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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
- -------------------------------------------------------------------------------------------------------------------
(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.
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
- -------------------------------------------------------------------------------------------------------
(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.
- --------------------------------------------------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------------------------------------------------
(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.
- --------------------------------------------------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------------------------------------------------
(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.
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)
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INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 (DECREASE) 2001 2000 (DECREASE)
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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)
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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
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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)
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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. The