. It requires that a liability for a cost
associated with an exit or disposal activity be recognized when a liability is
incurred. Under previous guidelines, a liability for an exit cost was recognized
at the date of an entity's commitment to an exit plan. Adoption of this
pronouncement is not expected to impact the Company's financial position or
results of operations.
On October 25, 2002, the EITF rescinded Issue No. 98-10 ("EITF 98-10"),
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." The Company's interpretation of EITF 98-10 is consistent with the
current rules that are being applied under SFAS No. 133; therefore, management
does not believe that rescinding EITF 98-10 will impact its financial position
or results of operations.
The FASB also adopted SFAS No. 147, "Acquisitions of Certain Financial
Institutions," and SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure," in 2002. These pronouncements had no impact on the
Company's financial position or results of operations.
RESTATEMENT AND RECLASSIFICATION OF PRIOR YEARS' AMOUNTS
Certain prior years' amounts have been reclassified to conform to the current
year's presentation.
B. BUSINESS COMBINATIONS
During 2001, Chesapeake acquired Absolute Water Care, Inc., and selected assets
of Aquarius Systems, Inc., EcoWater Systems of Rochester, Intermountain Water,
Inc. and Blue Springs Water. In January 2000, Chesapeake acquired Carroll Water
Systems, Inc. These companies provide water treatment, water conditioning and
bottled water to customers in various geographic regions.
These acquisitions were all accounted for as purchases and the Company's
financial results include the results of operations from the dates of
acquisition.
C. SEGMENT INFORMATION
The following table presents information about the Company's reportable
segments.
- ----------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------
OPERATING REVENUES, UNAFFILIATED CUSTOMERS
Natural gas distribution and transmission. . . $ 93,455,546 $107,824,752 $ 99,616,794
Propane distribution and marketing . . . . . . 24,521,931 27,612,578 31,779,593
Advanced information services. . . . . . . . . 12,523,856 14,103,890 12,353,056
Water services . . . . . . . . . . . . . . . . 11,720,505 9,971,020 7,010,538
Other. . . . . . . . . . . . . . . . . . . . . 7,697 0 26,005
- ----------------------------------------------------------------------------------------------
Total operating revenues, unaffiliated customers. $142,229,535 $159,512,240 $150,785,986
- ----------------------------------------------------------------------------------------------
INTERSEGMENT REVENUES (1)
Natural gas distribution and transmission. . . $ 90,730 $ 112,006 $ 119,480
Advanced information services. . . . . . . . . 239,767 0 36,535
Water services . . . . . . . . . . . . . . . . 10,462 0 0
Other. . . . . . . . . . . . . . . . . . . . . 709,759 783,051 814,995
- ----------------------------------------------------------------------------------------------
Total intersegment revenues . . . . . . . . . . . $ 1,050,718 $ 895,057 $ 971,010
- ----------------------------------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES
Natural gas distribution and transmission. . . $ 14,986,857 $ 14,454,665 $ 12,548,996
Propane distribution and marketing . . . . . . 1,051,888 912,819 2,135,001
Advanced information services. . . . . . . . . 343,296 517,427 335,849
Water services . . . . . . . . . . . . . . . . (2,785,761) (724,557) 190,178
Other & eliminations . . . . . . . . . . . . . 236,090 385,404 815,947
- ----------------------------------------------------------------------------------------------
Total operating income before income taxes. . . . $ 13,832,370 $ 15,545,758 $ 16,025,971
- ----------------------------------------------------------------------------------------------
DEPRECIATION AND AMORTIZATION
Natural gas distribution and transmission. . . $ 6,428,683 $ 5,638,336 $ 5,236,008
Propane distribution and marketing . . . . . . 1,602,655 1,465,215 1,446,063
Advanced information services. . . . . . . . . 208,430 255,760 280,053
Water services . . . . . . . . . . . . . . . . 843,155 741,668 375,432
Other & eliminations . . . . . . . . . . . . . 228,560 232,503 (194,945)
- ----------------------------------------------------------------------------------------------
Total depreciation and amortization . . . . . . . $ 9,311,483 $ 8,333,482 $ 7,142,611
- ----------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Natural gas distribution and transmission. . . $ 12,116,993 $ 23,185,889 $ 17,355,382
Propane distribution and marketing . . . . . . 1,231,199 2,453,081 3,762,630
Advanced information services. . . . . . . . . 99,290 252,159 240,727
Water services . . . . . . . . . . . . . . . . 1,203,997 2,892,799 998,672
Other. . . . . . . . . . . . . . . . . . . . . 388,051 401,877 698,318
- ----------------------------------------------------------------------------------------------
Total capital expenditures. . . . . . . . . . . . $ 15,039,530 $ 29,185,805 $ 23,055,729
- ----------------------------------------------------------------------------------------------
<FN>
(1) All significant intersegment revenues are billed at market rates and have been
eliminated from consolidated revenues.
</FN>
- ----------------------------------------------------------------------------------------------
AT DECEMBER 31, . . . . . . . . . . . . . . . . . 2002 2001 2000
- ----------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Natural gas distribution and transmission. . . $153,609,232 $151,872,347 $139,985,168
Propane distribution and marketing . . . . . . 37,737,882 34,314,633 48,800,935
Advanced information services. . . . . . . . . 2,734,188 2,593,740 2,382,407
Water services . . . . . . . . . . . . . . . . 7,197,328 12,001,461 7,724,647
Other. . . . . . . . . . . . . . . . . . . . . 9,665,544 9,552,845 11,771,858
- ----------------------------------------------------------------------------------------------
Total identifiable assets . . . . . . . . . . . . $210,944,174 $210,335,026 $210,665,015
- ----------------------------------------------------------------------------------------------
Chesapeake uses the management approach to identify operating segments.
Chesapeake organizes its business around differences in products or services and
the operating results of each segment are regularly reviewed by the Company's
chief operating decision maker in order to make decisions about resources and to
assess performance. The segments are evaluated based on their pre-tax operating
income.
In 2002, water services began to be reported separately. Also in 2002, the
management of the customers served by the Company's underground piped propane
operations was transferred to the propane segment from the natural gas
distribution and transmission segment. Segment results for all periods shown
have been reclassified to reflect these changes.
D. FAIR VALUE OF FINANCIAL INSTRUMENTS
Various items within the balance sheet are considered to be financial
instruments because they are cash or are to be settled in cash. The carrying
values of these items generally approximate their fair value (see Note E to the
Consolidated Financial Statements for disclosure of fair value of investments).
The Company's open forward and futures contracts at December 31, 2002, and
December 31, 2001, had a net unrealized gain in fair value of $630,000 and a net
unrealized loss in fair value of $75,000, respectively, based on market rates.
The fair value of the Company's long-term debt is estimated using a discounted
cash flow methodology. The Company's long-term debt at December 31, 2002,
including current maturities, had an estimated fair value of $88.0 million as
compared to a carrying value of $77.3 million. At December 31, 2001, the
estimated fair value was approximately $56.9 million as compared to a carrying
value of $51.1 million. These estimates are based on published corporate
borrowing rates for debt instruments with similar terms and average maturities.
E. INVESTMENTS
The investment balances at December 31, 2002 and 2001, 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.
F. GOODWILL AND OTHER INTANGIBLE ASSETS
The Company adopted SFAS No. 142 in the first quarter of 2002. Application of
the non-amortization provisions resulted in $154,000 of additional income ($0.03
per share), after tax, for 2002 compared to 2001. The Company performed a test
as of January 1, 2002, for goodwill impairment using the two-step process
prescribed in SFAS No. 142. The first step was a screen for potential
impairment, using January 1, 2002, as the measurement date. The second step was
a measurement of the amount of the goodwill determined to be impaired. The
results of the tests indicated that the goodwill associated with the Company's
water business was impaired and that the amount of the impairment was $3.2
million. This was recorded as the cumulative effect of a change in accounting
principle. The fair value of the water business was determined using several
methods, including discounted cash flow projections and market valuations for
recent purchases and sales of similar businesses. These were weighted based on
their expected probability. The previous test for impairment of goodwill,
prescribed under SFAS No. 121, looked at undiscounted cash flows. The
determination that the goodwill associated with the Company's water business was
impaired was the result of the more stringent tests required by the new
pronouncement. SFAS No. 142 requires that impairment tests be performed
annually. At December 31, 2002, the test indicated an additional impairment
charge of $1.5 million was necessary. The unprofitable performance of the
Company's water services business was the primary cause of the impairment.
The change in the carrying value of goodwill for the year ended December 31,
2002, is as follows:
WATER
BUSINESSES PROPANE TOTAL
------------ ----------- ------------
Balance at January 1, 2002 . . . . . . . . . $ 4,869,068 $ 674,451 $ 5,543,519
Impairment charges . . . . . . . . . . . . . (4,674,000) 0 (4,674,000)
- --------------------------------------------------------------------------------------
Balance at December 31, 2002 . . . . . . . . $ 195,068 $ 674,451 $ 869,519
- --------------------------------------------------------------------------------------
The impact of the non-amortization provision of SFAS No. 142 was as follows:
BASIC DILUTED
NET EARNINGS EARNINGS
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2001 INCOME PER SHARE PER SHARE
- --------------------------------------------- ------------ ----------- ------------
Net Income . . . . . . . . . . . . . . . . . $ 6,721,537 $ 1.252 $ 1.238
Amortization of goodwill, after tax. . . . . 153,594 0.029 0.027
- --------------------------------------------------------------------------------------
Net Income, exclusive of amortization. . . . $ 6,875,131 $ 1.281 $ 1.265
- --------------------------------------------------------------------------------------
Intangible assets subject to amortization are as follows:
DECEMBER, 2002 DECEMBER 31, 2001
---------------------------- ----------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Amount Amortization
------------- ------------- ------------- -------------
Customer Lists . . . . $ 1,099,202 $ 191,838 $ 1,111,651 $ 82,141
Non-compete agreements 1,000,000 256,257 1,000,000 140,417
Acquisition costs. . . 379,400 102,885 379,541 87,870
- -----------------------------------------------------------------------------------
Total. . . . . . . . . $ 2,478,602 $ 550,980 $ 2,491,192 $ 310,428
- -----------------------------------------------------------------------------------
Amortization of intangible assets was $241,000 for 2002. For the year ended
December 31, 2001, amortization of intangibles, excluding goodwill, was
$132,000. The estimated annual amortization of intangibles for the next five
years is: $224,000 for 2003; $224,000 for 2004; $213,000 for 2005; $213,000 for
2006; and $213,000 for 2007.
G. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL
In 2000 and 2001, the Company entered into agreements with an investment banker
to assist in identifying acquisition candidates. Under the agreements, the
Company issued warrants to the investment banker to purchase 15,000 shares of
Company stock in 2001 at a price of $18.25 per share and 15,000 shares in 2000
at a price of $18.00. The warrants are exercisable during a seven-year period
after the date granted. The Company has recognized expenses of $47,500 related
to the warrants. No warrants have been exercised.
H. LONG-TERM DEBT
The outstanding long-term debt, net of current maturities, is as shown below.
- ------------------------------------------------------------------
AT DECEMBER 31, 2002 2001
- ------------------------------------------------------------------
First mortgage sinking fund bonds:
9.37% Series I, due December 15, 2004 $ 756,000 $ 1,512,000
Uncollateralized senior notes:
7.97% note, due February 1, 2008. . . 5,000,000 6,000,000
6.91% note, due October 1, 2010 . . . 6,363,636 7,272,727
6.85% note, due January 1, 2012 . . . 8,000,000 10,000,000
7.83% note, due January 1, 2015 . . . 20,000,000 20,000,000
6.64% note, due October 31, 2017. . . 30,000,000 0
Convertible debentures:
8.25% due March 1, 2014. . . . . . . 3,281,000 3,358,000
Other debt . . . . . . . . . . . . . . . 7,048 265,869
- ------------------------------------------------------------------
Total Long-Term Debt . . . . . . . . . . $73,407,684 $48,408,596
- ------------------------------------------------------------------
<FN>
Annual maturities of consolidated long-term debt for the next five
years are as follows: $3,938,006 for 2003; $3,672,138 for 2004;
$2,909,091 for 2005; $4,909,091 for 2006;and $7,636,364 for 2007.
</FN>
The Company completed the private placement of $30.0 million of long-term debt
due October 31, 2017, and drew down the funds on October 31, 2002. The debt has
a fixed interest rate of 6.64 percent. The funds were used to repay short-term
borrowing.
The convertible debentures may be converted, at the option of the holder, into
shares of the Company's common stock at a conversion price of $17.01 per share.
During 2002 and 2001, debentures totaling $77,000 and $109,000, respectively,
were converted to stock. The debentures are also redeemable for cash at the
option of the holder, subject to an annual non-cumulative maximum limitation of
$200,000. During 2001 debentures totaling $4,000 were redeemed for cash. None
were redeemed in 2002. At the Company's option, the debentures may be redeemed
at stated amounts.
Indentures to the long-term debt of the Company and its subsidiaries contain
various restrictions. The most stringent restrictions state that the Company
must maintain equity of at least 40 percent of total capitalization and the
times interest earned ratio must be at least 2.5.
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. SHORT-TERM BORROWING
As of December 31, 2002, the Board of Directors had authorized the Company to
borrow up to $35.0 million from various banks and trust companies under
short-term lines of credit. Prior to the issuance of the $30.0 million long-term
debt on October 31, 2002, the Company had authorization to borrow up to $55.0
million. As of December 31, 2002, the Company had four unsecured, short-term
bank lines of credit totaling $75.0 million, none of which required compensating
balances. Under these lines of credit, the Company had short-term debt
outstanding of $10.9 million and $42.1 million at December 31, 2002 and 2001,
respectively. The annual weighted average interest rates were 2.35 percent for
2002 and 4.43 percent for 2001.
J. LEASE OBLIGATIONS
The Company has entered several operating lease arrangements for office space at
various locations, equipment and pipeline facilities. Rent expense related to
these leases was $1.1 million, $827,000 and $652,000 for 2002, 2001 and 2000,
respectively. Future minimum payments under the Company's current lease
agreements are $854,000, $746,000, $586,000, $522,000 and $143,000 for the years
of 2003 through 2007, respectively; and $677,000 thereafter, totaling $3.5
million.
K. EMPLOYEE BENEFIT PLANS
PENSION PLAN
In December 1998, the Company restructured its employee benefit plans to be
competitive with those in similar industries. Chesapeake offered
participants of the defined benefit plan the option to remain in the plan
or receive a one-time payout and enroll in an enhanced retirement savings
plan. Chesapeake closed the defined benefit plan to new participants,
effective December 31, 1998. Benefits under the plan are based on each
participant's years of service and highest average compensation. The
Company's funding policy provides that payments to the trustee shall be
equal to the minimum funding requirements of the Employee Retirement Income
Security Act of 1974.
The following schedule sets forth the funded status of the pension plan at
December 31, 2002 and 2001:
- -------------------------------------------------------------------------------
AT DECEMBER 31, 2002 2001
- -------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation -- beginning of year . . . . $ 10,120,364 $ 8,826,534
Service cost . . . . . . . . . . . . . . . . 319,230 347,955
Interest cost. . . . . . . . . . . . . . . . 672,392 646,205
Change in discount rate. . . . . . . . . . . 372,918 659,629
Actuarial (gain) loss. . . . . . . . . . . . (307,100) 47,068
Benefits paid. . . . . . . . . . . . . . . . (395,814) (407,027)
- -------------------------------------------------------------------------------
Benefit obligation -- end of year . . . . . . . 10,781,990 10,120,364
- -------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -- beginning of year. 11,745,574 11,738,984
Actual return on plan assets . . . . . . . . (1,911,035) 413,617
Benefits paid. . . . . . . . . . . . . . . . (395,814) (407,027)
- -------------------------------------------------------------------------------
Fair value of plan assets -- end of year. . . . 9,438,725 11,745,574
- -------------------------------------------------------------------------------
FUNDED STATUS. . . . . . . . . . . . . . . . . . . (1,343,265) 1,625,210
UNRECOGNIZED TRANSITION OBLIGATION . . . . . . . . (50,955) (66,059)
UNRECOGNIZED PRIOR SERVICE COST. . . . . . . . . . (48,356) (53,055)
UNRECOGNIZED NET LOSS (GAIN) . . . . . . . . . . . 659,522 (2,413,816)
- -------------------------------------------------------------------------------
ACCRUED PENSION COST . . . . . . . . . . . . . . . ($783,054) ($907,720)
- -------------------------------------------------------------------------------
ASSUMPTIONS:
Discount rate . . . . . . . . . . . . . . . . . 6.75% 7.00%
Rate of compensation increase . . . . . . . . . 5.00% 4.75%
Expected return on plan assets. . . . . . . . . 8.50% 8.50%
- -------------------------------------------------------------------------------
Net periodic pension costs for the defined benefit pension plan for 2002,
2001 and 2000 include the components as shown below:
- --------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- --------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC PENSION COST:
Service cost. . . . . . . . . . . . . . . . . $ 319,230 $ 347,955 $ 354,031
Interest cost . . . . . . . . . . . . . . . . 672,392 646,205 605,185
Expected return on assets . . . . . . . . . . (980,915) (981,882) (859,245)
Amortization of:
Transition assets. . . . . . . . . . . . . (15,104) (15,104) (15,104)
Prior service cost . . . . . . . . . . . . (4,699) (4,699) (4,699)
Actuarial gain . . . . . . . . . . . . . . (115,570) (195,029) (141,533)
- --------------------------------------------------------------------------------------
NET PERIODIC PENSION BENEFIT . . . . . . . . . . ($124,666) ($202,554) ($61,365)
- --------------------------------------------------------------------------------------
The Company sponsors an unfunded executive excess benefit plan. The accrued
benefit obligation and accrued pension costs were $1.2 million and
$840,000, respectively, as of December 31, 2002, and $1.2 million and
$687,000, respectively, at December 31, 2001.
RETIREMENT SAVINGS PLAN
The Company sponsors a 401(k) Retirement Savings Plan, which provides
participants a mechanism for making contributions for retirement savings.
Each participant may make pre-tax contributions of up to 15 percent of
eligible base compensation, subject to Internal Revenue Service
limitations. For participants still covered by the defined benefit pension
plan, the Company makes a contribution matching 60 percent or 100 percent
of each participant's pre-tax contributions based on the participant's
years of service, not to exceed six percent of the participant's eligible
compensation for the plan year.
Effective January 1, 1999, the Company began offering an enhanced 401(k)
plan to all new employees, as well as existing employees that elected to no
longer participate in the defined benefit plan. The Company makes matching
contributions on a basis of up to six percent of each employee's pre-tax
compensation for the year. The match is between 100 percent and 200
percent, based on a combination of the employee's age and years of service.
The first 100 percent of the funds are matched with Chesapeake common
stock. The remaining match is invested in the Company's 401(k) plan
according to each employee's election options. On December 1, 2001, the
Company converted the 401(k) fund holding Chesapeake stock to an Employee
Stock Ownership Plan.
Effective, January 1, 1999, the Company began offering a non-qualified
supplemental employee retirement savings plan open to Company executives
over a specific income threshold. Participants receive a cash only matching
contribution percentage equivalent to their 401(k) match level. All
contributions and matched funds earn interest income monthly. This plan is
not funded externally.
The Company's contributions to the 401(k) plans totaled $1,409,000,
$1,352,000 and $1,231,000 for the years ended December 31, 2002, 2001 and
2000, respectively. As of December 31, 2002, there are 220,467 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 2002, 2001 and 2000 include the
following components:
- --------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- --------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC POST-RETIREMENT COST:
Service cost. . . . . . . . . . . . . . . . . $ 2,739 $ 887 $ 1,803
Interest cost . . . . . . . . . . . . . . . . 68,437 49,799 57,584
Amortization of:
Transition obligation. . . . . . . . . . . 27,859 27,859 27,859
Actuarial (gain) loss. . . . . . . . . . . 12,109 (1,717) 0
- --------------------------------------------------------------------------------------
Net periodic post-retirement cost. . . . . . . . 111,144 76,828 87,246
Amounts amortized. . . . . . . . . . . . . . . . - - 25,028
- --------------------------------------------------------------------------------------
TOTAL POST-RETIREMENT COST . . . . . . . . . . . $ 111,144 $ 76,828 $ 112,274
- --------------------------------------------------------------------------------------
The following schedule sets forth the status of the post-retirement health
care and life insurance plan:
- -------------------------------------------------------------------------------
AT DECEMBER 31, 2002 2001
- -------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation -- beginning of year . . . . $ 723,926 $ 832,535
Retirees . . . . . . . . . . . . . . . . . . 123,134 (58,485)
Fully-eligible active employees. . . . . . . 140,786 (24,453)
Other active . . . . . . . . . . . . . . . . 66,104 (25,671)
- -------------------------------------------------------------------------------
Benefit obligation -- end of year. . . . . . . . . $ 1,053,950 $ 723,926
- -------------------------------------------------------------------------------
FUNDED STATUS. . . . . . . . . . . . . . . . . . . ($1,053,950) ($723,926)
UNRECOGNIZED TRANSITION OBLIGATION . . . . . . . . 105,859 133,718
UNRECOGNIZED NET LOSS (GAIN) . . . . . . . . . . . 304,827 (73,737)
- -------------------------------------------------------------------------------
ACCRUED POST-RETIREMENT COST . . . . . . . . . . . ($643,264) ($663,945)
- -------------------------------------------------------------------------------
ASSUMPTIONS:
Discount rate . . . . . . . . . . . . . . . . . 6.75% 7.00%
- -------------------------------------------------------------------------------
The health care inflation rate for 2002 is assumed to be 12 percent for
medical and 16 percent for prescription drugs. These rates are projected to
gradually decrease to ultimate rates of 5 and 6 percent, respectively, by
the year 2009. A one percentage point increase in the health care inflation
rate from the assumed rate would increase the accumulated post-retirement
benefit obligation by approximately $114,000 as of January 1, 2003, and
would increase the aggregate of the service cost and interest cost
components of the net periodic post-retirement benefit cost for 2003 by
approximately $9,000. A one percentage point decrease in the health care
inflation rate from the assumed rate would decrease the accumulated
post-retirement benefit obligation by approximately $96,000 as of January
1, 2003, and would decrease the aggregate of the service cost and interest
cost components of the net periodic post-retirement benefit cost for 2003
by approximately $7,000.
L. 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 and the
individual's achievement of goals set annually for each executive.
The Company executed Stock Option Agreements for a three-year performance period
ending December 31, 2000, with certain executive officers. One-half of these
options became exercisable over time and the other half became exercisable if
certain performance targets 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 shares 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 $165,000, $123,000 and
$118,000 associated with these performance shares in 2002, 2001 and 2000,
respectively.
Changes in outstanding options were as shown on the chart below:
- ------------------------------------------------------------------------------------------------------------
2002 2001 2000
NUMBER OPTION NUMBER OPTION NUMBER OPTION
OF SHARES PRICE OF SHARES PRICE OF SHARES PRICE
- ------------------------------------------------------------------------------------------------------------
Balance - beginning of year. . . . 41,948 $20.50 110,093 $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 41,948 $20.50 110,093 $20.50
- ------------------------------------------------------------------------------------------------------------
Exercisable. . . . . . . . . . . . 41,948 $20.50 41,948 $20.50 110,093 $12.75-$20.50
- ------------------------------------------------------------------------------------------------------------
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. The assumptions used in calculating
the pro forma information were: dividend yield, 4.73 percent; expected
volatility, 15.53 percent; risk-free interest rate, 5.89 percent; and an
expected life of four years. No options have been granted since 1997; therefore,
there is no pro forma impact for 2002 or 2001. The weighted average exercise
price of outstanding options was $20.50, $20.50 and $15.70 at December 31, 2002,
2001 and 2000, respectively. The options outstanding at December 31, 2002,
expire on December 31, 2005. As of December 31, 2002, there were 336,241 shares
reserved for issuance under the terms of the Company's Performance Incentive
Plan.
M. 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. The
Company is currently in discussions with the Maryland Department of the
Environment ("MDE") regarding a fourth site in Cambridge, Maryland.
In May 2001, Chesapeake, General Public Utilities Corporation, Inc. (now First
Energy), 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
terms of the final agreement have been memorialized in two consent decrees and
have been approved by all parties. The consent decrees have been presented to
the Department of Justice to its highest level of management for final approval.
The consent decrees will then be published for public comment and submitted to a
federal judge for final approval.
If the agreement receives final approval, Chesapeake will:
o 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.
o 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 the EPA is
received that indicates the remedial action related to the former
manufactured gas plant is not sufficiently protective. These contingencies
are standard, and are required by the United States in all liability
settlements.
At December 31, 2002, 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.
Through December 31, 2002, the Company has incurred approximately $9.2 million
in costs relating to environmental testing and remedial action studies at the
Dover site. Approximately $6.9 million has been recovered through December 2002
from other parties or through rates.
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.
The second site is the Salisbury Town Gas Light site in Salisbury, Maryland. In
cooperation with the MDE, the Company performed remediation that included 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 remedial 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.
The Company has adjusted the liability with respect to the Salisbury site to
$21,000 at December 31, 2002. The Company had previously accrued $100,000 as of
December 31, 2001. This amount is based on the estimated costs to perform
limited product monitoring and recovery efforts and fulfill ongoing reporting
requirements. A corresponding regulatory asset has been recorded, reflecting the
Company's belief that costs incurred will be recoverable in base rates.
Through December 31, 2002, the Company has incurred approximately $2.9 million
for remedial actions and environmental studies at the Maryland site. Of this
amount, approximately $1.8 million has been recovered through insurance proceeds
or ratemaking treatment. The Company will apply for the recovery of these and
any future costs in the next base rate filing with the Maryland Public Service
Commission.
The third site is located in the state of Florida. 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 remaining costs to complete the RAP is $681,000
(discounted). Accordingly, at December 31, 2002, the Company accrued a liability
of $681,000. Through December 31, 2002, the Company has incurred approximately
$319,000 of environmental costs associated with the Florida site. A regulatory
asset of $406,000 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.
In August 2002, the Company along with two other parties met with MDE to discuss
alleged manufactured gas plant contamination at a property located in Cambridge,
Maryland. At that meeting, one of the other parties agreed to perform a remedial
investigation of the site. The possible exposure of the Company at this site
cannot be determined at this time.
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.
N. OTHER COMMITMENTS AND CONTINGENCIES
NATURAL GAS AND PROPANE SUPPLY
The Company's natural gas and propane distribution operations have entered
into contractual commitments for gas from various suppliers. The contracts
have various expiration dates. In 2000, the Company entered into a
long-term contract with an energy marketing and risk management company to
manage a portion of the Company's natural gas transportation and storage
capacity. That contract expires on October 31, 2003.
CORPORATE GUARANTEES
The Company has issued corporate guarantees to certain vendors of its
propane wholesale marketing subsidiary. The guarantees at December 31,
2002, totaled $4.5 million and expire on various dates in 2003.
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.
O. QUARTERLY FINANCIAL DATA (UNAUDITED)
In the opinion of the Company, the quarterly financial information shown below
includes all adjustments necessary for a fair presentation of the operations for
such periods. Due to the seasonal nature of the Company's business, there are
substantial variations in operations reported on a quarterly basis. Due to the
adoption of EITF Issue No. 02-03 in the third quarter of 2002, which required
reclassification of prior periods, the amounts presented below do not agree to
amounts reported in prior Form 10-Q reports.
- ----------------------------------------------------------------------------------------------
FOR THE QUARTERS ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
- ----------------------------------------------------------------------------------------------
2002
Operating Revenue. . . . . . . . . . . $45,937,941 $31,661,191 $ 23,528,465 $ 41,101,938
Gross Margin . . . . . . . . . . . . . 22,339,889 14,526,398 12,331,845 18,878,210
Operating Income . . . . . . . . . . . 5,906,924 1,701,808 198,372 2,562,574
Before Change in Accounting Principle
Net Income (Loss). . . . . . . . . . 4,883,478 529,694 (939,165) 1,171,146
Earnings per share:
Basic. . . . . . . . . . . . . . . $ 0.90 $ 0.10 ($0.17) $ 0.21
Diluted. . . . . . . . . . . . . . $ 0.87 $ 0.10 ($0.17) $ 0.21
After Change in Accounting Principle
Net Income . . . . . . . . . . . . . 2,967,478 529,694 (939,165) 1,171,146
Earnings per share:
Basic. . . . . . . . . . . . . . . $ 0.55 $ 0.10 ($0.17) $ 0.21
Diluted. . . . . . . . . . . . . . $ 0.53 $ 0.10 ($0.17) $ 0.21
- ----------------------------------------------------------------------------------------------
2001
Operating Revenue. . . . . . . . . . . $65,593,008 $36,990,529 $ 24,794,008 $ 32,134,695
Gross Margin . . . . . . . . . . . . . 23,156,863 13,811,322 11,755,652 15,241,843
Operating Income . . . . . . . . . . . 6,666,331 1,741,229 562,419 2,548,236
Net Income (Loss). . . . . . . . . . . 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
- ----------------------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information pertaining to the Directors of the Company is incorporated herein by
reference to the Proxy Statement, under "Information Regarding the Board of
Directors and Nominees" and Section 16(a) Beneficial Ownership Reporting
Compliance" to be filed not later than April 30, 2003 in connection with the
Company's Annual Meeting to be held on May 20, 2003.
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,
2003, in connection with the Company's Annual Meeting to be held on May 20,
2003.
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, 2003 in connection with the Company's Annual
Meeting to be held on May 20, 2003.
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,
2003, in connection with the Company's Annual Meeting to be held on May 20,
2003.
PART IV
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:
o Accountants' Report dated February 20, 2003 of
PricewaterhouseCoopers LLP, Independent Accountants
o Consolidated Statements of Income for each of the three years
ended December 31, 2002, 2001 and 2000
o Consolidated Balance Sheets at December 31, 2002 and December 31,
2001
o Consolidated Statements of Cash Flows for each of the three years
ended December 31, 2002, 2001 and 2000
o Consolidated Statements of Common Stockholders' Equity for each
of the three years ended December 31, 2002, 2001 and 2000
o Consolidated Statements of Income Taxes for each of the three
years ended December 31, 2002, 2001 and 2000
o Notes to Consolidated Financial Statements
2. Financial Statement Schedules - Schedule II - Valuation and
Qualifying Accounts
All other schedules are omitted because they are not required, are inapplicable
or the information is otherwise shown in the financial statements or notes
thereto.
(B) REPORTS ON FORM 8-K:
On November 6, 2002, the Company filed, under Item 5, that the Company had
completed a private placement of $30 million of long-term Senior Notes payable.
(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) First Mortgage Sinking Fund Bonds dates December 15, 1989 between
the Company and The Prudential Insurance Company of America, with respect
to $8.2 million of 9.37% Series I Mortgage Bonds due December 15, 2004, is
not being filed herewith, in accordance with Item 601(b)(4)(iii) of
Regulation S-K. The Company hereby agrees to furnish a copy of that
agreement to the Commission upon request.
Exhibit 4(c) Note Agreement dated February 9, 1993, by and between the Company
and Massachusetts Mutual Life Insurance Company and MML Pension Insurance
Company, with respect to $10 million of 7.97% Unsecured Senior Notes due
February 1, 2008, is incorporated herein by reference to Exhibit 4 to the
Company's Annual Report on Form 10-K for the year ended December 31, 1992,
File No. 0-593.
Exhibit 4(d) Note Purchase Agreement entered into by the Company on October 2,
1995, pursuant to which the Company privately placed $10 million of its
6.91% Senior Notes due in 2010, is not being filed herewith, in accordance
with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to
furnish a copy of that agreement to the Commission upon request.
Exhibit 4(e) Note Purchase Agreement entered into by the Company on December 15,
1997, pursuant to which the Company privately placed $10 million of its
6.85% Senior Notes due 2012, is not being filed herewith, in accordance
with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to
furnish a copy of that agreement to the Commission upon request.
Exhibit 4(f) Note Purchase Agreement entered into by the Company on December 27,
2000, pursuant to which the Company privately placed $20 million of its
7.83% Senior Notes due 2015, is not being filed herewith, in accordance
with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to
furnish a copy of that agreement to the Commission upon request.
Exhibit 4(g) Note Agreement entered into by the Company on October 31, 2002,
pursuant to which the Company privately placed $30 million of its 6.64%
Senior Notes due 2017, is incorporated herein by reference to Exhibit 2 of
the Company's Current Report on Form 8-K, filed November 6, 2002, File No.
001-11590.
*Exhibit 10(a) Executive Employment Agreement dated March 26, 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) Form of Executive Employment Agreement dated March 1997, by and
between Chesapeake Utilities Corporation and each of Michael P. McMasters,
William C. Boyles and Stephen C. Thompson, filed herewith.
*Exhibit 10(c) Executive Employment Agreement dated January 1, 2003, by and
between Chesapeake Utilities Corporation and Ralph J. Adkins filed
herewith.
*Exhibit 10(d) 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(e) Form of Performance Share Agreement dated January 1, 2002,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of Ralph J. Adkins,
John R. Schimkaitis, Michael P. McMasters, William C. Boyles and Stephen C.
Thompson is incorporated herein by reference to Exhibit 10 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001, File No.
001-11590.
*Exhibit 10(f) Form of Performance Share Agreement dated January 1, 2003,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of John R.
Schimkaitis, Michael P. McMasters, Stephen C. Thompson and William C.
Boyles, filed herewith.
*Exhibit 10(g) 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(h) 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(i) 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(j) 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(k) United Systems, Inc. Executive Appreciation Rights Plan dated
December 31, 2000 is incorporated herein by reference to Exhibit 10 of the
Company's Annual Report on Form 10-K for the year ended December 31, 2000,
File No. 001-11590.
Exhibit 12 Computation of Ratio of Earning to Fixed Charges, filed herewith.
Exhibit 21 Subsidiaries of the Registrant, filed herewith.
Exhibit 23 Consent of Independent Accountants, filed herewith.
Exhibit 99.1 Certificate of Chief Executive Office of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated March 28, 2003, filed
herewith.
Exhibit 99.2 Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated March 28, 2003, filed
herewith.
* Management contract or compensatory plan or agreement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange
Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Chesapeake Utilities Corporation
By: /s/ John R. Schimkaitis
--------------------------
John R. Schimkaitis
President and Chief
Executive Officer
Date: March 14, 2003
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 14, 2003 Date: March 14, 2003
/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 14, 2003 Date: March 14, 2003
/s/ Thomas J. Bresnan /s/ Walter J. Coleman
- ------------------------ ------------------------
Thomas J. Bresnan, Director Walter J. Coleman, Director
Date: March 14, 2003 Date: March 14, 2003
/s/ John W. Jardine, Jr. /s/ J. Peter Martin
- ---------------------------- ----------------------
John W. Jardine, Jr., Director J. Peter Martin, Director
Date: March 14, 2003 Date: March 14, 2003
/s/ Joseph E. Moore, Esq. /s/ Calvert A. Morgan, Jr.
- ----------------------------- ------------------------------
Joseph E. Moore, Esq., Director Calvert A. Morgan, Jr., Director
Date: March 14, 2003 Date: March 14, 2003
/s/ Rudolph M. Peins, Jr. /s/ Robert F. Rider
- ----------------------------- ----------------------
Rudolph M. Peins, Jr., Director Robert F. Rider, Director
Date: March 14, 2003 Date: March 14, 2003
CERTIFICATIONS
I, John R. Schimkaitis, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Utilities
Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report ("Evaluation Date");
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function);
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weakness in
internal controls;
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ John R. Schimkaitis
- --------------------------
John R. Schimkaitis
President and Chief Executive Officer
I, Michael P. McMasters, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Utilities
Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report ("Evaluation Date");
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function);
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weakness in
internal controls;
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ Michael P. McMasters
- ---------------------------
Michael P. McMasters
Vice President, Treasurer and Chief Financial Officer
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
- --------------------------------------------------------------------------------------------------
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
2002 . . . . . . . . . . . . . . . . $621,516 $677,461 $210,735 $ (850,084) $659,628
- --------------------------------------------------------------------------------------------------
2001 . . . . . . . . . . . . . . . . $549,961 $592,590 $488,895 $(1,009,930) $621,516
- --------------------------------------------------------------------------------------------------
2000 . . . . . . . . . . . . . . . . $475,592 $342,4077 $ 63,741 $ (331,779) $549,961
- --------------------------------------------------------------------------------------------------
<FN>
(1) Recoveries.
(2) Uncollectible accounts charged off.
</FN>
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
EXHIBIT 12
RATIO OF EARNINGS TO FIXED CHARGES
- ----------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ----------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS . . . . . . . . . . . $ 5,645,153 $ 6,721,537 $ 7,489,201
Add:
Income taxes . . . . . . . . . . . . . . . . . . . 3,650,154 4,252,275 4,496,592
Portion of rents representative of interest factor 370,061 275,773 156,680
Interest on indebtedness . . . . . . . . . . . . . 4,968,652 5,178,495 4,398,266
Amortization of debt discount and expense. . . . . 89,387 101,183 111,122
- ----------------------------------------------------------------------------------------------
EARNINGS AS ADJUSTED. . . . . . . . . . . . . . . . . . $14,723,407 $16,529,263 $16,651,861
==============================================================================================
FIXED CHARGES
Portion of rents representative of interest factor $ 370,061 $ 275,773 $ 156,680
Interest on indebtedness . . . . . . . . . . . . . 4,968,652 5,178,495 4,398,266
Amortization of debt discount and expense. . . . . 89,387 101,183 111,122
- ----------------------------------------------------------------------------------------------
FIXED CHARGES . . . . . . . . . . . . . . . . . . . . . $ 5,428,100 $ 5,555,451 $ 4,666,068
==============================================================================================
RATIO OF EARNINGS TO FIXED CHARGES. . . . . . . . . . . 2.71 2.98 3.57
==============================================================================================
CHESAPEAKE UTILITIES CORPORATION
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
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, Inc. 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
Exhibit 99.1
CERTIFICATE OF CHIEF EXECUTIVE OFFICER
OF
CHESAPEAKE UTILITIES CORPORATION
(PURSUANT TO 18 U.S.C. SECTION 1350)
I, John R. Schimkaitis, President and Chief Executive Officer of Chesapeake
Utilities Corporation, certify that, to the best of my knowledge, the Annual
Report on Form 10-K of Chesapeake Utilities Corporation ("Chesapeake") for the
year ended December 31, 2002, filed with the Securities and Exchange Commission
on the date hereof (i) fully complies with the requirements of section 13(1) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained therein fairly presents, in all material respects, the
financial condition and results of operations of Chesapeake.
/s/ JOHN R. SCHIMKAITIS
--------------------------
John R. Schimkaitis
March 28, 2003
A signed original of this written statement required by Section 906 of the
Sarbanes-Oxley Act of 2002 has been provided to Chesapeake Utilities Corporation
and will be retained by Chesapeake Utilities Corporation and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.2
CERTIFICATE OF CHIEF FINANCIAL OFFICER
OF
CHESAPEAKE UTILITIES CORPORATION
(PURSUANT TO 18 U.S.C. SECTION 1350)
I, Michael P. McMasters, Vice President, Chief Financial Officer and
Treasurer of Chesapeake Utilities Corporation, certify that, to the best of my
knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation
("Chesapeake") for the year ended December 31, 2002, filed with the Securities
and Exchange Commission on the date hereof (i) fully complies with the
requirements of section 13(1) or 15(d) of the Securities Exchange Act of 1934,
as amended, and (ii) the information contained therein fairly presents, in all
material respects, the financial condition and results of operations of
Chesapeake.
/s/ MICHAEL P. MCMASTERS
--------------------------
Michael P. McMasters
March 28, 2003
A signed original of this written statement required by Section 906 of the
Sarbanes-Oxley Act of 2002 has been provided to Chesapeake Utilities Corporation
and will be retained by Chesapeake Utilities Corporation and furnished to the
Securities and Exchange Commission or its staff upon request.
CONSENT OF INDEPENDENT ACCOUNTANTS
________
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-3 (Nos. 33-28391 and 33-64671) and Form S-8 (Nos. 333-01175
and 333-94159) of Chesapeake Utilities Corporation of our report dated February
20, 2003 relating to the financial statements and financial statement schedule,
which appears in this Form 10-K.
/s/ PRICEWATERHOUSECOOPERS
- ---------------------------
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
March 28, 2003
Upon written request,
Chesapeake will provide, free of
charge, a copy of any exhibit to
the 2002 Annual Report on
Form 10-K not included
in this document.