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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, 2003
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 10, 2004, 5,706,022 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, 2003, 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 $122
million.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2004 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, 2003
TABLE OF CONTENTS
PAGE
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PART I.......................................................................1
Item 1. Business.........................................................1
Item 2. Properties...................................................... 9
Item 3. Legal Proceedings..............................................10
Item 4. Submission of Matters to a Vote of Security Holders.....11
PART II.....................................................................12
Item 5. Market for the Registrant's Common Stock and
Related Security Holder Matters.................................12
Item 6. Selected Financial Data.......................................14
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................18
Item 7a. Quantitative and Qualitative Disclosures About Market Risk....35
Item 8. Financial Statements and Supplemental Data..................35
Item 9. Changes In and Disagreements With Accountants
on Accounting and Financial Disclosure........................62
Item 9a. Controls and Procedures.......................................62
PART III....................................................................62
Item 10. Directors and Executive Officers of the Registrant.......62
Item 11. Executive Compensation........................................63
Item 12. Security Ownership of Certain Beneficial Owners
and Management.................................................63
Item 13. Certain Relationships and Related Transactions.............63
Item 14. Principal Accounting Fees and Services.....................63
PART IV.....................................................................64
Item 15. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K............................64
SIGNATURES...................................................................67
PART I
ITEM 1. BUSINESS
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") 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. The address of Chesapeake's internet website is
www.chpk.com. The content of this website is not part of this report.
Chesapeake has a Business Code of Ethics and Conduct applicable to all
employees, officers and directors and a Code of Ethics for Financial Officers.
Copies of the Business Code of Ethics and Conduct and the Financial Officer Code
of Ethics are available on our internet website. Chesapeake also adopted
Corporate Governance Guidelines and Charters for the Audit Committee,
Compensation Committee, and Governance Committee of the Board of Directors, each
of which satisfies the regulatory requirements established by the Securities and
Exchange Commission and the New York Stock Exchange. Each of these documents
also is available on Chesapeake's internet website or may be obtained by writing
to:
Corporate Secretary; c/o Chesapeake Utilities Corporation; 909 Silver Lake
Blvd.; Dover, DE 19904.
If Chesapeake makes any amendment to, or grants a waiver of, any provision of
the Business Code of Ethics and Conduct or the Financial Officer Code of Ethics
applicable to its principal executive officer, principal financial officer,
principal accounting officer or controller, the amendment or waiver will be
disclosed within five business days on the internet website.
(A) GENERAL DEVELOPMENT OF BUSINESS
Chesapeake is a diversified utility company engaged directly or through
subsidiaries in natural gas distribution and transmission, propane distribution
and wholesale marketing, advanced information services, and other related
businesses.
Chesapeake's three natural gas distribution divisions serve approximately 47,600
residential, commercial and industrial customers in central and southern
Delaware, 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 34,900 customers
in central and southern Delaware, the Eastern Shore of both Maryland and
Virginia and parts of Florida. The advanced information services segment
provides domestic and international clients with information technology related
business services and solutions for both enterprise and e-business applications.
During 2003, Chesapeake decided to exit the water services business and sold the
assets of six of the seven dealerships. Chesapeake expects to sell the remaining
water dealership during 2004.
(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 D."
(C) NARRATIVE DESCRIPTION OF BUSINESS
The Company is engaged in three primary business activities: natural gas
distribution and transmission, propane distribution and wholesale marketing and
advanced information 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 residential, commercial and
industrial customers in central and southern Delaware, 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
serve an average of approximately 36,400 customers, of which approximately
36,200 are residential and commercial customers purchasing gas primarily
for heating purposes. The remainder are industrial customers. For the year
2003, residential and commercial customers accounted for approximately 64%
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
11,100 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 PESCO, provides natural gas supply management services to 250
customers.
Eastern Shore. The Company's wholly owned transmission subsidiary, Eastern
Shore, owns and 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 through Delaware to its terminus on the Eastern Shore of
Maryland. Eastern Shore also provides swing transportation service and
contract storage services. Eastern Shore's rates and services 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
Transcontinental Gas Pipeline Corporation ("Transco"), Columbia Gas
Transmission Corporation ("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. The Delaware division's contracts with Transco include: (a) firm
transportation capacity of 9,029 dekatherms ("Dt") per day, which expires
in 2005; (b) firm transportation capacity of 311 Dt per day for December
through February, expiring in 2006; (c) firm transportation capacity of 174
Dt per day, which expires in 2004; 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.
The Delaware division'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.
The Delaware division'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.
The Delaware division's contracts with Eastern Shore include: (a) firm
transportation capacity of 34,587 Dt per day for the period December
through February, 33,365 Dt per day for the months of November, March and
April, and 24,289 Dt per day for the period May through October, with
various expiration dates ranging from 2004 to 2017; (b) firm storage
capacity 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 providing a
peak day entitlement of 580 Dt and a total capacity of 29,000 Dt, which
expires in 2013; (d) firm storage capacity providing a peak day entitlement
of 911 Dt and a total capacity of 5,708 Dt, which expires in 2006; and (e)
firm storage capacity providing a peak day entitlement of 230 Dt and a
total capacity of 11,700 Dt, which expires in 2004. The Delaware division'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 the Delaware division's
Transco capacity referenced earlier and (b) an interruptible storage
service that supports a swing supply service provided by Transco.
The Delaware division 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 21,700 Dt and the
supplies are transported by Transco, Columbia, Gulf and Eastern Shore under
firm transportation contracts. The gas purchase contracts have various
expiration dates and daily quantities may vary from day to day and month to
month.
Maryland. The Maryland division'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.
The Maryland division'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. The Maryland division'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.
The Maryland division'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.
The Maryland division's contracts with Eastern Shore include: (a) firm
transportation capacity of 13,678 Dt per day for the period December
through February, 12,954 Dt per day for the months of November, March and
April, and 8,393 Dt per day for the period May through October, with
various expiration dates ranging from 2004 to 2013; (b) firm storage
capacity 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 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 providing a peak day
entitlement of 569 Dt and a total capacity of 3,560 Dt, which expires in
2006. The Maryland division'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 the Maryland division's Transco capacity referenced earlier and
(b) an interruptible storage service that supports a swing supply service
provided by Transco.
The Maryland division 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
the Maryland division'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, which expires in 2010; and (b) daily firm
transportation capacity of 1,000 Dt daily, which expires in 2015.
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 10,000 Dt daily. The contract with Gulfstream expires May 31,
2022.
Eastern Shore. Eastern Shore has 2,888 thousand cubic feet ("Mcf") of firm
transportation capacity under contract with Transco, which expires in 2005.
Eastern Shore also has contracts with Transco for: (a) 5,406 Mcf of firm
peak day entitlements and total storage capacity of 267,981 Mcf, which
expires in 2013; and (b) 1,640 Mcf of firm peak day entitlements and total
storage capacity of 10,283 Mcf, which expires in 2006.
Eastern Shore also has firm storage service and firm storage transportation
capacity 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 and storage 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 customers in each respective 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 Eastern Shore can charge for its transportation
and storage 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 achieved rate of return in each jurisdiction in
order to ensure the timely filing of rate adjustment applications.
REGULATORY PROCEEDINGS
Delaware. 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 resulted in an increase in rates of approximately $380,000
per year. The Delaware Public Service Commission approved a settlement
agreement among the Company, the Commission staff and the Division of the
Public Advocate for Phase II of the Rate Increase Application in November
2002. Phase II resulted 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.
Florida. On November 19, 2001, the Florida division filed a petition with
the Florida Public Service Commission for approval of certain
transportation cost recovery rates. The Florida Public Service Commission
approved the rates on January 24, 2002, which provide for the recovery,
over a two-year period, of the Florida division's actual and projected
non-recurring expenses incurred in the implementation of the transportation
provisions of the tariff as approved in a November 2000 rate case. The
Florida division filed a petition on February 4, 2004, to dispose of a
minor under-recovery of the actual expenses incurred to implement the
tariff provisions.
On November 5, 2002, the Florida Public Service Commission authorized a
pilot program under which the Florida division converted all remaining
sales customers to transportation service and exited the gas merchant
function. Implementation of Phase One of the Transitional Transportation
Service ("TTS") program was completed in November 2002, and the Florida
division is now actively providing the administrative services as approved
by the FPSC.
On July 15, 2003, the FPSC approved a rate restructuring proposed by the
Florida Division. The restructuring created three new low volume rate
classes, with customer charge levels that ensure that all customers receive
benefits from the TTS program
On January 4, 2004, the Florida Public Service Commission authorized the
Florida division to refund the remaining balance in its over-recovered
purchased gas costs account, totaling $246,000, as a final step in its exit
of the gas merchant function.
Eastern Shore. On October 31, 2001, Eastern Shore filed a rate change with
the FERC pursuant to the requirements of the Stipulation and Agreement
dated August 1, 1997. Following settlement conferences held in May 2002,
the parties reached a settlement in principle on or about May 23, 2002, to
resolve all issues related to its rate case.The Offer of Settlement and the
Stipulation and Agreement were finalized and filed with the FERC on August
2, 2002. The agreement provided for a reduction in rates of approximately
$456,000 on an annual basis. On October 10, 2002, the FERC issued an Order
approving the Offer of Settlement and the Stipulation and Agreement.
Settlement rates went into effect on December 1, 2002.
On January 25, 2002, Eastern Shore filed an application before the 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 April 1, 2003, Eastern Shore filed an application before the FERC
requesting authorization for the following: (1) Phase I - upgrade of
Parkesburg M & R Station; (2) Phase II - construct and operate 2.7 miles of
16-inch mainline looping in Pennsylvania; and (3) Phase III - construct and
operate 3.0 miles of 16-inch mainline looping and a pressure control
station in Delaware. The purpose of this construction is to enable Eastern
Shore to provide additional daily firm transportation capacity of 15,100 Dt
on Eastern Shore's system. Such increased capacity is to be phased in over
a three-year period commencing November 1, 2003. Phase I of this expansion
was completed and placed into service on November 1, 2003.
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). At that time, the FERC
would not review Eastern Shore's filing, because the FERC wished to settle
a related matter with another transmission company first. The other
transmission company submitted a filing on December 5, 2003. The FERC has
not yet acted on the filing. Eastern Shore will resubmit its transition
cost recovery filing immediately upon learning of the FERC's approval.
On December 16, 2003, Eastern Shore filed with the FERC revised tariff
sheets to implement revisions to its Fuel Retention and Cash Out
provisions. These will be effective January 15, 2004. The proposed tariff
revisions permit Eastern Shore to incorporate its Deferred Gas Required for
Operations amounts into the calculation of its annual Fuel Retention
percentage adjustment and to implement a surcharge, effective July 1 of
each year, to recover cash-out amounts. The FERC accepted Eastern Shore's
revised tariff sheets on January 15, 2004, subject to certain revisions to
clarify the tariff sheets. On January 30, 2004, Eastern Shore submitted the
revised tariff sheets.
(I) (B) PROPANE DISTRIBUTION AND WHOLESALE 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 wholesale 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 34,900
propane customers on the Delmarva Peninsula and in Florida and delivered
approximately 24 million retail and wholesale gallons of propane during
2003.
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 - Market Risk."
The propane distribution business is affected by many factors such as
seasonality, the absence of price regulation and competition among local
providers. The propane wholesale 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
See discussion on competition in Item 7 under the heading "Management's
Discussion and Analysis - Competition."
RATES AND REGULATION
The Company's propane distribution and wholesale 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, headquartered in Norcross, Georgia, provides domestic and
international clients with information technology related business services
and solutions for both enterprise and e-business applications.
COMPETITION
See discussion on competition in Item 7 under the heading "Management's
Discussion and Analysis - Competition."
(I) (D) OTHER SUBSIDIARIES
Skipjack, Inc. ("Skipjack"), Eastern Shore Real Estate, Inc. and Chesapeake
Investment Company are wholly owned subsidiaries of Chesapeake Service
Company. Skipjack and Eastern Shore Real Estate, Inc. own and lease office
buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake
Investment Company is a Delaware affiliated investment company.
Chesapeake conducted its water conditioning and treatment and bottled water
services business through separate subsidiaries. The assets of all of the
water businesses except for Sharp Water of Florida, Inc were sold in 2003
and the subsidiaries are now inactive.
(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, 2003, Chesapeake had 452 employees, including 197 in
natural gas, 140 in propane, 71 in advanced information services and 13 in
water services. 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:
John R. Schimkaitis (age 56) Mr. Schimkaitis has served as the Chief
Executive Officer of Chesapeake since 1999, and as President since 1997.
Mr. Schimkaitis has been employed by Chesapeake since 1984. His positions
with the Company prior to 1997 included 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 since 1996.
Michael P. McMasters (age 45) Mr. McMasters has served as Vice President
and Chief Financial Officer of Chesapeake since 1996. Mr. McMasters resumed
his employment with Chesapeake in 1994. He previously served as Treasurer,
Vice President of Eastern Shore, Director of Accounting and Rates and
Controller. Prior to rejoining Chesapeake, Mr. McMasters was employed as
Director of Operations Planning for Equitable Gas Company.
Stephen C. Thompson (age 43) Mr. Thompson has served as Vice President of
the Natural Gas Operations as well as Vice President of Chesapeake
Utilities Corporation since 1997. Mr. Thompson has been employed by
Chesapeake since 1983. His positions with the Company prior to 1997
included 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 46) Mr. Boyles has served as Vice President of
Chesapeake since 1997 and as Corporate Secretary of Chesapeake since 1998.
Mr. Boyles has been employed by Chesapeake since 1988. 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.
S. Robert Zola (age 52) Mr. Zola has served as President of Sharp Energy
since he began his employment with Chesapeake in 2002. Prior to joining
Chesapeake, he was employed as a Northeast Regional Manager for Synergy
Gas, now Cornerstone MLP in Pennsylvania.
ITEM 2. PROPERTIES
(A) GENERAL
The Company owns offices and operates facilities in the following locations:
Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford,
Laurel and Georgetown, Delaware; and Winter Haven, Florida. Chesapeake rents
office space in Dover and Ocean View, Delaware; Jupiter, Lecanto and Stuart,
Florida; Chincoteague and Belle Haven, Virginia; Easton, and Salisbury,
Maryland; Houston, Texas; and Atlanta, Georgia. In general, the Company believes
that its properties 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 754 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 natural gas distribution 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 and operates approximately 304 miles of transmission
pipelines extending from supply interconnects at Parkesburg, Pennsylvania;
Daleville, Pennsylvania and Hockessin, Delaware to approximately seventy-five
delivery points in southeastern Pennsylvania, Delaware and the eastern shore of
Maryland. Eastern Shore also owns compressor stations located in Daleville,
Pennsylvania, Delaware City, Delaware and Bridgeville, Delaware. The compressor
stations are used to increase pressures as necessary to meet system demands.
(D) PROPANE DISTRIBUTION AND WHOLESALE 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 40 plant facilities in Delaware, Maryland and Virginia, located on
real estate that is either owned or leased. 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; however, it leases propane storage capacity and
pipeline capacity.
(E) WATER SERVICES
The Company owns a facility in Salisbury, Maryland that is currently being
rented to another party. The Company intends to sell the facility during 2004.
ITEM 3. LEGAL PROCEEDINGS
(F) GENERAL
The Company and its subsidiaries are involved in various legal actions and
claims arising in the normal course of business. The Company is also involved in
certain legal and administrative proceedings before various governmental
agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings will not have a material effect on the
consolidated financial position of the Company.
(G) ENVIRONMENTAL
The Company has participated in the investigation, assessment and remediation of
three former gas manufacturing plant sites located in different jurisdictions.
The Company has accrued liabilities for each of the Dover Gas Light, Salisbury
Town Gas Light and the Winter Haven Coal Gas sites. The Company is currently in
discussions with the Maryland Department of the Environment ("MDE") regarding a
fourth site in Cambridge, Maryland.
DOVER GAS LIGHT SITE
On January 15, 2004, the Company received a Certificate of Completion of Work
from the United States Environmental Protection Agency ("EPA") regarding the
Dover Gas Light site. This concluded the remedial action obligation that
Chesapeake had related to this site. The Dover Gas Light Site is a former
manufactured gas plant site located in Dover, Delaware. In May 2001, the
Company, General Public Utilities Corporation, Inc. (now FirstEnergy
Corporation), the State of Delaware, the United States Environmental Protection
Agency ("USEPA") and the United States Department of Justice ("DOJ") signed a
settlement term sheet to settle complaints brought by the Company and the United
States in 1996 and 1997, respectively, with respect to the Dover Site. In
October 2002, the final Consent Decrees were signed and delivered to the DOJ.
The Consent Decrees were lodged simultaneously with the United States District
Court for the District of Delaware and a notice soliciting public comment for a
30-day period was published in the Federal Register. The public comment period
ended April 30, 2003 with no public comments. The DOJ filed an Unopposed Motion
for Entry of Consent Decrees on June 26, 2003.
By Order dated July 18, 2003, the U.S. District Court for the District of
Delaware entered final judgment approving and entering the Consent Decrees
resolving this litigation. The entry of the Consent Decrees triggered the
parties' obligations to make the payments required by the settlement agreement
within thirty days. Chesapeake received from other parties, net settlement
payments of $1.15 million. These proceeds will be passed on to the Company's
firm customers, in accordance with the environmental rate rider. Under the
Consent Decrees, Chesapeake received a release from liability and covenant not
to sue from the EPA and the State of Delaware. This relieves Chesapeake from
liability for future remediation at the site, unless previously unknown
conditions are discovered at the site, or information previously unknown to the
EPA is received that indicates the remedial action related to the former
manufactured gas plant is not sufficiently protective. These contingencies are
standard, and are required by the United States in all liability settlements.
At December 31, 2003, the Company had accrued $10,000 for costs associated with
the Dover Gas Light site and had recorded an associated regulatory asset for the
same amount. Through December 31, 2003, the Company has incurred approximately
$9.6 million in costs relating to environmental testing and remedial action
studies at the site. Approximately $9.4 million has been recovered through
December 2003 from other parties or through rates.
SALISBURY TOWN GAS LIGHT SITE
In cooperation with the MDE, the Company completed an assessment of the
Salisbury manufactured gas plant site, which determined 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 to
discontinue all on-site and off-site well monitoring, except for one well that
is being maintained for continued product monitoring and recovery. 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 has completed the MDE recommended work plans and has executed the deed
restrictions. During the third quarter of 2003 the Company submitted a revised
request for the NFA. The MDE has not yet responded to the request.
The Company has adjusted the liability with respect to the Salisbury Town Gas
Light site to $8,000 at December 31, 2003. This amount is based on the estimated
costs to perform limited product monitoring and recovery efforts and fulfill
ongoing reporting requirements. A corresponding regulatory asset has been
recorded, reflecting the Company's belief that costs incurred will be
recoverable in base rates.
Through December 31, 2003, the Company has incurred approximately $2.9 million
for remedial actions and environmental studies at the Salisbury Town Gas Light
site. Of this amount, approximately $1.8 million has been recovered through
insurance proceeds or in rates. The Company expects to recover the remaining
costs through rates and has established a regulatory asset for those costs.
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. 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 a 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 $544,000 as of December 31, 2003 for the
Florida site. Through December 31, 2003, the Company has incurred approximately
$1.3 million of environmental costs associated with the Florida site. At
December 31, 2003 the Company had collected through rates $179,000 in excess of
costs incurred. A regulatory asset of approximately $335,000, representing the
uncollected portion of the estimated clean-up costs, has 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 2003 and
2002 were as follows:
- ---------------------------------------------------------
DIVIDENDS
DECLARED
QUARTER ENDED HIGH LOW CLOSE PER SHARE
- ---------------------------------------------------------
2003
MARCH 31 . . $19.8400 $18.4000 $18.8000 $0.2750
JUNE 30. . . 23.8400 18.4500 22.6000 0.2750
SEPTEMBER 30 24.4500 20.4900 22.9200 0.2750
DECEMBER 31. 26.7000 23.0200 26.0500 0.2750
- ---------------------------------------------------------
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
- ---------------------------------------------------------
Indentures to the long-term debt of the Company 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 Company's Note
Agreement for the 6.64 percent Senior Notes, the Company cannot, until the
retirement of the Senior Note, pay any dividends after October 31, 2002 which
exceed the sum of $10 million plus consolidated net income recognized after
January 1, 2003. As of December 31, 2003, the amount available for future
dividends under this covenant is $11.6 million.
At December 31, 2003, there were approximately 2,069 shareholders of record of
the Common Stock.
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 (1) 2001 (1) 2000 (1) 1999 (1)
- --------------------------------------------------------------------------------------------------------------------------
OPERATING (IN THOUSANDS OF DOLLARS) (3)
- ---------------------------------------
Revenues
Natural gas distribution and transmission . . . . . . $ 110,247 $ 93,588 $ 107,418 $ 101,138 $ 75,637
Propane . . . . . . . . . . . . . . . . . . . . . . . 39,760 28,124 35,742 31,780 25,199
Advanced informations systems . . . . . . . . . . . . 12,578 12,764 14,104 12,390 13,531
Other and eliminations. . . . . . . . . . . . . . . . (287) (333) (113) (131) (14)
- --------------------------------------------------------------------------------------------------------------------------
Total revenues. . . . . . . . . . . . . . . . . . . . . $ 162,298 $ 134,143 $ 157,151 $ 145,177 $ 114,353
Operating income
Natural gas distribution and transmission . . . . . . $ 16,653 $ 14,973 $ 14,405 $ 12,798 $ 10,388
Propane . . . . . . . . . . . . . . . . . . . . . . . 3,875 1,052 913 2,135 2,622
Advanced informations systems . . . . . . . . . . . . 692 343 517 336 1,470
Other and eliminations. . . . . . . . . . . . . . . . 359 237 386 816 495
- --------------------------------------------------------------------------------------------------------------------------
Total operating income. . . . . . . . . . . . . . . . . $ 21,579 $ 16,605 $ 16,221 $ 16,085 $ 14,975
Net income from continuing operations . . . . . . . . . $ 10,079 $ 7,535 $ 7,341 $ 7,665 $ 8,372
- --------------------------------------------------------------------------------------------------------------------------
ASSETS (in thousands of dollars)
- --------------------------------
Gross property, plant and equipment . . . . . . . . . . $ 234,919 $ 229,128 $ 216,903 $ 192,925 $ 172,068
Net property, plant and equipment (4) . . . . . . . . . $ 167,872 $ 166,846 $ 161,014 $ 131,466 $ 117,663
Total assets (4). . . . . . . . . . . . . . . . . . . . $ 221,165 $ 223,721 $ 222,229 $ 211,664 $ 166,958
Capital expenditures (3). . . . . . . . . . . . . . . . $ 11,822 $ 13,836 $ 26,293 $ 22,057 $ 21,365
- --------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION (in thousands of dollars)
- ----------------------------------------
Stockholders' equity. . . . . . . . . . . . . . . . . . $ 72,939 $ 67,350 $ 67,517 $ 64,669 $ 60,714
Long-term debt, net of current maturities . . . . . . . $ 69,416 $ 73,408 $ 48,409 $ 50,921 $ 33,777
- --------------------------------------------------------------------------------------------------------------------------
Total capital . . . . . . . . . . . . . . . . . . . . . $ 142,355 $ 140,758 $ 115,926 $ 115,590 $ 94,491
Current portion of long-term debt . . . . . . . . . . . $ 3,665 $ 3,938 $ 2,686 $ 2,665 $ 2,665
Short-term debt . . . . . . . . . . . . . . . . . . . . $ 3,515 $ 10,900 $ 42,100 $ 25,400 $ 23,000
- --------------------------------------------------------------------------------------------------------------------------
Total capitalization and short-term financing . . . . . $ 149,535 $ 155,596 $ 160,712 $ 143,655 $ 120,156
- --------------------------------------------------------------------------------------------------------------------------
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect
the Company's Delaware and Maryland natural gas divisions on
the "accrual" rather than the "as billed" revenue recognition method.
(2) The years 1998, 1997, 1996, 1995 and 1994 have not been restated to reflect
the "accrual" revenue recognition method due to the
immateriality of the impact on the Company's financial results.
(3) These amounts exclude the results of water services due to their
reclassification to discontinued operations.
(4) The years 2003, 2002 and 2001 reflect the results of adopting SFAS 143.
(5) 1994 has not been restated to include the business combinations with
Tri-County Gas Company, Inc., Tolan Water Service and Xeron, Inc.
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1998 (2) 1997 (2) 1996 (2) 1995 (2) 1994 (2) (5)
- --------------------------------------------------------------------------------------------------------------------------
OPERATING (IN THOUSANDS OF DOLLARS) (3)
- ---------------------------------------
Revenues
Natural gas distribution and transmission . . . . . . $ 68,770 $ 88,108 $ 90,044 $ 79,110 $ 71,781
Propane . . . . . . . . . . . . . . . . . . . . . . . 23,377 28,614 36,727 26,806 20,770
Advanced informations systems . . . . . . . . . . . . 10,331 7,786 7,230 8,862 8,311
Other and eliminations. . . . . . . . . . . . . . . . (15) (182) (243) (1,661) (2,290)
- --------------------------------------------------------------------------------------------------------------------------
Total revenues. . . . . . . . . . . . . . . . . . . . . $ 102,463 $ 124,326 $ 133,758 $ 113,117 $ 98,572
Operating income
Natural gas distribution and transmission . . . . . . $ 8,820 $ 9,240 $ 9,627 $ 10,812 $ 7,820
Propane . . . . . . . . . . . . . . . . . . . . . . . 965 1,137 2,668 2,128 2,288
Advanced informations systems . . . . . . . . . . . . 1,316 1,046 1,056 1,061 105
Other and eliminations. . . . . . . . . . . . . . . . 485 558 560 (34) (456)
- --------------------------------------------------------------------------------------------------------------------------
Total operating income. . . . . . . . . . . . . . . . . $ 11,586 $ 11,981 $ 13,911 $ 13,967 $ 9,757
Net income from continuing operations . . . . . . . . . $ 5,329 $ 5,812 $ 7,764 $ 7,681 $ 4,460
- --------------------------------------------------------------------------------------------------------------------------
ASSETS (in thousands of dollars)
- --------------------------------
Gross property, plant and equipment . . . . . . . . . . $ 152,991 $ 144,251 $ 134,001 $ 120,746 $ 110,023
Net property, plant and equipment (4) . . . . . . . . . $ 104,266 $ 99,879 $ 94,014 $ 85,055 $ 75,313
Total assets (4). . . . . . . . . . . . . . . . . . . . $ 145,029 $ 145,719 $ 155,786 $ 130,998 $ 108,271
Capital expenditures (3). . . . . . . . . . . . . . . . $ 12,516 $ 13,471 $ 15,399 $ 12,887 $ 10,653
- --------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION (in thousands of dollars)
- ----------------------------------------
Stockholders' equity. . . . . . . . . . . . . . . . . . $ 56,356 $ 53,656 $ 50,700 $ 45,587 $ 37,063
Long-term debt, net of current maturities . . . . . . . $ 37,597 $ 38,226 $ 28,984 $ 31,619 $ 24,329
- --------------------------------------------------------------------------------------------------------------------------
Total capital . . . . . . . . . . . . . . . . . . . . . $ 93,953 $ 91,882 $ 79,684 $ 77,206 $ 61,392
Current portion of long-term debt . . . . . . . . . . . $ 520 $ 1,051 $ 3,526 $ 1,787 $ 1,348
Short-term debt . . . . . . . . . . . . . . . . . . . . $ 11,600 $ 7,600 $ 12,735 $ 5,400 $ 8,000
- --------------------------------------------------------------------------------------------------------------------------
Total capitalization and short-term financing . . . . . $ 106,073 $ 100,533 $ 95,945 $ 84,393 $ 70,740
- --------------------------------------------------------------------------------------------------------------------------
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect
the Company's Delaware and Maryland natural gas divisions on
the "accrual" rather than the "as billed" revenue recognition method.
(2) The years 1998, 1997, 1996, 1995 and 1994 have not been restated to reflect
the "accrual" revenue recognition method due to the
immateriality of the impact on the Company's financial results.
(3) These amounts exclude the results of water services due to their
reclassification to discontinued operations.
(4) The years 2003, 2002 and 2001 reflect the results of adopting SFAS 143.
(5) 1994 has not been restated to include the business combinations with
Tri-County Gas Company, Inc., Tolan Water Service and Xeron, Inc.
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31,. . . . . . . . . . . . . 2003 2002 (1) 2001 (1) 2000 (1) 1999 (1)
- --------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA AND RATIOS
- ----------------------------
Basic earnings per share from continuing operations (3) $ 1.80 $ 1.37 $ 1.37 $ 1.46 $ 1.63
Return on average equity from continuing operations (3) 14.4% 11.2% 11.1% 12.2% 14.3%
Common equity / total capital . . . . . . . . . . . . . 51.2% 47.8% 58.2% 55.9% 64.3%
Common equity / total capital and short-term financing. 48.8% 43.3% 42.0% 45.0% 50.5%
Book value per share. . . . . . . . . . . . . . . . . . $ 12.89 $ 12.16 $ 12.45 $ 12.21 $ 11.71
- --------------------------------------------------------------------------------------------------------------------------
Market price:
High. . . . . . . . . . . . . . . . . . . . . . . . . $ 26.700 $ 21.990 $ 19.900 $ 18.875 $ 19.813
Low . . . . . . . . . . . . . . . . . . . . . . . . . $ 18.400 $ 16.500 $ 17.375 $ 16.250 $ 14.875
Close . . . . . . . . . . . . . . . . . . . . . . . . $ 26.050 $ 18.300 $ 19.800 $ 18.625 $ 18.375
- --------------------------------------------------------------------------------------------------------------------------
Average number of shares outstanding. . . . . . . . . . 5,610,592 5,489,424 5,367,433 5,249,439 5,144,449
Shares outstanding end of year. . . . . . . . . . . . . 5,660,594 5,537,710 5,424,962 5,297,443 5,186,546
Registered common shareholders. . . . . . . . . . . . . 2,069 2,130 2,171 2,166 2,212
Cash dividends declared per share . . . . . . . . . . . $ 1.10 $ 1.10 $ 1.10 $ 1.07 $ 1.03
Dividend yield (annualized) . . . . . . . . . . . . . . 4.2% 6.0% 5.6% 5.8% 5.7%
Payout ratio from continuing operations (3) . . . . . . 61.1% 80.3% 80.3% 73.3% 63.2%
- --------------------------------------------------------------------------------------------------------------------------
ADDITIONAL DATA
- ---------------
Customers
Natural gas distribution and transmission . . . . . . 47,649 45,133 42,741 40,854 39,029
Propane distribution. . . . . . . . . . . . . . . . . 34,894 34,566 35,530 35,563 35,267
- --------------------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF). . . . . . . . . . . 27,821 27,935 27,264 30,830 27,383
Propane distribution (in thousands of gallons). . . . 25,147 21,185 23,080 28,469 27,788
- --------------------------------------------------------------------------------------------------------------------------
Heating degree-days (Delmarva Peninsula). . . . . . . . 4,715 4,161 4,368 4,730 4,082
Propane bulk storage capacity (in thousands of gallons) 2,195 2,151 1,958 1,928 1,926
Total employees (3) . . . . . . . . . . . . . . . . . . 439 455 458 471 466
- --------------------------------------------------------------------------------------------------------------------------
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect
the Company's Delaware and Maryland natural gas divisions on
the "accrual" rather than the "as billed" revenue recognition method.
(2) The years 1998, 1997, 1996, 1995 and 1994 have not been restated to reflect
the "accrual" revenue recognition method due to the
immateriality of the impact on the Company's financial results.
(3) These amounts exclude the results of water services due to their
reclassification to discontinued operations.
(4) 1994 has not been restated to include the business combinations with
Tri-County Gas Company, Inc., Tolan Water Service and Xeron, Inc.
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31,. . . . . . . . . . . . . 1998 (2) 1997 (2) 1996 (2) 1995 (2) 1994 (2) (4)
- --------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA AND RATIOS
- ----------------------------
Basic earnings per share from continuing operations (3) $ 1.05 $ 1.17 $ 1.58 $ 1.59 $ 1.23
Return on average equity from continuing operations (3) 9.7% 11.3% 16.2% 18.6% 12.4%
Common equity / total capital . . . . . . . . . . . . . 60.0% 58.4% 63.6% 59.0% 60.4%
Common equity / total capital and short-term financing. 53.1% 53.4% 52.8% 54.0% 52.4%
Book value per share. . . . . . . . . . . . . . . . . . $ 11.06 $ 10.72 $ 10.26 $ 9.38 $ 10.15
- --------------------------------------------------------------------------------------------------------------------------
Market price:
High. . . . . . . . . . . . . . . . . . . . . . . . . $ 20.500 $ 21.750 $ 18.000 $ 15.500 $ 15.250
Low . . . . . . . . . . . . . . . . . . . . . . . . . $ 16.500 $ 16.250 $ 15.125 $ 12.250 $ 12.375
Close . . . . . . . . . . . . . . . . . . . . . . . . $ 18.313 $ 20.500 $ 16.875 $ 14.625 $ 12.750
- --------------------------------------------------------------------------------------------------------------------------
Average number of shares outstanding. . . . . . . . . . 5,060,328 4,972,086 4,912,136 4,836,430 3,628,056
Shares outstanding end of year. . . . . . . . . . . . . 5,093,788 5,004,078 4,939,515 4,860,588 3,653,182
Registered common shareholders. . . . . . . . . . . . . 2,271 2,178 2,213 2,098 1,721
Cash dividends declared per share . . . . . . . . . . . $ 1.00 $ 0.97 $ 0.93 $ 0.90 $ 0.88
Dividend yield (annualized) . . . . . . . . . . . . . . 5.5% 4.7% 5.5% 6.2% 6.9%
Payout ratio from continuing operations (3) . . . . . . 95.2% 82.9% 58.9% 56.6% 71.5%
- --------------------------------------------------------------------------------------------------------------------------
ADDITIONAL DATA
- ---------------
Customers
Natural gas distribution and transmission . . . . . . 37,128 35,797 34,713 33,530 32,346
Propane distribution. . . . . . . . . . . . . . . . . 34,113 33,123 31,961 31,115 22,180
- --------------------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF). . . . . . . . . . . 21,400 23,297 24,835 29,260 22,728
Propane distribution (in thousands of gallons). . . . 25,979 26,682 29,975 26,184 18,395
- --------------------------------------------------------------------------------------------------------------------------
Heating degree-days (Delmarva Peninsula). . . . . . . . 3,704 4,430 4,717 4,594 4,398
Propane bulk storage capacity (in thousands of gallons) 1,890 1,866 1,860 1,818 1,230
Total employees (3) . . . . . . . . . . . . . . . . . . 431 397 338 335 320
- --------------------------------------------------------------------------------------------------------------------------
(1) The years 2002, 2001, 2000 and 1999 have been restated in order to reflect
the Company's Delaware and Maryland natural gas divisions on
the "accrual" rather than the "as billed" revenue recognition method.
(2) The years 1998, 1997, 1996, 1995 and 1994 have not been restated to reflect
the "accrual" revenue recognition method due to the
immateriality of the impact on the Company's financial results.
(3) These amounts exclude the results of water services due to their
reclassification to discontinued operations.
(4) 1994 has not been restated to include the business combinations with
Tri-County Gas Company, Inc., Tolan Water Service and Xeron, Inc.
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 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 temporarily to finance capital expenditures. During 2003, net cash provided
by operating activities was $22.0 million, cash used by investing activities was
$5.9 million and cash used by financing activities was $15.5 million. Cash
provided by operating activities declined by $2.4 million from 2002 to 2003, as
higher income in 2003 was more than offset by changes in working capital items.
Cash provided by operating activities increased by $8.9 million from 2001 to
2002, as increases in current liabilities and non-cash charges related to
goodwill impairment more than offset a decline in income.
The Company completed a private placement of $30.0 million of long-term debt 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, 2003, 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, 2003, Chesapeake had five unsecured bank lines of
credit with three financial institutions, totaling $65.0 million, for short-term
cash needs to meet seasonal working capital requirements and temporarily to fund
portions of its capital expenditures. Two of the bank lines, totaling $15.0
million, are 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, 2003 and 2002 were $3.5 million and $10.9 million, respectively. In
2003 and 2002, Chesapeake used funds provided by operations to fund net
investing and financing activities.
During 2003, 2002 and 2001, net cash used for investing activities totaled
approximately $5.9, $14.1 and $29.2 million, respectively. Cash used by
investing activities was down in 2003 compared to 2002, due to the combination
of reduced capital expenditures and cash provided by the sales of the water
businesses and recoveries of environmental costs. 2003 additions to property,
plant and equipment totaled $11.8 million and were primarily for natural gas
distribution ($7.5 million), propane distribution ($2.0 million) and natural gas
transmission ($1.8 million). The property, plant and equipment expenditures for
2002 were primarily for natural gas distribution ($8.1 million) and natural gas
transmission ($4.0 million). In both 2003 and 2002, 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 in 2001 were high primarily as a result of Eastern
Shore Natural Gas expenditures, totaling $16.0 million, related to a 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 increase in intangibles shown on the cash flow statement was
related to acquisitions of water companies.
Chesapeake has budgeted $20.9 million for capital expenditures during 2004. This
amount includes $15.8 million for natural gas distribution and transmission,
$4.1 million for propane distribution and marketing, $285,000 for advanced
information services and $614,000 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. The other category includes
general plant, computer software and hardware. Financing for the 2004 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 expects to incur approximately $170,000 in 2004 and $250,000 in 2005
for environmental-related expenditures. Additional expenditures may be required
in future years (see Note N 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, 2003, common equity represented 51.2 percent of total
capitalization, compared to 47.8 percent in 2002. Including short-term borrowing
and the current portion of long-term debt, the equity component of the Company's
capitalization would have been 48.8 percent and 43.3 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
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.
Chesapeake issued common stock in connection with its Automatic Dividend
Reinvestment and Stock Purchase Plan in the amounts of 51,125 shares in 2003,
49,782 shares in 2002 and 43,101 shares in 2001. Chesapeake also issued shares
of common stock totaling 43,245, 52,740 and 54,921 in 2003, 2002 and 2001,
respectively, for matching contributions for the Retirement Savings Plan.
Chesapeake repaid approximately $4.3 million and $3.8 million of long-term debt
in 2003 and 2002, respectively.
CONTRACTUAL OBLIGATIONS
We have the following contractual obligations and other commercial commitments
as of December 31, 2003:
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---------------------- PAYMENTS DUE BY PERIOD -----------------------
LESS THAN MORE THAN
CONTRACTUAL OBLIGATIONS 1 YEAR 1 - 3 YEARS 3 - 5 YEARS 5 YEARS TOTAL
- ----------------------------------------------------------------------------------------------------------
Long-term debt (1) $ 3,665,091 $ 7,818,182 $15,272,728 $45,752,636 $ 72,508,637
Operating leases (2) 870,914 1,223,288 387,242 199,200 2,680,644
Purchase obligations (3)
Transmission capacity 8,501,240 14,714,426 12,075,525 36,744,851 72,036,042
Storage - Natural Gas 1,562,022 2,825,202 2,752,481 8,395,586 15,535,291
Commodities 13,259,717 - - - 13,259,717
Forward contracts - Propane (4) 6,618,046 - - - 6,618,046
Unfunded benefits (5) 179,000 372,000 322,000 1,965,000 2,838,000
Funded benefits (6) 43,000 86,000 86,000 1,160,000 1,375,000
- ----------------------------------------------------------------------------------------------------------
Total Contractual Obligations $34,699,030 $27,039,098 $30,895,976 $94,217,273 $186,851,377
==========================================================================================================
(1) Principal payments on long-term debt, see Note I, "Long-Term Debt," in the
Notes to the Consolidated Financial Statements for additional
discussion of this item.
(2) See Note K, "Lease Obligations," in the Notes to the Consolidated Financial
Statements for additional discussion of this item.
(3) See Note O, "Other Commitments and Contingencies," in the Notes to the
Consolidated Financial Statements for further information.
(4) The Company has also entered into forward sale contracts of $7,356,527, see
"Market Risk" of the Management's Discussion and Analysis for
further information.
(5) The Company has recorded long-term liabilities of $2.8 million at December
31, 2003 for unfunded post-retirement benefit plans. The schedule
of cash outflows above is based on expected payments to current retirees
and assumes a retirement age of 65 for currently active employees.
There are many factors that would cause actual payments to differ from
these amounts, including early retirement, future health care costs that
differ from past experience and rates of return implicit in
calculations.
(6) The Company has recorded long-term liabilities of $1.4 million at December
31, 2003 for funded benefits. Of this total, $387,000 has been
funded using a Rabbi Trust and an asset in the same amount is recorded in
the Investments caption on the Balance Sheet. The other balance,
$988,000 represents a liability for a defined benefit pension plan.
The plan was closed to new participants on January 1, 1999 and
participants in the plan on that date were given the option to leave
the plan. See Note L, "Employee Benefit Plans," in the Notes to the
Consolidated Financial Statements for further information on the plan.
Since the plan modification, no additional funding has been required
From the Company and none is expected for the next five years,
based on factors in effect at December 31, 2003. However, this is subject
to change based on the actual return earned by the plan assets and
other actuarial assumptions, such as the discount rate, long-term expected
rate of return on plan assets and expected pay rate increases.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has issued corporate guarantees to certain vendors of its
propane wholesale marketing subsidiary. The corporate guarantees provide
for the payment of propane purchases by the subsidiary, in the case of the
subsidiary's default. The guarantees at December 31, 2003, totaled $4.5
million and expire on various dates in 2004.
The Company has issued a letter of credit to its main insurance company for
$694,000, which expires June 1, 2004.
RESULTS OF OPERATIONS
Net income from continuing operations for 2003 was $10.1 million compared to
restated net income of $7.5 million for 2002 and $7.3 million for 2001. Net
income for 2003 was $9.3 million or $1.66 per share compared to restated net
income of $3.7 million and $6.7 million in 2002 and 2001, respectively, and
restated earnings per share of $0.68 and $1.25 in 2002 and 2001, respectively.
During 2003, Chesapeake decided to exit the water services business and, at
December 31, 2003, had sold the assets of six of seven dealerships. The results
of water services have been reclassified to discontinued operations.
Discontinued operations experienced losses of $0.14, $0.34 and $0.12 per share
for 2003, 2002 and 2001, respectively. Chesapeake adopted Statement of Financial
Accounting Standards No. 142 "Goodwill and Other Intangible Assets" in 2002.
This resulted in a non-cash charge of $0.35 per share for goodwill impairment
recorded as the cumulative effect of a change in accounting principle.
The Company has restated its 2002 and 2001 financial statements in order to
reflect the results of its Delaware and Maryland natural gas divisions on the
"accrual" rather than the "as billed" revenue recognition method. This change
had an insignificant effect on the Company's annual results for the last three
years. Under the "as billed" method, revenues from customer sales are not
recognized until the meter is read and the amount of gas actually used is
billed. Under the "accrual" method, at the end of each period, the amount of gas
used is estimated and is recognized as revenue. The Company's Florida division
has historically used the "accrual" method in accordance with Florida Public
Service Commission ("PSC") requirements. The Delaware and Maryland divisions
have historically used the "as billed" method to recognize revenues consistent
with the rate-setting processes in those states. In order to consistently apply
the "accrual" method, the Company met separately with the staffs of the Delaware
and Maryland Public Service Commissions to determine the regulatory impact of
the change. Having determined that there is little to no impact, the Company has
conformed the revenue recognition method used in its Delaware and Maryland
divisions to the method used by its Florida division. In order to provide
comparable information, the Company has restated its 2002 and 2001 financial
statements to reflect the "accrual" revenue recognition method. As a result of
the restatement, retained earnings of the Company as of January 1, 2001 has
increased by $697,000 compared to previously reported amounts. The change had no
impact on basic earnings per share. There is no impact on fully diluted earnings
per share in 2002 and a $0.01 decrease in 2001. See Note A to the Consolidated
Financial Statements for further information on this change.
NET INCOME & BASIC EARNINGS PER SHARE SUMMARY
- ---------------------------------------------------------------------------------------------------------------------
2002 INCREASE 2002 2001 INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED (DECREASE) RESTATED RESTATED (DECREASE)
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME *
Continuing operations . . . . . . . . . $ 10,080 $ 7,535 $ 2,545 $ 7,535 $ 7,341 $ 194
Discontinued operations . . . . . . . . (788) (1,898) 1,110 (1,898) (649) (1,249)
Change in accounting principle. . . . . - (1,916) 1,916 (1,916) - (1,916)
- ---------------------------------------------------------------------------------------------------------------------
Total Net Income. . . . . . . . . . . . $ 9,292 $ 3,721 $ 5,571 $ 3,721 $ 6,692 ($2,971)
=====================================================================================================================
EARNINGS PER SHARE
Continuing operations . . . . . . . . . $ 1.80 $ 1.37 $ 0.43 $ 1.37 $ 1.37 $ 0.00
Discontinued operations . . . . . . . . (0.14) (0.34) 0.20 (0.34) (0.12) (0.22)
Change in accounting principle. . . . . - (0.35) 0.35 (0.35) - (0.35)
- ---------------------------------------------------------------------------------------------------------------------
Total Earnings Per Share. . . . . . . . $ 1.66 $ 0.68 $ 0.98 $ 0.68 $ 1.25 ($0.57)
=====================================================================================================================
* Dollars in thousands.
Improvement in Chesapeake's overall results is primarily related to strong
customer growth and colder weather, which led to increased contributions from
the Company's Delmarva natural gas and propane distribution operations. The
Delmarva natural gas operations experienced an increase of 6.4 percent in
residential customers. Weather, measured in heating degree-days, was 13 percent
colder than 2002. The Florida natural gas operations, propane wholesale
marketing operation and the advanced information services segment also improved
operating income compared to 2002. However, decreases in operating income for
the natural gas transmission operation and the Florida propane distribution
operation partially offset those improvements.
OPERATING INCOME SUMMARY (IN THOUSANDS)
- ---------------------------------------------------------------------------------------------------------------------
2002 INCREASE 2002 2001 INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED (DECREASE) RESTATED RESTATED (DECREASE)
- ---------------------------------------------------------------------------------------------------------------------
BUSINESS SEGMENT:
Natural gas distribution & transmission $ 16,653 $ 14,973 $ 1,680 $ 14,973 $ 14,405 $ 568
Propane . . . . . . . . . . . . . . . . 3,875 1,052 2,823 1,052 913 139
Advanced information services . . . . . 692 343 349 343 517 (174)
Other & eliminations. . . . . . . . . . 359 237 122 237 386 (149)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL OPERATING INCOME. . . . . . . . . $ 21,579 $ 16,605 $ 4,974 $ 16,605 $ 16,221 $ 384
- ---------------------------------------------------------------------------------------------------------------------
During 2002, operating income increased over 2001 levels 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
partially offset by declines in the advanced information services and other
segments. The advanced information services segment was adversely affected by a
slowdown in the information technology services sector.
The following discussions of segment results include use of the term "gross
margin." Gross margin is determined by deducting the cost of sales from
operating revenue. Cost of sales includes the purchased gas cost for natural gas
and propane and the cost of labor spent on direct revenue-producing activities
for advanced information services. This should not be considered an alternative
to operating income or net income, which are determined in accordance with
generally accepted accounting principles ("GAAP"). Chesapeake believes that
gross margin, although a non-GAAP measure, is useful and meaningful to investors
because it provides them with valuable information that demonstrates the
profitability achieved by the Company under its allowed rates for regulated
operations and under its competitive pricing structure for non-regulated
segments, as another criteria in making investment decisions. Chesapeake's
management uses gross margin in measuring certain performance goals and has
historically analyzed and reported gross margin information publicly. Other
companies may calculate gross margin in a different manner.
NATURAL GAS DISTRIBUTION AND TRANSMISSION
The natural gas distribution and transmission segment earned operating
income of $16.7 million for 2003 compared to restated operating income of
$15.0 million for the corresponding period last year, an increase of $1.7
million.
NATURAL GAS DISTRIBUTION AND TRANSMISSION (IN THOUSANDS)
- ---------------------------------------------------------------------------------------------------------------------
2002 INCREASE 2002 2001 INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED (DECREASE) RESTATED RESTATED (DECREASE)
- ---------------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 110,247 $ 93,588 $ 16,659 $ 93,588 $ 107,418 ($13,830)
Cost of gas . . . . . . . . . . . . . . 65,434 52,735 12,699 52,735 70,112 (17,377)
- ---------------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 44,813 40,853 3,960 40,853 37,306 3,547
Operations & maintenance. . . . . . . . 19,954 18,047 1,907 18,047 15,980 2,067
Depreciation & amortization . . . . . . 5,188 5,050 138 5,050 4,389 661
Other taxes . . . . . . . . . . . . . . 3,018 2,783 235 2,783 2,532 251
- ---------------------------------------------------------------------------------------------------------------------
Operating expenses. . . . . . . . . . . 28,160 25,880 2,280 25,880 22,901 2,979
- ---------------------------------------------------------------------------------------------------------------------
TOTAL OPERATING INCOME. . . . . . . . . $ 16,653 $ 14,973 $ 1,680 $ 14,973 $ 14,405 $ 568
- ---------------------------------------------------------------------------------------------------------------------
Revenue and cost of gas increased in 2003 compared to 2002 and decreased in
2002 compared to 2001, due primarily to changes in natural gas commodity
costs. 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 affected by 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 purchased both the
commodity and transportation service from the Company, to purchasing
transportation service only.
Gross margins for the Delaware and Maryland distribution divisions
increased $2.7 million in 2003 over 2002. Temperatures in 2003 were 13
percent colder than 2002 (554 heating degree-days) and 7 percent colder
than the 10-year average (306 heating degree-days). The Company estimates
that, on an annual basis, for each heating degree-day variance from the
10-year average, gross margins change by $1,680. An increase in the average
number of customers also contributed to the increase. Delaware and Maryland
experienced an increase of 1,923 in the average number of residential
customers, or 6.4 percent, in 2003 compared to the same period in 2002. The
Company estimates that each residential customer added contributes $360
annually to gross margin and requires an additional cost of $100 for
operations and maintenance expenses. Also contributing to the increased
margins were rate increases in Delaware that were effective in December
2002 and volumetric increases for existing customers.
Gross margin for the Florida distribution operations increased $1.2
million, due to the implementation of transportation services for
residential customers and customer additions. Residential customer growth
reached 4.4 percent in Florida, an increase of 434 customers. Agreements
with two new industrial customers also helped increase margins.
Margins for the transmission operation increased by $219,000 in 2003
compared to 2002. An increase in interruptible transportation margins and
volume added through a system expansion completed in November 2002 were
partially offset by a rate reduction that was effective December 2002. The
rate agreement is more fully discussed in the section below captioned
"Regulatory Matters."
The natural gas margin increases were partially offset by higher operating
expenses, primarily operations and maintenance expenses and other taxes
that relate to the increased volumes and earnings and pension and employee
costs.
The natural gas distribution and transmission segment increased operating
income to $15.0 million for 2002 compared to restated operating income of
$14.4 million for 2001, an increase of $568,000. Restated 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. This system expansion
increased margins by approximately $2.2 million per year. 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. This decline was more
than offset by residential customer growth of 1,838, or 6.5 percent, and a
rate increase in Delaware. 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.
PROPANE
The propane segment experienced an increase in operating income of $2.8
million, or 268 percent over 2002. Gross margin increased $3.1 million,
with an increase of only $230,000 in operating expenses.
PROPANE (IN THOUSANDS)
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INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 (DECREASE) 2002 2001 (DECREASE)
- ---------------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 39,760 $ 28,124 $ 11,636 $ 28,124 $ 35,742 ($7,618)
Cost of sales . . . . . . . . . . . . . 22,256 13,673 8,583 13,673 21,168 (7,495)
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Gross Margin. . . . . . . . . . . . . . 17,504 14,451 3,053 14,451 14,574 (123)
Operations & maintenance. . . . . . . . 11,290 11,053 237 11,053 11,459 (406)
Depreciation & amortization . . . . . . 1,506 1,603 (97) 1,603 1,465 138
Other taxes . . . . . . . . . . . . . . 833 743 90 743 737 6
- ---------------------------------------------------------------------------------------------------------------------
Operating expenses. . . . . . . . . . . 13,629 13,399 230 13,399 13,661 (262)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL OPERATING INCOME. . . . . . . . . $ 3,875 $ 1,052 $ 2,823 $ 1,052 $ 913 $ 139
- ---------------------------------------------------------------------------------------------------------------------
The increases in revenues and cost of sales in 2003 compared to 2002 were
caused both by increases in volumes and by increases in the commodity costs
of propane. Commodity costs changes are generally passed on to the
customer, subject to competitive market conditions. The margin increase for
the propane segment was due primarily to an increase of $2.9 million for
the Delmarva distribution operations. Volumes sold in 2003 increased 3.3
million gallons or 15 percent. Temperatures in 2003 were 13 percent colder
than 2002 (554 heating degree-days) and 7 percent colder than the 10-year
average (306 heating degree-days). The Company estimates that on an annual
basis, for each heating degree-day variance from the 10-year average,
margins change by $1,670. Additionally, the margin per retail gallon
improved by $0.0374 in 2003 compared to 2002. The margin increase was
partially offset by increased operating expenses, primarily related to the
higher volumes, such as delivery costs, and incentive compensation costs
associated with higher income. The Florida propane distribution operations
experienced an increase in margins of $102,000 in 2003; however, the
margins included $192,000 related to a non-recurring service project.
The Company's propane wholesale marketing operation experienced an increase
in margins of $51,000 and a decrease of $148,000 in operating expenses,
leading to an improvement of $199,000 in operating income. Wholesale price
volatility created trading opportunities during some portions of the year;
however, these were partially offset by reduced trading activities
particularly during the third quarter. Cost savings, primarily reduced
taxes on propane inventory, have also helped to improve operating income
for the period.
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 revenues and
costs were lower by $7.6 million and $7.5 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 Delmarva distribution operations experienced an increase of $624,000 in
gross margin in 2002. 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.
Operating expenses decreased by $249,000 resulting from cost containment
efforts that began in April 2001 and remain in effect. These efforts have
reduced customer accounting, sales and marketing costs. Other costs, such
as delivery expenses, decreased due to the lower volumes sold. The
operating income of the Florida propane operation increased by $195,000 in
2002. Margins increased $441,000, but were partially offset by an increase
of $246,000 in operating expenses.
ADVANCED INFORMATION SERVICES
The advanced information services segment provides domestic and
international clients with information technology related business services
and solutions for both enterprise and e-business applications. The advanced
information services business earned operating income of $692,000 in 2003
compared to $343,000 in 2002.
ADVANCED INFORMATION SERVICES (IN THOUSANDS)
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INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 (DECREASE) 2002 2001 (DECREASE)
- ---------------------------------------------------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . . $ 12,578 $ 12,764 ($186) $ 12,764 $ 14,104 ($1,340)
Cost of sales . . . . . . . . . . . . . 7,018 6,700 318 6,700 7,385 (685)
- ---------------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 5,560 6,064 (504) 6,064 6,719 (655)
Operations & maintenance. . . . . . . . 4,196 4,940 (744) 4,940 5,361 (421)
Depreciation & amortization . . . . . . 191 208 (17) 208 256 (48)
Other taxes . . . . . . . . . . . . . . 481 573 (92) 573 585 (12)
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Operating expenses. . . . . . . . . . . 4,868 5,721 (853) 5,721 6,202 (481)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL OPERATING INCOME. . . . . . . . . $ 692 $ 343 $ 349 $ 343 $ 517 ($174)
- ---------------------------------------------------------------------------------------------------------------------
Revenues continued to decline in 2003; however, at a rate that was less
than 2002. The revenue decline was more than offset by reduced operating
costs, primarily payroll and benefits. A non-recurring sale of software
contributed $302,000 to operating income in 2003.
During 2002, this segment was adversely affected by the nation's economic
slowdown as discretionary consulting projects were postponed or cancelled.
Lower revenues in 2002 were partially offset by reductions in the cost of
sales and in operating expenses, principally sales and marketing.
OTHER OPERATIONS AND ELIMINATIONS
The other operations segment consists of subsidiaries that own real estate
leased to other Chesapeake subsidiaries. Eliminations are entries required
to eliminate activities between business segments from the consolidated
results.
OTHER OPERATIONS & ELIMINATIONS (IN THOUSANDS)
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INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 (DECREASE) 2002 2001 (DECREASE)
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Revenue . . . . . . . . . . . . . . . . $ 702 $ 717 ($15) $ 717 $ 783 ($66)
Cost of sales . . . . . . . . . . . . . - - - - - -
- ---------------------------------------------------------------------------------------------------------------------
Gross Margin. . . . . . . . . . . . . . 702 717 (15) 717 783 (66)
Operations & maintenance. . . . . . . . 80 84 (4) 84 107 (23)
Depreciation & amortization . . . . . . 238 233 5 233 233 -
Other taxes . . . . . . . . . . . . . . 55 57 (2) 57 57 -
- ---------------------------------------------------------------------------------------------------------------------
Pre-tax operating expenses. . . . . . . 373 374 (1) 374 397 (23)
- ---------------------------------------------------------------------------------------------------------------------
Operating Income Other. . . . . . . . . $ 329 $ 343 ($14) $ 343 $ 386 ($43)
Operating Income Eliminations . . . . . $ 30 ($106) $ 136 ($106) $ 0 ($106)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL OPERATING INCOME. . . . . . . . . $ 359 $ 237 $ 122 $ 237 $ 386 ($149)
- ---------------------------------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS
In 2003, Chesapeake decided to exit the water services business. Six of
seven water dealerships were sold during 2003. A net gain of $12,000,
after-tax, was recorded in 2003 for the sale of the assets. The Company
expects to dispose of the remaining operation of during 2004. Accordingly,
the assets were recorded at their fair value. The results of the water
companies' operations for all periods presented in the consolidated income
statements have been reclassified to discontinued operations and shown net
of tax. Losses from discontinued operations were $800,000, $1.9 million and
$649,000 for 2003, 2002 and 2001, respectively. The 2002 loss included a
non-cash impairment charge of $973,000 (after-tax) related to goodwill.
INCOME TAXES
Operating income taxes increased in 2003 compared to 2002, due to increased
income. The effective federal income tax rate for both years was 34 percent.
Operating income taxes were lower in 2002 compared to 2001, due to the decrease
in operating income and a lowering of the effective federal income tax rate from
35 percent to 34 percent in 2002. During both 2003 and 2002, the Company
benefited from a change in the tax law that allows tax deductions for dividends
paid on Company stock held in Employee Stock Ownership Plans ("ESOP").
OTHER INCOME
Other income was $238,000, $495,000 and $694,000 for the years 2003, 2002 and
2001, respectively. This includes interest income, earned primarily on
regulatory assets, and gains from the sale of plant assets.
INTEREST EXPENSE
In 2002, approximately $103,000 of interest expense was associated with
discontinued operations and has therefore been reclassified on the income
statement. Total interest expense for 2003 increased approximately $648,000, or
13 percent, over 2002. The increase reflects the increase in the average
long-term debt balance caused by the placement of $30.0 million completed in
October 2002. The average long-term debt balance during 2003 was $75.4 million
with an average interest rate of 7.24 percent, compared to $54.6 million with an
average interest rate of 7.52 percent in 2002. The increase in long-term debt
was partially offset by a reduction in the average short-term borrowing balance,
which decreased from $29.4 million in 2002 to $3.5 million in 2003. The average
interest rate for short-term borrowing increased slightly from 2.35 percent for
2002 to 2.40 percent for 2003.
In the years 2002 and 2001, interest expense associated with discontinued
operations was approximately $103,000 and $269,000, respectively. Those amounts
have been reclassified to discontinued operations on the income statement. Total
interest expense for 2002 decreased approximately $222,000, or 4 percent, over
the same period in 2001. The decrease was due primarily to a reduction in the
average interest rate for short-term borrowing from 4.43 percent on an average
balance of $26.9 million in 2001 to 2.35 percent on an average balance of $29.4
million for the same period in 2002. Interest on long-term debt partially offset
the short-term savings, due to an increase in the average balance outstanding
from $52.4 million in 2001 to $54.6 million in 2002. However, the average
long-term interest rate declined from 7.64 percent to 7.52 percent, offsetting a
portion of the increase related to higher balances.
CRITICAL ACCOUNTING POLICIES
Chesapeake's reported financial condition and results of operations are affected
by the accounting methods, assumptions and estimates that are used in the
preparation of the Company's financial statements. However, because most of
Chesapeake's businesses are regulated, the accounting methods used by Chesapeake
must comply with the requirements of the regulatory bodies; therefore, the
choices available are, in many cases, limited by these regulatory requirements.
Management believes that the following policies require significant estimates or
other judgments of matters that are inherently uncertain. These policies have
been discussed with the Audit Committee of Chesapeake.
REGULATORY ASSETS AND LIABILITIES
Chesapeake records certain assets and liabilities in accordance with SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation." Costs
are deferred when there is a probable expectation that they will be
recovered in future revenues as a result of the regulatory process. At
December 31, 2003, Chesapeake had recorded regulatory assets of $3.1
million, including $661,000 for underrecovered purchased gas costs and
$717,000 for environmental costs. The Company has recorded regulatory
liabilities for accrued asset removal cost and self-insurance of $13.5
million and $1.3 million, respectively, at December 31, 2003. If the
Company were required to terminate application of SFAS No. 71, it would be
required to recognize all such deferred amounts as a charge to earnings,
net of applicable income taxes. Such a charge could have a material adverse
effect on the Company's results of operations.
GOODWILL IMPAIRMENT
In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets",
Chesapeake no longer amortizes goodwill. Instead, goodwill is tested for
impairment. The initial test was performed upon adoption of SFAS No. 142 on
January 1, 2002, and again at the end of 2002 and 2003. These tests were
based on subjective measurements, including discounted cash flows of
expected future operating results and market valuations of similar
businesses. Those tests indicated that the goodwill associated with the
water business was impaired and charges totaling $4.7 million (pre-tax)
were recorded in 2002. At December 31, 2003, no goodwill remained related
to the water companies. Goodwill is tested annually and when events change.
VALUATION OF ENVIRONMENTAL ASSETS AND LIABILITIES
As more fully described in Note N to the Financial Statements, Chesapeake
has completed its responsibilities related to one environmental site and is
currently participating in the investigation, assessment or remediation of
three other former gas manufacturing plant sites. Amounts have been
recorded as environmental liabilities and associated environmental
regulatory assets based on estimates of future costs provided by
independent consultants. There is uncertainty in these amounts because the
Environmental Protection Agency ("EPA") or state authority may not have
selected the final remediation methods. Additionally, there is uncertainty
due to the outcome of legal remedies sought from other potentially
responsible parties. At December 31, 2003, Chesapeake had recorded
environmental regulatory assets of $717,000 and a liability for
environmental costs of $562,000.
PROPANE WHOLESALE MARKETING CONTRACTS
Chesapeake's propane wholesale marketing operation enters into forward and
futures contracts that are considered derivatives under SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." In
accordance with the pronouncement, open positions are marked to market
prices at the end of each reporting period and unrealized gains or losses
are recorded in the Consolidated Statement of Income. The contracts all
mature within one year, and are almost exclusively for propane commodities
with delivery points of Mt. Belvieu, Texas and Hattiesburg, Mississippi.
Management estimates the market valuation based on reference to
exchange-traded futures prices, historical differentials and actual trading
activity at the end of the reporting period. At December 31, 2003 and 2002,
these contracts had net unrealized gains of $172,000 and $630,000,
respectively.
OPERATING REVENUES
Revenues for the natural gas distribution operations of the Company are
based on rates approved by the various public service commissions. The
natural gas transmission operation revenues are based on rates approved by
the Federal Energy Regulatory Commission ("FERC"). Customers' base rates
may not be changed without formal approval by these commissions. However,
the regulatory authorities have granted the Company's regulated natural gas
distribution operations the ability to negotiate rates with customers that
have competitive alternatives using approved methodologies. In addition,
the natural gas transmission operations can negotiate rates above or below
the FERC approved tariff rates.
Chesapeake's natural gas distribution operations each have a gas cost
recovery mechanism that provides for the adjustment of rates charged to
customers as gas costs fluctuate. These amounts are collected or refunded
through adjustments to rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution's
industrial interruptible customers to make them competitive with
alternative types of fuel. Based on pricing, these customers can choose
natural gas or alternative types of supply. Neither the Company nor the
interruptible customer is contractually obligated to deliver or receive
natural gas.
In 2003 Chesapeake changed the revenue recognition method for its Delaware
and Maryland natural gas distribution divisions to conform to its Florida
division. See Note A to the Consolidated Financial Statements for further
information.
The propane marketing operation records trading activity net, on a
mark-to-market basis for open contracts. The propane distribution, advanced
information services and other segments record revenue in the period the
products are delivered and/or services are rendered.
REGULATORY ACTIVITIES
The Company's natural gas distribution operations are subject to regulation by
the Delaware, Maryland and Florida Public Service Commissions. The natural gas
transmission operation is subject to regulation by the FERC.
On August 2, 2001, the Delaware division filed a general rate increase
application with the Delaware Public Service Commission ("PSC"). Interim rates,
subject to refund, went into effect on October 1, 2001. The PSC approved a
settlement agreement for Phase I of the Rate Increase Application in April 2002.
Phase I resulted in an increase in rates of approximately $380,000 per year.
Phase II of the filing was approved by the Delaware PSC in November 2002. It
resulted in an additional increase in rates of approximately $90,000. Phase II
also reduces the Company's sensitivity to weather by changing the minimum
customer charge and the margin sharing arrangement for interruptible sales, off
system sales and capacity release income.
On October 31, 2001, Eastern Shore filed a rate change with the FERC pursuant to
the requirements of the Stipulation and Agreement dated August 1, 1997.
Following settlement conferences held in May 2002, the parties reached a
settlement in principle on or about May 23, 2002, to resolve all issues related
to its rate case.
The Offer of Settlement and the Stipulation and Agreement were finalized and
filed with the FERC on August 2, 2002. The agreement provided for a reduction in
rates of approximately $456,000 on an annual basis. On October 10, 2002, the
FERC issued an Order approving the Offer of Settlement and the Stipulation and
Agreement. Settlement rates went into effect on December 1, 2002.
During October 2002, Eastern Shore filed for recovery of gas supply realignment
costs associated with the implementation of FERC Order No. 636. The costs
totaled $196,000 (including interest). At that time, the FERC would not review
Eastern Shore's filing, because the FERC wished to settle a related matter with
another transmission company first. The other transmission company submitted a
filing on December 5, 2003. The FERC has not yet acted on the filing. Eastern
Shore will resubmit its transition cost recovery filing immediately upon
learning of FERC's approval.
On December 16, 2003, Eastern Shore filed revised tariff sheets to implement
revisions to its Fuel Retention and Cash Out provisions. These became effective
January 15, 2004. The proposed tariff revisions permit Eastern Shore to
incorporate its Deferred Gas Required for Operations amounts into the
calculation of its annual Fuel Retention percentage adjustment and to implement
a surcharge, effective July 1 of each year, to recover cash-out amounts. The
FERC accepted Eastern Shore's revised tariff sheets on January 15, 2004, subject
to certain revisions to clarify the tariff sheets. On January 30, 2004, Eastern
Shore submitted the revised tariff sheets.
On March 29, 2002, the Florida division filed tariff revisions with the Florida
PSC to complete the unbundling process by requiring all customers, including
residential, to migrate to transportation service and authorized the Florida
division to exit the merchant function. Transportation services were already
available to all nonresidential customers. On November 5, 2002, the Florida PSC
approved the Company's request for the first phase of the unbundling process as
a pilot program for a minimum two-year period. The Company has implemented the
program. As a part of this pilot program, the Company submitted several filings
during 2003 to address transition costs, the disposition of the unrecovered gas
cost balances, the implementation of the operational balancing account and the
level of base rates. On July 15, 2003, the Florida PSC approved a rate
restructuring proposed by Chesapeake. The restructuring created three new low
volume rate classes, with customer charge levels that ensure that all customers
receive benefits from the unbundling. On January 4, 2004, the Florida PSC
authorized the refund of the remaining balance in the PGA account, totaling
$246,000.
ENVIRONMENTAL MATTERS
The Company has completed its responsibilities related to the Dover Gas Light
site and continues to work with federal and state environmental agencies to
assess the environmental impact and explore corrective action at three other
environmental sites (see Note N to the Consolidated Financial Statements). The
Company believes that future costs associated with these sites will be
recoverable in rates or through sharing arrangements with, or contributions by,
other responsible parties.
MARKET RISK
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Long-term debt is subject to potential losses based on the
change in interest rates. The Company's long-term debt consists of first
mortgage bonds, senior notes and convertible debentures (see Note I to the
Consolidated Financial Statements for annual maturities of consolidated
long-term debt). All of Chesapeake's long-term debt is fixed-rate debt and was
not entered into for trading purposes. The carrying value of the Company's
long-term debt, including current maturities, was $73.1 million at December 31,
2003, as compared to a fair value of $80.9 million, based mainly on current
market prices or discounted cash flows using current rates for similar issues
with similar terms and remaining maturities. The Company is exposed to changes
in interest rates as a result of financing through its issuance of fixed-rate
long-term debt. The Company evaluates whether to refinance existing debt or
permanently finance existing short-term borrowing based in part on the
fluctuation in interest rates.
The Company's propane distribution business is exposed to market risk as a
result of propane storage activities and entering into fixed price contracts for
supply. The Company can store up to approximately four million gallons of
propane (including leased storage and rail cars) during the winter season to
meet its customers' peak requirements and to serve metered customers. Decreases
in the wholesale price of propane may cause the value of stored propane to
decline. To mitigate the impact of price fluctuations, the Company has adopted a
Risk Management Policy that allows the propane distribution operation to enter
into fair value hedges of its inventory. At December 31, 2003, the propane
distribution operation had entered into contracts to hedge 2.6 million gallons
of propane inventory.
The propane wholesale marketing operation is a party to natural gas liquids
("NGL") forward contracts, primarily propane contracts, with various third
parties. These contracts require that the propane marketing operation purchase
or sell NGL at a fixed price at fixed future dates. At expiration, the contracts
are settled by the delivery of NGL to the Company or the counter party or
booking out the transaction (booking out is a procedure for financially settling
a contract in lieu of the physical delivery of energy). The propane wholesale
marketing operation also enters into futures contracts that are traded on the
New York Mercantile Exchange. In certain cases, the futures contracts are
settled by the payment of a net amount equal to the difference between the
current market price of the futures contract and the original contract price.
The forward and futures contracts are entered into for trading and wholesale
marketing purposes. The propane wholesale marketing operation is subject to
commodity price risk on its open positions to the extent that market prices for
NGL deviate from fixed contract settlement amounts. Market risk associated with
the trading of futures and forward contracts are monitored daily for compliance
with Chesapeake's Risk Management Policy, which includes volumetric limits for
open positions. To manage exposures to changing market prices, open positions
are marked up or down to market prices and reviewed by oversight officials on a
daily basis. Additionally, the Risk Management Committee reviews periodic
reports on market and credit risk, approves any exceptions to the Risk
Management Policy (within the limits established by the Board of Directors) and
authorizes the use of any new types of contracts. Quantitative information on
the forward and futures contracts at December 31, 2003 and 2002 is shown in the
following chart.
- -------------------------------------------------------------------------
QUANTITY ESTIMATED WEIGHTED AVERAGE
AT DECEMBER 31, 2003 IN GALLONS MARKET PRICES CONTRACT PRICES
- -------------------------------------------------------------------------
FORWARD CONTRACTS
Sale . . . . . . . . 11,956,200 $ 0.6650 - $0.6900 $ 0.6153
Purchase . . . . . . 10,876,000 $ 0.6650 - $0.6900 $ 0.6085
FUTURES CONTRACTS
Sale . . . . . . . . 200,000 $ 0.6650 - $0.6675 $ 0.6675
- -------------------------------------------------------------------------
Estimated market prices and weighted average contract prices
are in dollars per gallon.
All contracts expire in 2004.
- -------------------------------------------------------------------------
QUANTITY ESTIMATED WEIGHTED AVERAGE
AT DECEMBER 31, 2002 IN GALLONS MARKET PRICES CONTRACT PRICES
- -------------------------------------------------------------------------
FORWARD CONTRACTS
Sale . . . . . . . . 7,291,200 $ 0.5200 - $0.5700 $ 0.5349
Purchase . . . . . . 4,515,000 $ 0.5200 - $0.5700 $ 0.5001
FUTURES CONTRACTS
Sale . . . . . . . . 1,764,000 $ 0.5200 - $0.5400 $ 0.5449
- -------------------------------------------------------------------------
Estimated market prices and weighted average contract prices
are in dollars per gallon.
All contracts expire in 2003.
The Company's natural gas distribution operations have entered into agreements
with natural gas suppliers to purchase natural gas for resale to their
customers. Purchases under these contracts are considered "normal purchases and
sales" under SFAS No. 133 and are not marked to market.
COMPETITION
The Company's natural gas operations compete with other forms of energy
including electricity, oil and propane. The principal competitive factors are
price, and to a lesser extent, accessibility. The Company's natural gas
distribution operations have several large volume industrial customers that have
the capacity to use fuel oil as an alternative to natural gas. When oil prices
decline, these interruptible customers convert to oil to satisfy their fuel
requirements. Lower levels in interruptible sales occur when oil prices are
lower relative to the price of natural gas. Oil prices, as well as the prices of
electricity and other fuels are subject to fluctuation for a variety of reasons;
therefore, future competitive conditions are not predictable. To address this
uncertainty, the Company uses flexible pricing arrangements on both the supply
and sales side of its business to maximize sales volumes. As a result of the
transmission business' conversion to open access, this business has shifted from
providing competitive sales service to providing transportation and contract
storage services.
The Company's natural gas distribution operations located in Delaware, Maryland
and Florida offer transportation services to certain industrial customers. In
2001, the Florida operation extended transportation service to commercial
customers and, in 2002, to residential customers. With transportation service
now available on the Company's distribution systems, the Company is competing
with third party suppliers to sell gas to industrial customers. As it relates to
transportation services, the Company's competitors include the interstate
transmission company if the distribution customer is located close enough to the
transmission company's pipeline to make a connection economically feasible. The
customers at risk are usually large volume commercial and industrial customers
with the financial resources and capability to bypass the distribution
operations in this manner. In certain situations, the distribution operations
may adjust services and rates for these customers to retain their business. The
Company expects to continue to expand the availability of transportation service
to additional classes of distribution customers in the future. The Company
established a natural gas sales and supply operation in Florida in 1994 to
compete for customers eligible for transportation services.
The Company's propane distribution operations compete with several other
propane distributors in their service territories, primarily on the basis of
service and price, 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.
The propane wholesale marketing operation competes against various marketers,
many of which have significantly greater resources and are able to obtain price
or volumetric advantages.
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. This segment
competes on the basis of technological expertise, reputation and price.
INFLATION
Inflation affects the cost of labor, products and services required for
operation, maintenance and capital improvements. While the impact of inflation
has remained low in recent years, natural gas and propane prices are subject to
rapid fluctuations. Fluctuations in natural gas prices are passed on to
customers through the gas cost recovery mechanism in the Company's tariffs. To
help cope with the effects of inflation on its capital investments and returns,
the Company seeks rate relief from regulatory commissions for regulated
operations while monitoring the returns of its unregulated business operations.
To compensate for fluctuations in propane gas prices, Chesapeake adjusts its
propane selling prices to the extent allowed by the market.
RECENT PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") adopted SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities" in June 2002,
which requires that a liability for a cost associated with an exit or disposal
activity be recognized when a liability is incurred. Under previous guidelines,
a liability for an exit cost was recognized at the date of an entity's
commitment to an exit plan. This statement was effective for exit or disposal
activities initiated on January 1, 2003 or thereafter and had no effect on the
Company during 2003.
FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," was adopted in November 2002. The Company has adopted FIN No. 45. There
was no impact on the financial statements; however, the disclosures in the
Commitments and Contingencies footnote (Note O) were expanded to include
additional disclosures required by the pronouncement.
In December 2003, the FASB issued FIN No. 46R, "Consolidation of Variable
Interest Entities," which replaced FIN No. 46, "Consolidation of Variable
Interest Entities," issued in January 2003. FIN No. 46R was issued to replace
FIN No. 46 and to clarify the required accounting for interests in variable
interest entities. A variable interest entity is an entity that does not have
sufficient equity investment at risk, or the holders of the equity instruments
lack the essential characteristics of a controlling financial interest. A
variable interest entity is to be consolidated by a company if that company is
subject to a majority of the risk of loss from the variable interest entity's
activities, or is entitled to receive a majority of the entity's residual
returns, or both. As of December 31, 2003, the Company did not have any variable
interests in a variable interest entity.
Chesapeake adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
in 2003. See Note B for additional information on the impact.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." This had no impact on the Company's
financial position or results of operations. The Company continues to apply the
intrinsic value method in accounting for stock-based employee compensation
permitted by Accounting Principles Board Opinion No. 25 and SFAS No. 123. For
each of the periods presented in the consolidated statement of income, no
stock-based compensation expense was recorded as no new stock options were
issued during those periods.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This statement amends and
clarifies financial accounting and reporting for derivative instruments and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities" by requiring that contracts with comparable
characteristics be accounted for similarly. The adoption of SFAS No. 149 did not
have a material impact on Chesapeake's financial position or results of
operations.
On August 13, 2003, the FASB ratified the Emerging Issues Task Force ("EITF")
Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative Instruments
That Are Subject to FASB Statement No. 133 and Not 'Held for Trading Purposes'
as Defined in EITF Issue No. 02 - 3." This did not have any effect on the
Company's financial position or results of operations.
On January 12, 2004, the FASB released FASB Staff Position No. FAS 106-1
"Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003." The Company has elected to
defer the accounting for the Act, as allowed under Staff Position No. 106-1. See
Note L for required disclosures.
CAUTIONARY STATEMENT
Chesapeake has made statements in this report that are considered to be
forward-looking statements. These statements are not matters of historical fact.
Sometimes they contain words such as "believes," "expects," "intends," "plans,"
"will," or "may," and other similar words of a predictive nature. These
statements relate to matters such as customer growth, changes in revenues or
margins, capital expenditures, environmental remediation costs, regulatory
approvals, market risks associated with the Company's propane marketing
operation, competition and other matters. It is important to understand that
these forward-looking statements are not guarantees but are subject to certain
risks and uncertainties and other important factors that could cause actual
results to differ materially from those in the forward-looking statements. These
factors include, among other things:
o the temperature sensitivity of the natural gas and propane businesses;
o the effect of spot, forward and futures market prices of natural gas and
propane on the Company's distribution, wholesale marketing and energy
trading businesses;
o the effects of competition on the Company's unregulated and regulated
businesses;
o the effect of changes in federal, state or local regulatory and tax
requirements, including deregulation;
o the effect of accounting changes;
o the effect of compliance with environmental regulations or the remediation
of environmental damage;
o the effects of general economic conditions on the Company and its
customers;
o the ability of the Company's new and planned facilities and acquisitions to
generate expected revenues; and
o the Company's ability to obtain the rate relief and cost recovery requested
from utility regulators and the timing of the requested regulatory actions.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information concerning quantitative and qualitative disclosure about market risk
is included in Item 7 under the heading "Management's Discussion and Analysis -
Market Risk."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
REPORT OF INDEPENDENT ACCOUNTANTS
________
To the Board of Directors and Stockholders of Chesapeake Utilities Corporation:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)(1) on page 64 present fairly, in all material
respects, the financial position of Chesapeake Utilities Corporation and its
subsidiaries at December 31, 2003 and 2002, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2003 in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 15(a)(2) on page 64 presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As described in Note A to the consolidated financial statements, the Company has
restated its December 31, 2002 and 2001 financial statements with respect to
utility unbilled revenue accounting matters.
As discussed in Note G to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets," in 2002. In addition, as discussed in Note B to the
consolidated financial statements, the Company adopted Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," in
2003.
/S/PRICEWATERHOUSECOOPERS LLP
- -----------------------------
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 19, 2004
CONSOLIDATED STATEMENTS OF INCOME
- ----------------------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------------------
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . $162,298,007 $134,142,530 $157,151,253
OPERATING EXPENSES
Cost of sales, excluding costs below. . . . . . . . . . . . 94,680,207 72,999,567 98,663,948
Operations. . . . . . . . . . . . . . . . . . . . . . . . . 32,823,830 31,368,621 30,263,403
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . 1,737,855 1,924,210 1,748,932
Depreciation and amortization . . . . . . . . . . . . . . . 7,089,837 7,089,190 6,342,412
Other taxes . . . . . . . . . . . . . . . . . . . . . . . . 4,386,878 4,156,263 3,911,557
- ------------------------------------------------------------- ------------- ------------- -------------
Total operating expenses. . . . . . . . . . . . . . . . . . . 140,718,607 117,537,851 140,930,252
- ----------------------------------------------------------------------------------------------------------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 21,579,400 $ 16,604,679 $ 16,221,001
Other Income. . . . . . . . . . . . . . . . . . . . . . . . . 238,439 494,904 694,441
- ----------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . . . . 21,817,839 17,099,583 16,915,442
Interest Charges. . . . . . . . . . . . . . . . . . . . . . . 5,705,911 4,955,022 5,010,516
- ----------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . 16,111,928 12,144,561 11,904,926
Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . 6,032,445 4,609,552 4,564,363
- ----------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS . . . . . . . . . . . . . . 10,079,483 7,535,009 7,340,563
- ----------------------------------------------------------------------------------------------------------
Income (Loss) from discontinued
operations, net of tax
Discontinued operations . . . . . . . . . . . . . . . . . (799,794) (1,897,837) (648,751)
Gain on sale. . . . . . . . . . . . . . . . . . . . . . . 12,187 - -
- ----------------------------------------------------------------------------------------------------------
Total loss from discontinued operations . . . . . . . . . . . (787,607) (1,897,837) (648,751)
- ----------------------------------------------------------------------------------------------------------
Cumulative Effect of Change in
Accounting Principle, net of tax. . . . . . . . . . . . . . - (1,916,000) -
- ----------------------------------------------------------------------------------------------------------
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,291,876 $ 3,721,172 $ 6,691,812
==========================================================================================================
EARNINGS PER SHARE OF COMMON STOCK:
Basic
From continuing operations. . . . . . . . . . . . . . . . . . $ 1.80 $ 1.37 $ 1.37
From discontinued operations. . . . . . . . . . . . . . . . . (0.14) (0.34) (0.12)
Effect of change in accounting principle. . . . . . . . . . . - (0.35) -
- ----------------------------------------------------------------------------------------------------------
Net Income. . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.66 $ 0.68 $ 1.25
==========================================================================================================
Diluted
From continuing operations. . . . . . . . . . . . . . . . . . $ 1.76 $ 1.37 $ 1.35
From discontinued operations. . . . . . . . . . . . . . . . . (0.13) (0.34) (0.12)
Effect of change in accounting principle. . . . . . . . . . . - (0.35) -
- ----------------------------------------------------------------------------------------------------------
Net Income. . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.63 $ 0.68 $ 1.23
==========================================================================================================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income. . . . . . . . . . . . . . . . . . . . . . . . . $ 9,291,876 $ 3,721,172 $ 6,691,812
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization . . . . . . . . . . . . . . 8,030,398 7,932,345 7,084,080
Depreciation and accretion included in other costs. . . . 2,467,582 2,490,799 1,908,978
Goodwill impairment . . . . . . . . . . . . . . . . . . . - 4,674,000 -
Deferred income taxes, net. . . . . . . . . . . . . . . . 2,397,594 263,826 475,901
Mark-to-market adjustments. . . . . . . . . . . . . . . . 457,901 (704,908) 906,551
Employee benefits and compensation. . . . . . . . . . . . 1,121,571 188,616 193,777
Other, net. . . . . . . . . . . . . . . . . . . . . . . . 15,874 34,571 197,475
Changes in assets and liabilities:
Accounts receivable, net. . . . . . . . . . . . . . . . . (3,565,363) (2,821,343) 17,193,931
Inventories, storage gas and materials. . . . . . . . . . (466,411) 311,668 1,117,052
Prepaid expenses and other current assets . . . . . . . . 226,455 (675,063) (293,836)
Other deferred charges. . . . . . . . . . . . . . . . . . 239,862 (347,671) (1,814,802)
Accounts payable, net . . . . . . . . . . . . . . . . . . 882,575 6,590,375 (19,103,097)
Refunds payable to customers. . . . . . . . . . . . . . . (291,260) (473,733) (43,553)
Income taxes receivable . . . . . . . . . . . . . . . . . 25,090 182,591 497,581
Accrued interest. . . . . . . . . . . . . . . . . . . . . (47,464) (1,058,570) 1,163,226
Accrued compensation. . . . . . . . . . . . . . . . . . . 762,629 (261,114) 313,625
Over (under) recovered deferred purchased gas costs . . . 102,666 3,606,075 358,779
Other current liabilities . . . . . . . . . . . . . . . . (192,996) 594,107 (1,083,994)
Other long-term liabilities . . . . . . . . . . . . . . . 521,870 141,358 (312,889)
- ----------------------------------------------------------------------------------------------------------
Net cash provided by operating activities . . . . . . . . . . 21,980,449 24,389,101 15,450,597
- ----------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant and equipment expenditures, net . . . . . . (11,790,364) (14,705,244) (27,414,426)
Change in intangibles . . . . . . . . . . . . . . . . . . . - 12,426 (2,208,699)
Sale of discontinued operations . . . . . . . . . . . . . . 3,732,649 - -
Environmental recoveries, net of expenditures . . . . . . . 2,193,318 631,750 437,319
- ----------------------------------------------------------------------------------------------------------
Net cash used by investing activities . . . . . . . . . . . . (5,864,397) (14,061,068) (29,185,806)
- ----------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Common stock dividends. . . . . . . . . . . . . . . . . . . (6,147,264) (6,016,052) (5,825,837)
Issuance of stock:
Dividend Reinvestment Plan optional cash. . . . . . . . . 347,546 266,638 191,765
Dividends reinvested by stockholders. . . . . . . . . . . 743,728 693,858 609,793
Retirement Savings Plan . . . . . . . . . . . . . . . . . 920,522 1,011,515 1,023,919
Conversion of debentures. . . . . . . . . . . . . . . . . 319,437 76,831 108,756
Net (repayments) borrowing under line of credit agreements. (7,384,742) (31,200,000) 16,700,000
Proceeds from issuance of long-term debt, net . . . . . . . - 29,918,850 300,000
Repayment of long-term debt . . . . . . . . . . . . . . . . (4,265,054) (3,809,732) (2,791,168)
- ----------------------------------------------------------------------------------------------------------
Net cash (used) provided by financing activities. . . . . . . (15,465,827) (9,058,092) 10,317,228
- ----------------------------------------------------------------------------------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . 650,225 1,269,941 (3,417,981)
CASH AND CASH EQUIVALENTS BEGINNING OF PERIOD . . . . . . . . 2,458,276 1,188,335 4,606,316
- ----------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS END OF PERIOD . . . . . . . . . . . $ 3,108,501 $ 2,458,276 $ 1,188,335
==========================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest. . . . . . . . . . . . . . . . . . . $ 5,648,332 $ 6,255,193 $ 4,128,477
Cash paid for income taxes. . . . . . . . . . . . . . . . . $ 3,767,816 $ 2,160,750 $ 3,601,400
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEETS
ASSETS
- --------------------------------------------------------------------------------------
2002
AT DECEMBER 31, 2003 RESTATED
- --------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Natural gas distribution and transmission . . . . . . $186,661,469 $178,082,794
Propane . . . . . . . . . . . . . . . . . . . . . . . 35,577,104 34,347,597
Advanced information services . . . . . . . . . . . . 1,396,595 1,475,060
Water services. . . . . . . . . . . . . . . . . . . . 762,383 4,603,745
Other plant . . . . . . . . . . . . . . . . . . . . . 8,796,305 9,062,339
- --------------------------------------------------------------------------------------
Total property, plant and equipment . . . . . . . . . . 233,193,856 227,571,535
Plus: Construction work in progress. . . . . . . . . 1,724,721 1,556,040
Less: Accumulated depreciation and amortization. . . (67,046,318) (62,281,788)
- --------------------------------------------------------------------------------------
Net property, plant and equipment . . . . . . . . . . . 167,872,259 166,845,787
- --------------------------------------------------------------------------------------
INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . 386,710 362,855
- --------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . 3,108,501 2,458,276
Accounts receivable (less allowance for uncollectibles
of $659,047 and $659,628, respectively). . . . . . . 30,689,597 27,343,754
Materials and supplies, at average cost . . . . . . . 923,556 995,165
Appliance and other inventory, at FIFO. . . . . . . . 173,044 1,193,585
Propane inventory, at average cost. . . . . . . . . . 3,387,535 4,028,878
Storage gas prepayments . . . . . . . . . . . . . . . 4,622,601 3,033,772
Underrecovered purchased gas costs. . . . . . . . . . 660,601 763,267
Income taxes receivable . . . . . . . . . . . . . . . 489,841 514,931
Prepaid expenses. . . . . . . . . . . . . . . . . . . 2,069,988 2,833,314
Other current assets. . . . . . . . . . . . . . . . . 768,958 755,682
- --------------------------------------------------------------------------------------
Total current assets. . . . . . . . . . . . . . . . . . 46,894,222 43,920,624
- --------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Environmental regulatory assets . . . . . . . . . . . 353,092 2,527,251
Environmental expenditures. . . . . . . . . . . . . . 364,088 2,557,406
Goodwill, net . . . . . . . . . . . . . . . . . . . . 674,451 869,519
Other intangible assets, net. . . . . . . . . . . . . 305,213 1,927,622
Long-term receivables . . . . . . . . . . . . . . . . 1,637,998 1,536,624
Other regulatory assets . . . . . . . . . . . . . . . 1,693,401 2,029,073
Other deferred charges. . . . . . . . . . . . . . . . 983,230 1,144,020
- --------------------------------------------------------------------------------------
Total deferred charges and other assets . . . . . . . . 6,011,473 12,591,515
- --------------------------------------------------------------------------------------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . $221,164,664 $223,720,781
======================================================================================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
- --------------------------------------------------------------------------------------
2002
AT DECEMBER 31, 2003 RESTATED
- --------------------------------------------------------------------------------------
CAPITALIZATION
Stockholders' equity
Common Stock, par value $.4867 per share;
(authorized 12,000,000 shares; issued and outstanding
5,660,594 and 5,537,710 shares, respectively) . . . $ 2,754,748 $ 2,694,935
Additional paid-in capital. . . . . . . . . . . . . . 34,176,361 31,756,983
Retained earnings . . . . . . . . . . . . . . . . . . 36,008,246 32,898,283
- --------------------------------------------------------------------------------------
Total stockholders' equity. . . . . . . . . . . . . . . 72,939,355 67,350,201
Long-term debt, net of current maturities . . . . . . . 69,415,545 73,407,684
- --------------------------------------------------------------------------------------
Total capitalization. . . . . . . . . . . . . . . . . . 142,354,900 140,757,885
- --------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt . . . . . . . . . . 3,665,091 3,938,006
Short-term borrowing. . . . . . . . . . . . . . . . . 3,515,258 10,900,000
Accounts payable. . . . . . . . . . . . . . . . . . . 21,997,413 21,141,996
Refunds payable to customers. . . . . . . . . . . . . 206,582 497,842
Customer deposits . . . . . . . . . . . . . . . . . . 2,008,379 2,007,983
Accrued interest. . . . . . . . . . . . . . . . . . . 652,367 699,831
Dividends payable . . . . . . . . . . . . . . . . . . 1,556,631 1,521,982
Deferred income taxes payable . . . . . . . . . . . . 119,814 49,714
Accrued compensation. . . . . . . . . . . . . . . . . 3,266,072 1,777,544
Other accrued liabilities . . . . . . . . . . . . . . 1,657,523 2,052,442
- --------------------------------------------------------------------------------------
Total current liabilities . . . . . . . . . . . . . . . 38,645,130 44,587,340
- --------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes . . . . . . . . . . . . . . . . 19,590,995 17,263,501
Deferred investment tax credits . . . . . . . . . . . 492,725 547,541
Environmental liability . . . . . . . . . . . . . . . 562,194 2,802,424
Accrued pension costs . . . . . . . . . . . . . . . . 2,015,128 1,619,456
Accrued asset removal cost. . . . . . . . . . . . . . 13,536,209 12,067,121
Other liabilities . . . . . . . . . . . . . . . . . . 3,967,383 4,075,513
- --------------------------------------------------------------------------------------
Total deferred credits and other liabilities. . . . . . 40,164,634 38,375,556
- --------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTES N AND O)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $221,164,664 $223,720,781
======================================================================================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- ----------------------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------------------
COMMON STOCK
Balance beginning of year . . . . . . . . . . . . . . . . . $ 2,694,935 $ 2,640,060 $ 2,577,992
Dividend Reinvestment Plan. . . . . . . . . . . . . . . . 24,888 24,229 20,977
Retirement Savings Plan . . . . . . . . . . . . . . . . . 21,047 25,669 26,730
Conversion of debentures. . . . . . . . . . . . . . . . . 9,144 2,199 3,117
Performance shares and options exercised. . . . . . . . . 4,734 2,778 11,244
- ----------------------------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . . . . . . . . . 2,754,748 2,694,935 2,640,060
- ----------------------------------------------------------------------------------------------------------
ADDITIONAL PAID-IN CAPITAL
Balance beginning of year . . . . . . . . . . . . . . . . . 31,756,983 29,653,992 27,672,005
Dividend Reinvestment Plan. . . . . . . . . . . . . . . . 1,066,386 936,268 780,582
Retirement Savings Plan . . . . . . . . . . . . . . . . . 899,475 985,846 997,187
Conversion of debentures. . . . . . . . . . . . . . . . . 310,293 74,632 105,639
Performance shares and options exercised. . . . . . . . . 143,224 106,245 98,579
- ----------------------------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . . . . . . . . . 34,176,361 31,756,983 29,653,992
- ----------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance beginning of year . . . . . . . . . . . . . . . . . 32,898,283 35,223,314 34,419,225
Net income. . . . . . . . . . . . . . . . . . . . . . . . 9,291,876 3,721,172 6,691,812
Cash dividends (1). . . . . . . . . . . . . . . . . . . . (6,181,913) (6,046,203) (5,887,723)
- ----------------------------------------------------------------------------------------------------------
Balance end of year . . . . . . . . . . . . . . . . . . . . 36,008,246 32,898,283 35,223,314
- ----------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY. . . . . . . . . . . . . . . . . . $ 72,939,355 $ 67,350,201 $ 67,517,366
==========================================================================================================
(1) Cash dividends declared per share for 2003, 2002 and 2001 were $1.10,
$1.10 and $1.095, respectively.
- ----------------------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------------------
COMMON STOCK SHARES ISSUED AND OUTSTANDING (2)
Balance beginning of year . . . . . . . . . . . . . . . . . 5,537,710 5,424,962 5,297,443
Dividend Reinvestment Plan (3). . . . . . . . . . . . . . 51,125 49,782 43,101
Sale of stock to the Company's Retirement Savings Plan. . 43,245 52,740 54,921
Conversion of debentures. . . . . . . . . . . . . . . . . 18,788 4,518 6,395
Performance shares and options exercised. . . . . . . . . 9,726 5,708 23,102
- ----------------------------------------------------------------------------------------------------------
Balance end of year (4) . . . . . . . . . . . . . . . . . . 5,660,594 5,537,710 5,424,962
==========================================================================================================
(2) 12,000,000 shares are authorized at a par value of $0.4867 per share.
(3) Includes dividends reinvested and optional cash payments.
(4) The Company had 47,659, 37,353, and 30,446 shares held in Rabbi Trusts
at December 31, 2003, 2002 and 2001, respectively.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF INCOME TAXES
- ----------------------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------------------
CURRENT INCOME TAX EXPENSE
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,732,101 $ 1,624,698 $ 3,204,526
State . . . . . . . . . . . . . . . . . . . . . . . . . . . 943,993 571,540 605,459
Investment tax credit adjustments, net. . . . . . . . . . . (54,816) (54,816) (54,815)
- ----------------------------------------------------------------------------------------------------------
Total current income tax expense. . . . . . . . . . . . . . . 3,621,278 2,141,422 3,755,170
- ----------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAX EXPENSE (1)
Property, plant and equipment . . . . . . . . . . . . . . . 1,855,131 3,742,415 769,264
Deferred gas costs. . . . . . . . . . . . . . . . . . . . . 105,846 (1,701,273) (48,426)
Pensions and other employee benefits. . . . . . . . . . . . (203,229) (139,861) (71,089)
Impairment of intangibles . . . . . . . . . . . . . . . . . 1,463,995 (1,785,160) 0
Environmental expenditures. . . . . . . . . . . . . . . . . (866,206) (404,659) (142,362)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . (19,367) 507,799 (29,885)
- ----------------------------------------------------------------------------------------------------------
Total deferred income tax expense . . . . . . . . . . . . . . 2,336,170 219,261 477,502
- ----------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE. . . . . . . . . . . . . . . . . . . $ 5,957,448 $ 2,360,683 $ 4,232,672
==========================================================================================================
RECONCILIATION OF EFFECTIVE INCOME TAX RATES
Continuing operations
Federal income tax expense (2). . . . . . . . . . . . . . $ 5,478,056 $ 4,129,150 $ 4,166,724
State income taxes, net of federal benefit. . . . . . . . 737,367 582,681 492,061
Other . . . . . . . . . . . . . . . . . . . . . . . . . . (182,978) (102,279) (94,422)
- ----------------------------------------------------------------------------------------------------------
Total continuing operations . . . . . . . . . . . . . . . . 6,032,445 4,609,552 4,564,363
Discontinued operations . . . . . . . . . . . . . . . . . . (74,997) (2,248,869) (331,691)
- ----------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE. . . . . . . . . . . . . . . . . . . $ 5,957,448 $ 2,360,683 $ 4,232,672
==========================================================================================================
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . . 39.1% 38.8% 38.7%
- -------------------------------------------------------------------------------------------
2002
AT DECEMBER 31, 2003 RESTATED
- -------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES
DEFERRED INCOME TAX LIABILITIES:
Property, plant and equipment . . . . . . . . . . . . . . $ 21,186,978 $ 19,568,426
Environmental costs . . . . . . . . . . . . . . . . . . . 67,354 881,567
Deferred gas costs. . . . . . . . . . . . . . . . . . . . 277,438 70,542
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 910,705 1,307,082
- -------------------------------------------------------------------------------------------
Total deferred income tax liabilities . . . . . . . . . . . 22,442,475 21,827,617
- -------------------------------------------------------------------------------------------
DEFERRED INCOME TAX ASSETS:
Pension and other employee benefits . . . . . . . . . . . 1,500,539 1,505,008
Impairment of intangibles . . . . . . . . . . . . . . . . 125,165 1,785,160
Self insurance. . . . . . . . . . . . . . . . . . . . . . 585,524 547,349
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 520,438 676,885
- -------------------------------------------------------------------------------------------
Total deferred income tax assets. . . . . . . . . . . . . . 2,731,666 4,514,402
- -------------------------------------------------------------------------------------------
Deferred Income Taxes Per Consolidated Balance Sheet. . . . . $ 19,710,809 $ 17,313,215
===========================================================================================
(1) Includes $113,000, $131,000 and $98,000 of deferred state income taxes
for the years 2003, 2002 and 2001, respectively.
(2) Federal income taxes for the years 2003 and 2002 were recorded at 34%.
The year 2001 was recorded at 35%.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
A. SUMMARY OF ACCOUNTING POLICIES
RESTATEMENT
The Company has restated its 2002 and 2001 financial statements in order to
reflect the results of its Delaware and Maryland natural gas divisions on the
"accrual" revenue recognition method rather than the "as billed" revenue
recognition method. This change had an insignificant effect on the Company's
annual results for the last three years. Under the "as billed" method, revenues
from customer sales are not recognized until the meter is read and the amount of
gas used is billed. Whereas, under the "accrual" method, at the end of each
period, the amount of gas used is estimated and is recognized as revenue. The
Company's Florida division has historically used the "accrual" method in
accordance with Florida Public Service Commission ("PSC") requirements. The
Delaware and Maryland divisions have historically used the "as billed" method to
recognize revenues consistent with the rate-setting processes in those states.
In order to consistently apply the "accrual" method, the Company met separately
with the staffs of the Delaware and Maryland Public Service Commissions to
determine the regulatory impact of the change. Having determined that there is
little to no impact, the Company has conformed the revenue recognition method
used in its Delaware and Maryland divisions to the method used by its Florida
division. In order to provide comparable information, the Company has restated
its 2002 and 2001 financial statements to reflect the "accrual" revenue
recognition method. As a result of the restatement, retained earnings of the
Company as of January 1, 2001 increased by $697,000 compared to previously
reported amounts. As indicated below, the change has no impact on basic earnings
per share. There is no impact on fully diluted earnings per share in 2002 and a
$0.01 decrease in 2001.
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, IMPACT OF DECEMBER 31, DECEMBER 31, IMPACT OF DECEMBER 31,
2002 REVENUE 2002 2001 REVENUE 2001
AS PREVIOUSLY RECOGNITION AS PREVIOUSLY RECOGNITION
REPORTED (1) CHANGE AS RESTATED REPORTED (1) CHANGE AS RESTATED
- ---------------------------------------------------------------------------------------------------------------------------------
SELECTED INCOME STATEMENT INFORMATION
Operating Revenues . . . . . . . . $ 134,100,730 $ 41,800 $ 134,142,530 $ 157,670,322 $ (519,069) $ 157,151,253
Operating Income . . . . . . . . . 16,618,131 (13,452) 16,604,679 16,270,315 (49,314) 16,221,001
Income from Continuing Operations. 7,542,990 (7,981) 7,535,009 7,370,288 (29,725) 7,340,563
Net Income . . . . . . . . . . . . 3,729,153 (7,981) 3,721,172 6,721,537 (29,725) 6,691,812
EARNINGS PER SHARE OF COMMON STOCK
Basic
From Continuing Operations . . . . $ 1.37 $ - $ 1.37 $ 1.37 $ - $ 1.37
Net Income . . . . . . . . . . . . $ 0.68 $ - $ 0.68 $ 1.25 $ - $ 1.25
Diluted
From Continuing Operations . . . . $ 1.37 $ - $ 1.37 $ 1.35 $ - $ 1.35
Net Income . . . . . . . . . . . . $ 0.68 $ - $ 0.68 $ 1.24 $ (0.01) $ 1.23
SELECTED BALANCE SHEET INFORMATION
Assets
Accounts receivable. . . . . . . . $ 24,045,852 $ 3,297,902 $ 27,343,754
Underrecovered purchased
gas costs. . . . . . . . . . . . . 2,968,931 (2,205,664) 763,267
Income taxes . . . . . . . . . . . 488,339 26,592 514,931
Other regulatory assets. . . . . . 2,020,751 8,322 2,029,073
Liabilities
Deferred income taxes. . . . . . . $ (417,665) $ 467,379 $ 49,714
Stockholders' Equity
Retained earnings. . . . . . . . . $ 32,238,510 $ 659,773 $ 32,898,283
(1) December 31, 2002 and 2001 Operating Revenue, Operating Income and
Income from Continuing Operations exclude the results of the
operations discontinued in 2003 and include minor reclassifications
to conform with the presentation of the 2003 results.
NATURE OF BUSINESS
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is engaged in
natural gas distribution to approximately 47,600 customers located in central
and southern Delaware, Maryland's Eastern Shore and Florida. The Company's
natural gas transmission subsidiary operates a pipeline from various points in
Pennsylvania and northern Delaware to the Company's Delaware and Maryland
distribution divisions, as well as other utility and industrial customers in
Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company's propane
distribution and wholesale marketing segment provides distribution service to
approximately 34,900 customers in central and southern Delaware, the Eastern
Shore of Maryland, Florida and Virginia, and markets propane to a number of
large independent oil and petrochemical companies, resellers and propane
distribution companies in the southeastern United States. The advanced
information services segment provides domestic and international clients with
information technology related business services and solutions for both
enterprise and e-business applications.
PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements include the accounts of the Company and
its wholly owned subsidiaries. The Company does not have any ownership interests
in investments accounted for using the equity method or any variable interests
in a variable interest entity. All significant intercompany transactions have
been eliminated in consolidation.
SYSTEM OF ACCOUNTS
The natural gas distribution divisions of the Company located in Delaware,
Maryland and Florida are subject to regulation by their respective PSCs with
respect to their rates for service, maintenance of their accounting records and
various other matters. Eastern Shore Natural Gas Company is an open access
pipeline and is subject to regulation by the Federal Energy Regulatory
Commission. The Company's financial statements are prepared in accordance with
generally accepted accounting principles, which give appropriate recognition to
the ratemaking and accounting practices and policies of the various commissions.
The propane and advanced information services segments are not subject to
regulation with respect to rates or maintenance of accounting records.
PROPERTY, PLANT, EQUIPMENT AND DEPRECIATION
Utility property is stated at original cost while the assets of the non-utility
segments are recorded at cost. The costs of repairs and minor replacements are
charged against income as incurred and the costs of major renewals and
betterments are capitalized. As of January 1, 2003, Chesapeake Utilities adopted
SFAS No. 143. See Note B for a summary of the impact on the financial
statements. Prior to the adoption of SFAS No. 143, upon retirement or
disposition of utility property, the recorded cost of removal, net of salvage
value, was charged to accumulated depreciation. In 2003, the costs were charged
against accrued asset removal cost. Upon retirement or disposition of
non-utility property, the gain or loss, net of salvage value, is charged to
income. The provision for depreciation is computed using the straight-line
method at rates that amortize the unrecovered cost of depreciable property over
the estimated remaining useful life of the asset. Depreciation and amortization
expenses are provided at an annual rate for each segment. Average rates for the
past three years were 3 percent for natural gas distribution and transmission, 5
percent for propane, 14 percent for advanced information services and 8 percent
for general plant.
CASH AND CASH EQUIVALENTS
The Company's policy is to invest cash in excess of operating requirements in
overnight income producing accounts. Such amounts are stated at cost, which
approximates market value. Investments with an original maturity of three months
or less are considered cash equivalents.
INVENTORIES
The Company uses the average cost method to value propane and materials and
supplies inventory. The appliance inventory is valued at first-in first-out
("FIFO"). If the market prices drop below cost, inventory balances are adjusted
to market values.
ENVIRONMENTAL REGULATORY ASSETS, LIABILITIES AND EXPENDITURES
Environmental regulatory assets represent amounts related to environmental
liabilities for which cash expenditures have not yet been made. As expenditures
are incurred, the environmental liability is reduced along with the
environmental regulatory asset. These amounts awaiting ratemaking treatment are
recorded to either environmental expenditures as an asset or accumulated
depreciation as cost of removal. Environmental expenditures are amortized and/or
recovered through a rider to base rates in accordance with the ratemaking
treatment granted in each jurisdiction.
GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill and other intangible assets are associated with the acquisition of
non-utility companies. In accordance with Statement of Financial Accounting
Standards ("SFAS") No. 142, goodwill is not amortized, but is tested for
impairment on an annual basis and when events change. Other intangible assets
are amortized on a straight-line basis over their estimated economic useful
lives.
OTHER DEFERRED CHARGES
Other deferred charges include discount, premium and issuance costs associated
with long-term debt and rate case expenses. Debt costs are deferred, then
amortized over the original lives of the respective debt issuances. Rate case
expenses are deferred, then amortized over periods approved by the applicable
regulatory authorities.
INCOME TAXES AND INVESTMENT TAX CREDIT ADJUSTMENTS
The Company files a consolidated federal income tax return. Income tax expense
allocated to the Company's subsidiaries is based upon their respective taxable
incomes and tax credits.
Deferred tax assets and liabilities are recorded for the tax effect of temporary
differences between the financial statements and tax bases of assets and
liabilities and are measured using current effective income tax rates. The
portions of the Company's deferred tax liabilities applicable to utility
operations, which have not been reflected in current service rates, represent
income taxes recoverable through future rates. Investment tax credits on utility
property have been deferred and are allocated to income ratably over the lives
of the subject property.
FINANCIAL INSTRUMENTS
Xeron, the Company's propane marketing operation, engages in trading activities
using forward and futures contracts which have been accounted for using the
mark-to-market method of accounting. Under mark-to-market accounting, the
Company's trading contracts are recorded at fair value, net of future servicing
costs, and changes in market price are recognized as gains or losses in revenues
on the income statement in the period of change. The resulting unrealized gains
and losses are recorded as assets or liabilities, respectively. There were
unrealized gains of $172,000 and $630,000 at December 31, 2003 and 2002,
respectively. Trading liabilities are recorded in other accrued liabilities.
Trading assets are recorded in prepaid expenses and other current assets.
The Company's natural gas and propane distribution operations have entered into
agreements with natural gas and propane suppliers to purchase gas for resale to
their customers. Purchases under these contracts are considered "normal
purchases and sales" under SFAS No. 133 and are accounted for on an accrual
basis.
The propane distribution operation has entered into fair value hedges of its
inventory, in order to mitigate the impact of wholesale price fluctuations. At
December 31, 2003, propane distribution had entered into contracts to hedge 2.6
million gallons of propane inventory.
EARNINGS PER SHARE
The calculations of both basic and diluted earnings per share from continuing
operations are presented in the following chart. In 2002, the impact of
converting the debentures would have been anti-dilutive; therefore, it was not
included in the calculation. Additionally, in both 2002 and 2001, the effect of
exercising the outstanding stock options would have been anti-dilutive;
therefore, it was not included in the calculations.
- -----------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- -----------------------------------------------------------------------------------------------
CALCULATION OF BASIC EARNINGS PER SHARE BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
Net income before cumulative effect of
change in accounting principle . . . . . . . . $10,079,483 $ 7,535,009 $ 7,340,563
Weighted average shares outstanding . . . . . . . 5,610,592 5,489,424 5,367,433
- -----------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE . . . . . . $ 1.80 $ 1.37 $ 1.37
- -----------------------------------------------------------------------------------------------
CALCULATION OF DILUTED EARNINGS PER SHARE BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
RECONCILIATION OF NUMERATOR:
Net income before cumulative effect of
change in accounting principle -- Basic. . . . $10,079,483 $ 7,535,009 $ 7,340,563
Effect of 8.25% Convertible debentures. . . . . . 157,557 - 171,725
- -----------------------------------------------------------------------------------------------
Adjusted numerator -- Diluted. . . . . . . . . . . . $10,237,040 $ 7,535,009 $ 7,512,288
- -----------------------------------------------------------------------------------------------
RECONCILIATION OF DENOMINATOR:
Weighted shares outstanding -- Basic. . . . . . . 5,610,592 5,489,424 5,367,433
Effect of dilutive securities
Stock options. . . . . . . . . . . . . . . . . 1,361 - -
Warrants . . . . . . . . . . . . . . . . . . . 5,481 1,649 849
8.25% Convertible debentures . . . . . . . . . 184,532 - 201,125
- -----------------------------------------------------------------------------------------------
Adjusted denominator -- Diluted . . . . . . . . . 5,801,966 5,491,073 5,569,407
- -----------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE . . . . . . $ 1.76 $ 1.37 $ 1.35
===============================================================================================
OPERATING REVENUES
Revenues for the natural gas distribution operations of the Company are based on
rates approved by the various public service commissions. The natural gas
transmission operation revenues are based on rates approved by the Federal
Energy Regulatory Commission ("FERC"). Customers' base rates may not be changed
without formal approval by these commissions. However, the regulatory
authorities have granted the Company's regulated natural gas distribution
operations the ability to negotiate rates with customers that have competitive
alternatives using approved methodologies. In addition, the natural gas
transmission operation can negotiate rates above or below the FERC-approved
tariff rates.
Chesapeake's natural gas distribution operations each have a gas cost recovery
mechanism that provides for the adjustment of rates charged to customers as gas
costs fluctuate. These amounts are collected or refunded through adjustments to
rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution's industrial
interruptible customers to compete with alternative types of fuel. Based on
pricing, these customers can choose natural gas or alternative types of supply.
Neither the Company nor the interruptible customer is contractually obligated to
deliver or receive natural gas.
The propane wholesale marketing operation records trading activity net, on a
mark-to-market basis for open contracts. The propane distribution, advanced
information services and other segments record revenue in the period the
products are delivered and/or services are rendered.
CERTAIN RISKS AND UNCERTAINTIES
The financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates in measuring
assets and liabilities and related revenues and expenses (see Notes N and O to
the Consolidated Financial Statements for significant estimates). These
estimates involve judgments with respect to, among other things, various future
economic factors that are difficult to predict and are beyond the control of the
Company. Therefore, actual results could differ from those estimates.
The Company records certain assets and liabilities in accordance with SFAS No.
71. If the Company were required to terminate application of SFAS No. 71 for its
regulated operations, all such deferred amounts would be recognized in the
income statement at that time. This would result in a charge to earnings, net of
applicable income taxes, which could be material.
FASB STATEMENTS AND OTHER AUTHORITATIVE PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") adopted SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities" in June 2002,
which requires that a liability for a cost associated with an exit or disposal
activity be recognized when a liability is incurred. Under previous guidelines,
a liability for an exit cost was recognized at the date of an entity's
commitment to an exit plan. This statement was effective for exit or disposal
activities initiated on January 1, 2003 or thereafter and had no effect on the
Company during 2003.
FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," was adopted in November 2002. The Company has adopted FIN No. 45. There
was no impact on the financial statements; however, the disclosures in the
Commitments and Contingencies footnote (Note O) were expanded to include
additional disclosures required by the pronouncement.
In December 2003, the FASB issued FIN No. 46R, "Consolidation of Variable
Interest Entities," which replaced FIN No. 46, "Consolidation of Variable
Interest Entities," issued in January 2003. FIN No. 46R was issued to replace
FIN No. 46 and to clarify the required accounting for interests in variable
interest entities. A variable interest entity is an entity that does not have
sufficient equity investment at risk, or the holders of the equity instruments
lack the essential characteristics of a controlling financial interest. A
variable interest entity is to be consolidated by a company if that company is
subject to a majority of the risk of loss from the variable interest entity's
activities, or is entitled to receive a majority of the entity's residual
returns, or both. As of December 31, 2003, the Company did not have any variable
interests in a variable interest entity.
Chesapeake adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
in 2003. See Note B for additional information on the impact.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." This had no impact on the Company's
financial position or results of operations. The Company continues to apply the
intrinsic value method in accounting for stock-based employee compensation
permitted by Accounting Principles Board Opinion No. 25 and SFAS No. 123. For
each of the periods presented in the consolidated statement of income, no
stock-based compensation expense was recorded as no new stock options were
issued during those periods.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This statement amends and
clarifies financial accounting and reporting for derivative instruments and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities" by requiring that contracts with comparable
characteristics be accounted for similarly. The adoption of SFAS No. 149 did not
have a material impact on Chesapeake's financial position or results of
operations.
On August 13, 2003, the FASB ratified the Emerging Issues Task Force ("EITF")
Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative Instruments
That Are Subject to FASB Statement No. 133 and Not 'Held for Trading Purposes'
as Defined in EITF Issue No. 02-3." This did not have any effect on the
Company's financial position or results of operations.
On January 12, 2004, the FASB released FASB Staff Position No. FAS 106-1
"Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003." The Company has elected to
defer the accounting for the Act, as allowed under Staff Position No. 106-1. See
Note L for required disclosures.
RECLASSIFICATION OF PRIOR YEARS' AMOUNTS
Certain prior years' amounts have been reclassified to conform to the current
year's presentation.
B. ADOPTION OF ACCOUNTING PRINCIPLES
Chesapeake adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
during 2003. The Company's regulated operations are allowed by the regulatory
bodies to recover the costs of retiring their long-lived assets through approved
depreciation rates. Under the pronouncement, the Company was required to record
the portion of depreciation that represents asset removal cost as a regulatory
liability on its financial statements. Previously, asset removal costs were
included in accumulated depreciation. Additionally, the portion of the
depreciation rates approved by the regulators that represents asset removal
costs are now recorded in operations expense. In the past, they were recorded in
depreciation expense. These changes had no impact on the net earnings of the
Company. All periods presented have been reclassified in order to make the
statements comparable. Accrued asset removal cost was $13.5 million and $12.1
million at December 31, 2003 and 2002, respectively.
Please refer to Note G for information on the adoption of SFAS No. 142.
C. BUSINESS DISPOSITIONS, DISCONTINUED OPERATIONS AND ACQUISITIONS
During 2001, Chesapeake acquired Absolute Water Care, Inc., and selected assets
of Aquarius Systems, Inc., EcoWater Systems of Rochester and Intermountain
Water, Inc. These companies provided water treatment, water conditioning and
bottled water to customers in various geographic regions. These acquisitions
were all accounted for as purchases and the Company's financial results included
the results of operations beginning on the date of acquisition. Previously,
Chesapeake had acquired three other water service companies.
During 2003, Chesapeake decided to exit the water services business and sold six
of the operations. Chesapeake expects to dispose of the remaining operation
during 2004. As of December 31, 2003, the results for all water service
businesses have been reclassified to discontinued operations for all periods
presented. A gain of $12,000, net of tax, was recorded in 2003 on the sale of
the water operations.
Operating revenues for discontinued operations were $9.8 million, $11.7 million
and $10.0 million for 2003, 2002 and 2001, respectively. Operating losses for
discontinued operations were $917,000, $2.8 million and $725,000 for 2003, 2002
and 2001, respectively. The following table represents amounts for discontinued
operations that are included in the balance sheets at December 31, 2003 and
2002.
CHESAPEAKE UTILITIES CORPORATION -- DISCONTINUED OPERATIONS
BALANCE SHEETS
ASSETS
- --------------------------------------------------------------------------------------
AT DECEMBER 31, 2003 2002
- --------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment . . . . . . . . . . . . $ 762,383 $ 4,619,703
Less: Accumulated depreciation and amortization. . . (326,792) (1,814,296)
- --------------------------------------------------------------------------------------
Net property, plant and equipment . . . . . . . . . . . 435,591 2,805,407
- --------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . 1,437,821 444,167
Accounts receivable (less allowance for uncollectibles
of $5,346 and $100,069, respectively). . . . . . . . 273,799 1,198,892
Appliance and other inventory, at FIFO. . . . . . . . 99,839 841,688
Deferred income taxes receivable. . . . . . . . . . . 20,725 35,024
Prepaid expenses. . . . . . . . . . . . . . . . . . . 110,175 146,240
- --------------------------------------------------------------------------------------
Total current assets. . . . . . . . . . . . . . . . . . 1,942,359 2,666,011
- --------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Goodwill, net . . . . . . . . . . . . . . . . . . . . - 195,068
Other intangible assets, net. . . . . . . . . . . . . 70,018 1,677,197
Deferred income taxes receivable. . . . . . . . . . . 150,847 1,439,098
Other deferred charges. . . . . . . . . . . . . . . . - 624
- --------------------------------------------------------------------------------------
Total deferred charges and other assets . . . . . . . . 220,865 3,311,987
- --------------------------------------------------------------------------------------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . $ 2,598,815 $ 8,783,405
======================================================================================
CAPITALIZATION AND LIABILITIES
- --------------------------------------------------------------------------------------
CAPITALIZATION
Common Stock. . . . . . . . . . . . . . . . . . . . . $ 51,010 $ 51,010
Additional paid-in capital. . . . . . . . . . . . . . 3,914,783 3,914,783
Retained deficits . . . . . . . . . . . . . . . . . . (5,271,164) (4,483,557)
- --------------------------------------------------------------------------------------
Total stockholders' equity. . . . . . . . . . . . . . . (1,305,371) (517,764)
Long-term debt, net of current maturities . . . . . . . - 7,047
- --------------------------------------------------------------------------------------
Total capitalization. . . . . . . . . . . . . . . . . . (1,305,371) (510,717)
- --------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt . . . . . . . . . . - 7,047
Accounts payable. . . . . . . . . . . . . . . . . . . 67,303 240,913
Due to parent company . . . . . . . . . . . . . . . . 3,558,434 7,710,706
Customer deposits . . . . . . . . . . . . . . . . . . 11,403 79,513
Income taxes payable. . . . . . . . . . . . . . . . . 192,290 146,978
Other accrued liabilities . . . . . . . . . . . . . . 74,756 378,924
- --------------------------------------------------------------------------------------
Total current liabilities . . . . . . . . . . . . . . . 3,904,186 8,564,081
- --------------------------------------------------------------------------------------
OTHER LIABILITIES . . . . . . . . . . . . . . . . . . . - 730,041
- --------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $ 2,598,815 $ 8,783,405
======================================================================================
D. SEGMENT INFORMATION
The following table presents information about the Company's reportable
segments. Results exclude discontinued operations.
- ----------------------------------------------------------------------------------------------
2002 2001
FOR THE YEARS ENDED DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------
OPERATING REVENUES, UNAFFILIATED CUSTOMERS
Natural gas distribution and transmission. . . $110,071,054 $ 93,497,345 $107,305,685
Propane distribution and marketing . . . . . . 39,759,536 28,124,093 35,741,678
Advanced information services. . . . . . . . . 12,476,746 12,523,856 14,103,890
Other. . . . . . . . . . . . . . . . . . . . . (9,329) (2,764) -
- ----------------------------------------------------------------------------------------------
Total operating revenues, unaffiliated customers. $162,298,007 $134,142,530 $157,151,253
- ----------------------------------------------------------------------------------------------
INTERSEGMENT REVENUES (1)
Natural gas distribution and transmission. . . $ 175,757 $ 90,730 $ 112,006
Advanced information services. . . . . . . . . 100,804 239,767 -
Other. . . . . . . . . . . . . . . . . . . . . 711,159 720,221 783,051
- ----------------------------------------------------------------------------------------------
Total intersegment revenues . . . . . . . . . . . $ 987,720 $ 1,050,718 $ 895,057
- ----------------------------------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES
Natural gas distribution and transmission. . . $ 16,653,111 $ 14,973,405 $ 14,405,352
Propane distribution and marketing . . . . . . 3,875,351 1,051,888 912,819
Advanced information services. . . . . . . . . 691,909 343,296 517,427
Other and eliminations . . . . . . . . . . . . 359,029 236,090 385,403
- ----------------------------------------------------------------------------------------------
Total operating income before income taxes. . . . $ 21,579,400 $ 16,604,679 $ 16,221,001
- ----------------------------------------------------------------------------------------------
DEPRECIATION AND AMORTIZATION
Natural gas distribution and transmission. . . $ 5,188,273 $ 5,049,546 $ 4,388,935
Propane distribution and marketing . . . . . . 1,506,201 1,602,655 1,465,215
Advanced information services. . . . . . . . . 190,548 208,430 255,760
Other and eliminations . . . . . . . . . . . . 204,815 228,559 232,502
- ----------------------------------------------------------------------------------------------
Total depreciation and amortization . . . . . . . $ 7,089,937 $ 7,089,190 $ 6,342,412
- ----------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Natural gas distribution and transmission. . . $ 9,078,043 $ 12,116,993 $ 23,185,889
Propane distribution and marketing . . . . . . 2,244,583 1,231,199 2,453,081
Advanced information services. . . . . . . . . 76,924 99,290 252,159
Other. . . . . . . . . . . . . . . . . . . . . 422,789 388,051 401,877
- ----------------------------------------------------------------------------------------------
Total capital expenditures. . . . . . . . . . . . $ 11,822,339 $ 13,835,533 $ 26,293,006
- ----------------------------------------------------------------------------------------------
(1) All significant intersegment revenues are billed at market rates and have been
eliminated from consolidated revenues.
- ----------------------------------------------------------------------------------------------
2002 2001
AT DECEMBER 31, 2003 RESTATED RESTATED
- ----------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Natural gas distribution and transmission. . . $169,865,930 $166,478,223 $163,766,176
Propane distribution and marketing . . . . . . 38,359,251 37,939,683 34,314,633
Advanced information services. . . . . . . . . 2,912,733 2,680,304 2,593,740
Other. . . . . . . . . . . . . . . . . . . . . 7,791,796 9,460,267 9,552,844
- ----------------------------------------------------------------------------------------------
Total identifiable assets . . . . . . . . . . . . $218,929,710 $216,558,477 $210,227,393
- ----------------------------------------------------------------------------------------------
Chesapeake uses the management approach to identify operating segments.
Chesapeake organizes its business around differences in products or services and
the operating results of each segment are regularly reviewed by the Company's
chief operating decision maker in order to make decisions about resources and to
assess performance. The segments are evaluated based on their pre-tax operating
income.
E. FAIR VALUE OF FINANCIAL INSTRUMENTS
Various items within the balance sheet are considered to be financial
instruments because they are cash or are to be settled in cash. The carrying
values of these items generally approximate their fair value (see Note F to the
Consolidated Financial Statements for disclosure of fair value of investments).
The Company's open forward and futures contracts at December 31, 2003 and 2002
had net unrealized gains in fair value of $172,000 and $630,000, respectively,
based on market rates. The fair value of the Company's long-term debt is
estimated using a discounted cash flow methodology. The Company's long-term debt
at December 31, 2003, including current maturities, had an estimated fair value
of $80.9 million as compared to a carrying value of $73.1 million. At December
31, 2002, the estimated fair value was approximately $88.0 million as compared
to a carrying value of $77.3 million. These estimates are based on published
corporate borrowing rates for debt instruments with similar terms and average
maturities.
F. INVESTMENTS
The investment balances at December 31, 2003 and 2002, consisted primarily of a
Rabbi Trust ("the trust") associated with the acquisition of Xeron, Inc. The
Company has classified the underlying investments held by the trust as trading
securities, which require all gains and losses to be recorded into other income.
The trust was established during the acquisition as a retention bonus for an
executive of Xeron. The Company has an associated liability recorded which is
adjusted, along with other expense, for the gains and losses incurred by the
trust.
G. GOODWILL AND OTHER INTANGIBLE ASSETS
The Company adopted SFAS No. 142 in the first quarter of 2002. The Company
performed a test as of January 1, 2002, for goodwill impairment using the
two-step process prescribed in SFAS No. 142. The first step was a screen for
potential impairment, using January 1, 2002, as the measurement date. The second
step was a measurement of the amount of the goodwill determined to be impaired.
The results of the tests indicated that the goodwill associated with the
Company's water business was impaired and that the amount of the impairment was
$3.2 million. This was recorded as the cumulative effect of a change in
accounting principle. The fair value of the water business was determined using
several methods, including discounted cash flow projections and market
valuations for recent purchases and sales of similar businesses. These were
weighted based on their expected probability. The previous test for impairment
of goodwill, prescribed under SFAS No. 121, looked at undiscounted cash flows.
The determination that the goodwill associated with the Company's water business
was impaired was the result of the more stringent tests required by the new
pronouncement. SFAS No. 142 requires that impairment tests be performed
annually. At December 31, 2002, the test indicated an additional impairment
charge of $1.5 million was necessary. The unprofitable performance of the
Company's water services business was the primary cause of the impairment.
In accordance with SFAS No. 142, the Company did not record any amortization of
goodwill in 2003 or 2002. In 2001, amortization of goodwill, net of associated
taxes, decreased income by $154,000 ($0.03 per share).
The change in the carrying value of goodwill for the two years ended December
31, 2003, is as follows:
WATER
BUSINESSES PROPANE TOTAL
------------ ----------- ------------
Balance at January 1, 2002 . . . . . . . . . $ 4,869,068 $ 674,451 $ 5,543,519
Impairment charges . . . . . . . . . . . . . (4,674,000) - (4,674,000)
- --------------------------------------------------------------------------------------
Balance at December 31, 2002 . . . . . . . . 195,068 674,451 869,519
Sale of discontinued operations. . . . . . . (195,068) - (195,068)
- --------------------------------------------------------------------------------------
Balance at December 31, 2003 . . . . . . . . $ 0 $ 674,451 $ 674,451
======================================================================================
Intangible assets subject to amortization are as follows:
DECEMBER, 2003 DECEMBER 31, 2002
---------------------------- ----------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Amount Amortization
------------- ------------- ------------- -------------
Customer Lists . . . . $ 276,616 $ 142,780 $ 1,099,202 $ 191,838
Non-compete agreements - - 1,000,000 256,257
Acquisition costs. . . 263,659 92,282 379,400 102,885
- -----------------------------------------------------------------------------------
Total. . . . . . . . . $ 540,275 $ 235,062 $ 2,478,602 $ 550,980
===================================================================================
The decrease from 2002 to 2003 reflects the sale of the assets of the water
businesses, including intangible assets. Amortization of intangible assets was
$168,000 and $241,000 for the years ended December 31, 2003 and 2002,
respectively. For the year ended December 31, 2001, amortization of intangibles,
excluding goodwill, was $132,000. The estimated annual amortization of
intangibles for the next five years is: $15,000 for 2004; $14,000 for 2005;
$14,000 for 2006; $14,000 for 2007; and $14,000 for 2008.
H. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL
In 2000 and 2001, the Company entered into agreements with an investment banker
to assist in identifying acquisition candidates. Under the agreements, the
Company issued warrants to the investment banker to purchase 15,000 shares of
Company stock in 2001 at a price of $18.25 per share and 15,000 shares in 2000
at a price of $18.00. The warrants are exercisable during a seven-year period
after the date granted. The Company recognized expenses of $47,500 related to
the warrants. No warrants have been exercised.
I. LONG-TERM DEBT
The outstanding long-term debt, net of current maturities, is as shown below.
- ------------------------------------------------------------------
AT DECEMBER 31, 2003 2002
- ------------------------------------------------------------------
First mortgage sinking fund bonds:
9.37% Series I, due December 15, 2004 $ 0 $ 756,000
Uncollateralized senior notes:
7.97% note, due February 1, 2008. . . 4,000,000 5,000,000
6.91% note, due October 1, 2010 . . . 5,454,545 6,363,636
6.85% note, due January 1, 2012 . . . 7,000,000 8,000,000
7.83% note, due January 1, 2015 . . . 20,000,000 20,000,000
6.64% note, due October 31, 2017. . . 30,000,000 30,000,000
Convertible debentures:
8.25% due March 1, 2014. . . . . . . 2,961,000 3,281,000
Other debt . . . . . . . . . . . . . . . - 7,048
- ------------------------------------------------------------------
Total Long-Term Debt . . . . . . . . . . $69,415,545 $73,407,684
- ------------------------------------------------------------------
Annual maturities of consolidated long-term debt for the next five
years are as follows: $3,665,091 for 2004; $2,909,091 for 2005;
$4,909,091 for 2006; $7,636,364 for 2007;and $7,636,364 for 2008.
The Company completed the private placement of $30.0 million of long-term debt
due October 31, 2017, and drew down the funds on October 31, 2002. The debt has
a fixed interest rate of 6.64 percent. The funds were used to repay short-term
borrowing.
The convertible debentures may be converted, at the option of the holder, into
shares of the Company's common stock at a conversion price of $17.01 per share.
During 2003 and 2002, debentures totaling $320,000 and $77,000, respectively,
were converted to stock. The debentures are also redeemable for cash at the
option of the holder, subject to an annual non-cumulative maximum limitation of
$200,000. During 2003 and 2002 no debentures were redeemed for cash. At the
Company's option, the debentures may be redeemed at stated amounts.
Indentures to the long-term debt of the Company and its subsidiaries contain
various restrictions. The most stringent restrictions state that the Company
must maintain equity of at least 40 percent of total capitalization and the
times interest earned ratio must be at least 2.5. The Company is in compliance
with all of its debt covenants.
Portions of the Company's natural gas distribution plant assets are subject to a
lien under the mortgage pursuant to which the Company's first mortgage sinking
fund bonds are issued.
J. SHORT-TERM BORROWING
As of December 31, 2003, the Board of Directors had authorized the Company to
borrow up to $35.0 million from various banks and trust companies under
short-term lines of credit. Prior to the issuance of the $30.0 million long-term
debt on October 31, 2002, the Company had authorization to borrow up to $55.0
million. As of December 31, 2003, the Company had three uncommitted and two
committed, short-term bank lines of credit totaling $65.0 million, none of which
required compensating balances. Under these lines of credit, the Company had
short-term debt outstanding of approximately $3.5 million and $10.9 million at
December 31, 2003 and 2002, respectively. The annual weighted average interest
rates were 2.40 percent for 2003 and 2.35 percent for 2002. The Company also had
a letter of credit outstanding in the amount of $694,000 that reduced the
amounts available under the lines of credit.
K. LEASE OBLIGATIONS
The Company has entered several operating lease arrangements for office space at
various locations, equipment and pipeline facilities. Rent expense related to
these leases was $1.1 million, $1.2 million and $952,000 for 2003, 2002 and
2001, respectively. Future minimum payments under the Company's current lease
agreements are $871,000, $669,000, $554,000, $222,000 and $165,000 for the years
of 2004 through 2008, respectively; and $199,000 thereafter, totaling $2.7
million.
L. EMPLOYEE BENEFIT PLANS
RETIREMENT PLANS
Prior to January 1,1999, the Company offered both a defined benefit plan and
defined contribution plan to qualified employees. On January 1, 1999, the
Company restructured its employee benefit plans to be competitive with those in
similar industries. Chesapeake offered participants of the defined benefit plan
the option to remain in the plan or receive a one-time payout and enroll in an
enhanced retirement savings plan. Chesapeake closed the defined benefit plan to
new participants, effective December 31, 1998.
DEFINED BENEFIT PLAN
Benefits under the plan are based on each participant's years of service and
highest average compensation. The Company's funding policy provides that
payments to the trustee shall be equal to the minimum funding requirements of
the Employee Retirement Income Security Act of 1974. The Company does not expect
to be required to make any funding payments in 2004.
The following schedule summarizes the assets of the pension plan, by investment
type, at December 31, 2003 and 2002:
- -------------------------------------------------------------------------------
AT DECEMBER 31, 2003 2002
- -------------------------------------------------------------------------------
ASSET CATEGORY
Equity securities. . . . . . . . . . . . . . 73.69% 63.59%
Debt securities. . . . . . . . . . . . . . . 14.95% 35.15%
Cash . . . . . . . . . . . . . . . . . . . . 11.36% 1.26%
- -------------------------------------------------------------------------------
TOTAL. . . . . . . . . . . . . . . . . . . . . . . 100.00% 100.00%
- -------------------------------------------------------------------------------
The investment policy of the Plan calls for an allocation of assets between
equity and debt instruments with equity being 60 percent and debt at 40 percent,
but allowing for a variance of 20 percent in either direction. Additionally, as
changes are made to holdings, cash, money market funds or United States Treasury
Bills may be held temporarily by the fund. Investments in the following are
prohibited: options, guaranteed investment contracts, real estate, venture
capital, private placements, futures, commodities, limited partnerships and
Chesapeake stock. Additionally, short selling and margin transactions are
prohibited.
The following schedule sets forth the funded status of the pension plan at
December 31, 2003 and 2002:
- -------------------------------------------------------------------------------
AT DECEMBER 31, 2003 2002
- -------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation -- beginning of year . . . . $10,781,990 $10,120,364
Service cost . . . . . . . . . . . . . . . . 325,366 319,230
Interest cost. . . . . . . . . . . . . . . . 684,239 672,392
Change in discount rate. . . . . . . . . . . 772,254 372,918
Actuarial (gain) loss. . . . . . . . . . . . (212,528) (307,100)
Benefits paid. . . . . . . . . . . . . . . . (402,566) (395,814)
- -------------------------------------------------------------------------------
Benefit obligation -- end of year . . . . . . . 11,948,755 10,781,990
- -------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets -- beginning of year. 9,438,725 11,745,574
Actual return on plan assets . . . . . . . . 2,265,389 (1,911,035)
Benefits paid. . . . . . . . . . . . . . . . (402,566) (395,814)
- -------------------------------------------------------------------------------
Fair value of plan assets -- end of year. . . . 11,301,548 9,438,725
- -------------------------------------------------------------------------------
FUNDED STATUS. . . . . . . . . . . . . . . . . . . (647,207) (1,343,265)
UNRECOGNIZED TRANSITION OBLIGATION . . . . . . . . (35,851) (50,955)
UNRECOGNIZED PRIOR SERVICE COST. . . . . . . . . . (43,657) (48,356)
UNRECOGNIZED NET (GAIN) LOSS . . . . . . . . . . . (261,665) 659,522
- -------------------------------------------------------------------------------
ACCRUED PENSION COST . . . . . . . . . . . . . . . ($988,380) ($783,054)
- -------------------------------------------------------------------------------
ASSUMPTIONS:
Discount rate . . . . . . . . . . . . . . . . . 6.00% 6.75%
Rate of compensation increase . . . . . . . . . 4.00% 5.00%
Expected return on plan assets. . . . . . . . . 8.50% 8.50%
- -------------------------------------------------------------------------------
The expected return on plan assets was calculated using an expected long-term
rate of return of 9.5 percent for equity investments and 6.0 percent for debt
investments, weighted by their respective proportionate share of the fund
balance.
Net periodic pension costs for the defined benefit pension plan for 2003, 2002
and 2001 include the components as shown below:
- ---------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 2001
- ---------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC PENSION COST:
Service cost. . . . . . . . . . . . . . . . . $ 325,366 $ 319,230 $ 347,955
Interest cost . . . . . . . . . . . . . . . . 684,239 672,392 646,205
Expected return on assets . . . . . . . . . . (784,476) (980,915) (981,882)
Amortization of:
Transition assets. . . . . . . . . . . . . (15,104) (15,104) (15,104)
Prior service cost . . . . . . . . . . . . (4,699) (4,699) (4,699)
Actuarial gain . . . . . . . . . . . . . . - (115,570) (195,029)
- ---------------------------------------------------------------------------------------
NET PERIODIC PENSION COST (BENEFIT). . . . . . . $ 205,326 ($124,666) ($202,554)
- ---------------------------------------------------------------------------------------
The Company also sponsors an unfunded executive excess benefit plan. The accrued
benefit obligation and accrued pension costs were $1.4 million and $1.0 million,
respectively, as of December 31, 2003, and $1.2 million and $840,000,
respectively, at December 31, 2002.
RETIREMENT SAVINGS PLAN
The Company sponsors a 401(k) Retirement Savings Plan, which provides
participants a mechanism for making contributions for retirement savings. Each
participant may make pre-tax contributions of up to 15 percent of eligible base
compensation, subject to Internal Revenue Service limitations. For participants
still covered by the defined benefit pension plan, the Company makes a
contribution matching 60 percent or 100 percent of each participant's pre-tax
contributions based on the participant's years of service, not to exceed six
percent of the participant's eligible compensation for the plan year.
Effective January 1, 1999, the Company began offering an enhanced 401(k) plan to
all new employees, as well as existing employees that elected to no longer
participate in the defined benefit plan. The Company makes matching
contributions on a basis of up to six percent of each employee's pre-tax
compensation for the year. The match is between 100 percent and 200 percent,
based on a combination of the employee's age and years of service. The first 100
percent of the funds are matched with Chesapeake common stock. The remaining
match is invested in the Company's 401(k) plan according to each employee's
election options.
On December 1, 2001, the Company converted the 401(k) fund holding Chesapeake
stock to an Employee Stock Ownership Plan.
Effective, January 1, 1999, the Company began offering a non-qualified
supplemental employee retirement savings plan open to Company executives over a
specific income threshold. Participants receive a cash only matching
contribution percentage equivalent to their 401(k) match level. All
contributions and matched funds earn interest income monthly. This plan is not
funded externally.
The Company's contributions to the 401(k) plans totaled $1,444,000, $1,488,000
and $1,352,000 for the years ended December 31, 2003, 2002 and 2001,
respectively. As of December 31, 2003, there are 181,149 shares reserved to fund
future contributions to the Retirement Savings Plan.
OTHER POST-RETIREMENT BENEFITS
The Company sponsors a defined benefit post-retirement health care and life
insurance plan that covers substantially all employees.
Net periodic post-retirement costs for 2003, 2002 and 2001 include the following
components:
- ------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 2001
- ------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC POST-RETIREMENT COST:
Service cost. . . . . . . . . . . . . . . . . $ 5,138 $ 2,739 $ 887
Interest cost . . . . . . . . . . . . . . . . 85,319 68,437 49,799
Amortization of:
Transition obligation. . . . . . . . . . . 27,859 27,859 27,859
Actuarial loss (gain). . . . . . . . . . . 66,271 12,109 (1,717)
- ------------------------------------------------------------------------------------
TOTAL POST-RETIREMENT COST . . . . . . . . . . . $ 184,587 $ 111,144 $ 76,828
- ------------------------------------------------------------------------------------
The following schedule sets forth the status of the post-retirement health care
and life insurance plan:
- --------------------------------------------------------------------------------
AT DECEMBER 31, 2003 2002
- --------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation -- beginning of year . . . . $ 1,053,950 $ 723,926
Retirees . . . . . . . . . . . . . . . . . . (24,779) 123,134
Fully-eligible active employees. . . . . . . 356,027 140,786
Other active . . . . . . . . . . . . . . . . 86,466 66,104
- --------------------------------------------------------------------------------
Benefit obligation -- end of year. . . . . . . . . $ 1,471,664 $ 1,053,950
- --------------------------------------------------------------------------------
FUNDED STATUS. . . . . . . . . . . . . . . . . . . ($1,471,664) ($1,053,950)
UNRECOGNIZED TRANSITION OBLIGATION . . . . . . . . 78,000 105,589
UNRECOGNIZED NET LOSS. . . . . . . . . . . . . . . 655,585 304,827
- --------------------------------------------------------------------------------
ACCRUED POST-RETIREMENT COST . . . . . . . . . . . ($738,079) ($643,264)
- --------------------------------------------------------------------------------
ASSUMPTIONS:
Discount rate . . . . . . . . . . . . . . . . . 6.00% 6.75%
- --------------------------------------------------------------------------------
The health care inflation rate for 2003 is assumed to be 10 percent for medical
and 14 percent for prescription drugs. These rates are projected to gradually
decrease to ultimate rates of 5 and 6 percent, respectively, by the year 2009. A
one percentage point increase in the health care inflation rate from the assumed
rate would increase the accumulated post-retirement benefit obligation by
approximately $193,000 as of January 1, 2004, and would increase the aggregate
of the service cost and interest cost components of the net periodic
post-retirement benefit cost for 2004 by approximately $14,000. A one percentage
point decrease in the health care inflation rate from the assumed rate would
decrease the accumulated post-retirement benefit obligation by approximately
$159,000 as of January 1, 2004, and would decrease the aggregate of the service
cost and interest cost components of the net periodic post-retirement benefit
cost for 2004 by approximately $11,000.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the
"Act") was signed into law on December 8, 2003. The Company has elected to defer
FASB Staff Position No. FAS 106-1 "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003," due to the uncertainties that exist related to the Act and its impact, if
any, on the Company's post-retirement health benefits. The measures of
accumulated benefit obligation and net periodic benefit cost in the financial
statements and accompanying notes do not reflect the effects, if any, of the Act
on the Company's plan. Specific authoritative guidance on the accounting for the
federal subsidy is pending and that guidance, when issued, could require the
Company to change previously reported information.
M. EXECUTIVE INCENTIVE PLANS
A Performance Incentive Plan ("the Plan") adopted in 1992 and amended in April
1998 allows for the granting of performance shares, stock options and stock
appreciation rights to certain officers of the Company. The Company now uses
performance shares exclusively; however, stock options granted in prior years
remained outstanding at December 31, 2003. Additionally, stock appreciation
rights ("SARs") were granted previously. None remained outstanding at December
31, 2003.
The Plan enables participants the right to earn performance shares upon the
Company's achievement of certain performance goals, as set forth in the specific
agreements, and the individual's achievement of goals set annually for each
executive. The Company recorded compensation expense of $726,000, $165,000 and
$123,000 associated with these performance shares in 2003, 2002 and 2001,
respectively.
In 1997, the Company executed Stock Option Agreements for a three-year
performance period ending December 31, 2000, with certain executive officers.
One-half of these options became exercisable over time and the other half became
exercisable if certain performance targets were achieved. SFAS No. 123 requires
the disclosure of pro forma net income and earnings per share as if fair value
based accounting had been used to account for the stock-based compensation
costs. The assumptions used in calculating the pro forma information were:
dividend yield, 4.73 percent; expected volatility, 15.53 percent; risk-free
interest rate, 5.89 percent; and an expected life of four years. No options have
been granted since 1997; therefore, there is no pro forma impact for 2003, 2002
or 2001. The weighted average exercise price of outstanding options was $20.50
for all years presented. The options outstanding at December 31, 2003, expire on
December 31, 2005.
Changes in outstanding options are shown on the chart below:
- ------------------------------------------------------------------------------------------------------------
2003 2002 2001
NUMBER OPTION NUMBER OPTION NUMBER OPTION
OF SHARES PRICE OF SHARES PRICE OF SHARES PRICE
- ------------------------------------------------------------------------------------------------------------
Balance - beginning of year. . . . 41,948 $20.50 41,948 $20.50 110,093 $12.75-$20.50
Options exercised . . . . . . (12,458) $20.50 (53,220) $12.75
Options expired . . . . . . . (14,925) $12.75
- ------------------------------------------------------------------------------------------------------------
Balance - end of year. . . . . . . 29,490 $20.50 41,948 $20.50 41,948 $20.50
- ------------------------------------------------------------------------------------------------------------
Exercisable. . . . . . . . . . . . 29,490 $20.50 41,948 $20.50 41,948 $20.50
- ------------------------------------------------------------------------------------------------------------
In 2000, the Company replaced the third year of this Stock Option Agreement with
Stock Appreciation Rights. The SARs were awarded based on performance with a
minimum number of SARs established for each participant. During 2001 and 2000,
the Company granted 10,650 and 13,150 SARs, respectively, in conjunction with
the agreement. During 2003, all SARs were exercised.
As of December 31, 2003, there were 326,515 shares reserved for issuance under
the terms of the Company's Performance Incentive Plan.
N. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES
The Company has participated in the investigation, assessment and remediation of
three former gas manufacturing plant sites located in different jurisdictions.
The Company has accrued liabilities for the Dover Gas Light, Salisbury Town Gas
Light and the Winter Haven Coal Gas sites. The Company is currently in
discussions with the Maryland Department of the Environment ("MDE") regarding a
fourth site in Cambridge, Maryland.
DOVER GAS LIGHT SITE
On January 15, 2004, the Company received a Certificate of Completion of Work
from the United States Environmental Protection Agency ("EPA") regarding the
Dover Gas Light site. This concluded the remedial action obligation that
Chesapeake had related to this site. The Dover Gas Light site is a former
manufactured gas plant site located in Dover, Delaware. In May 2001, the
Company, General Public Utilities Corporation, Inc. (now FirstEnergy
Corporation), the State of Delaware, the United States Environmental Protection
Agency ("USEPA") and the United States Department of Justice signed a settlement
term sheet to settle complaints brought by the Company and the United States in
1996 and 1997, respectively, with respect to the Dover site. In October 2002,
the final Consent Decrees were signed and delivered to the United States
Department of Justice ("DOJ"). The Consent Decrees were lodged simultaneously
with the United States District Court for the District of Delaware and a notice
soliciting public comment for a 30-day period was published in the Federal
Register. The public comment period ended April 30, 2003 with no public
comments. The DOJ filed an Unopposed Motion for Entry of Consent Decrees on June
26, 2003.
By Order dated July 18, 2003, the U.S. District Court for the District of
Delaware entered final judgment approving and entering the Consent Decrees
resolving this litigation. The entry of the Consent Decrees triggered the
parties' obligations to make the payments required by the settlement agreement
within thirty days. Chesapeake received from other parties, net settlement
payments of $1.15 million. These proceeds will be passed on to the Company's
firm customers, in accordance with the environmental rate rider. Additionally,
Chesapeake received a release from liability and covenant not to sue from the
EPA and the State of Delaware. This will relieve Chesapeake from liability for
future remediation at the site, unless previously unknown conditions are
discovered at the site, or information previously unknown to the EPA is received
that indicates the remedial action related to the former manufactured gas plant
is not sufficiently protective. These contingencies are standard, and are
required by the United States in all liability settlements.
At December 31, 2003, the Company had accrued $10,000 for costs associated with
the Dover site and had recorded an associated regulatory asset for the same
amount. Through December 31, 2003, the Company has incurred approximately $9.7
million in costs relating to environmental testing and remedial action studies
at the Dover site. Approximately $9.4 million has been recovered through
December 2003 from other parties or through rates.
SALISBURY TOWN GAS LIGHT SITE
The Salisbury Town Gas Light site is a former manufactured gas plant site
located in Salisbury, Maryland. In cooperation with the MDE, the Company
performed the following remedial steps: (1) operation of an air sparging/soil
vapor extraction ("AS/SVE") remedial system; (2) monitoring and recovery of
product from recovery wells; and (3) monitoring of ground-water quality. In
March 2002, with MDE's permission, the Company permanently decommissioned the
AS/SVE system and discontinued nearly all on-site and off-site monitoring wells.
In November 2002, the Company submitted a request for a No Further Action
("NFA") for the site. 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. The Company has completed the MDE
recommended work plans and has executed the deed restrictions. During the third
quarter of 2003 the Company submitted a revised request for the NFA. The MDE has
not yet responded to the request.
The Company has adjusted the liability with respect to the Salisbury Town Gas
Light site to $8,000 at December 31, 2003. This amount is based on the estimated
costs to perform limited product monitoring and recovery efforts and fulfill
ongoing reporting requirements. A corresponding regulatory asset has been
recorded, reflecting the Company's belief that costs incurred will be
recoverable in base rates.
Through December 31, 2003, the Company has incurred approximately $2.9 million
for remedial actions and environmental studies at the Salisbury Town Gas Light
site. Of this amount, approximately $1.8 million has been recovered through
insurance proceeds or ratemaking treatment. The Company expects to recover the
remaining costs through rates and has established a regulatory asset for those
costs.
WINTER HAVEN COAL GAS SITE
The Winter Haven Coal Gas site is located in Winter Haven, Florida. In May 2001,
the Florida Department of Environmental Protection ("FDEP") approved a remedial
action plan that includes the utilization of the AS/SVE technologies to address
ground-water impacts throughout a majority of the site. The AS/SVE construction
was completed in the fourth quarter of 2002 and is now fully operational. The
Company is currently negotiating with FDEP on the extent of additional
investigation and remediation work required to address surface soil,
ground-water and sediment impacts that will not be remediated by the AS/SVE
system. The current estimate of costs to complete the remediation activities at
the site is approximately $544,000 (present value). Accordingly, at December 31,
2003 the Company has accrued a liability of $544,000. Through December 31, 2003
the Company has incurred approximately $1.3 million of environmental costs
associated with this site. At December 31, 2003 the Company had collected
through rates $179,000 in excess of costs incurred. A regulatory asset of
approximately $335,000 representing the uncollected portion of the estimated
cleanup costs has also been recorded.
It is management's opinion that any unrecovered current costs and any other
future costs associated with any of the three sites incurred will be recoverable
through future rates or sharing arrangements with other responsible parties.
In August 2002, the Company along with two other parties met with MDE to discuss
alleged manufactured gas plant contamination at a property located in Cambridge,
Maryland. At that meeting, one of the other parties agreed to perform a remedial
investigation of the site. The possible exposure of the Company at this site
cannot be determined at this time.
O. OTHER COMMITMENTS AND CONTINGENCIES
NATURAL GAS AND PROPANE SUPPLY
The Company's natural gas and propane distribution operations have entered into
contractual commitments for gas from various suppliers. The contracts have
various expiration dates. In November 2003, the Company entered into a one-year
contract with an energy marketing and risk management company to manage a
portion of the Company's natural gas transportation and storage capacity.
CORPORATE GUARANTEES
The Company has issued corporate guarantees to certain vendors of its propane
wholesale marketing subsidiary. The corporate guarantees provide for the payment
of propane purchases by the subsidiary, in the case of the subsidiary's default.
The guarantees at December 31, 2003, totaled $4.5 million and expire on various
dates in 2004.
OTHER
The Company is involved in certain legal actions and claims arising in the
normal course of business. The Company is also involved in certain legal and
administrative proceedings before various governmental agencies concerning
rates. In the opinion of management, the ultimate disposition of these
proceedings will not have a material effect on the consolidated financial
position, results of operations or cash flows of the Company.
P. QUARTERLY FINANCIAL DATA (UNAUDITED)
In the opinion of the Company, the quarterly financial information shown below
includes all adjustments necessary for a fair presentation of the operations for
such periods. Due to the seasonal nature of the Company's business, there are
substantial variations in operations reported on a quarterly basis. Due to the
restatement and the reclassification of the water businesses to discontinued
operations, which required changes to prior periods, the amounts presented below
may not agree to amounts reported in prior Form 10-Q reports. Dollars are shown
in thousands, except per share amounts.
----------------- 2003 ----------------- ----------------- 2002 -----------------
AS BILLED IMPACT OF ACCRUAL AS BILLED IMPACT OF ACCRUAL
METHOD REVENUE METHOD METHOD REVENUE METHOD
AS PREVIOUSLY RECOGNITION AS PREVIOUSLY RECOGNITION
REPORTED (1) CHANGE AS RESTATED REPORTED (1) CHANGE AS RESTATED
- -----------------------------------------------------------------------------------------------------------------------------
SELECTED FINANCIAL INFORMATION
Operating Revenues
First quarter . . . . . . . . . . . $ 63,924 $ (965) $ 62,959 $ 45,851 $ (735) $ 45,116
Second quarter. . . . . . . . . . . 32,237 (1,452) 30,785 28,633 (1,845) 26,788
Third quarter . . . . . . . . . . . 23,174 275 23,449 20,617 160 20,777
Fourth quarter. . . . . . . . . . . 42,388 2,717 45,105 39,000 2,462 41,462
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues. . . . . . . . $ 161,723 $ 575 $ 162,298 $ 134,101 $ 42 $ 134,143
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income
First quarter . . . . . . . . . . . $ 12,566 $ (256) $ 12,310 $ 9,152 $ (187) $ 8,965
Second quarter. . . . . . . . . . . 3,268 (406) 2,862 2,093 (553) 1,540
Third quarter . . . . . . . . . . . 144 9 153 (153) 14 (139)
Fourth quarter. . . . . . . . . . . 5,594 660 6,254 5,526 713 6,239
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Income. . . . . . . . . $ 21,572 $ 7 $ 21,579 $ 16,618 $ (13) $ 16,605
- -----------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
First quarter . . . . . . . . . . . $ 6,789 $ (153) $ 6,636 $ 5,057 $ (112) $ 4,945
Second quarter. . . . . . . . . . . 1,177 (242) 935 620 (330) 290
Third quarter . . . . . . . . . . . (715) 5 (710) (721) 8 (713)
Fourth quarter. . . . . . . . . . . 2,824 394 3,218 2,587 426 3,013
- -----------------------------------------------------------------------------------------------------------------------------
Total Income from Continuing Operations $ 10,075 $ 4 $ 10,079 $ 7,543 $ (8) $ 7,535
- -----------------------------------------------------------------------------------------------------------------------------
Income from Discontinued Operations
First quarter . . . . . . . . . . . $ (163) $ 0 $ (163) $ (174) $ 0 $ (174)
Second quarter. . . . . . . . . . . - - - (90) - (90)
Third quarter . . . . . . . . . . . (150) - (150) (218) - (218)
Fourth quarter. . . . . . . . . . . (475) - (475) (1,416) - (1,416)
- -----------------------------------------------------------------------------------------------------------------------------
Total Income from
Discontinued Operations . . . . . . . $ (788) $ 0 $ (788) $ (1,898) $ 0 $ (1,898)
- -----------------------------------------------------------------------------------------------------------------------------
Income from Change in Accounting Principle
First quarter . . . . . . . . . . . $ 0 $ 0 $ 0 $ (1,916) $ 0 $ (1,916)
Second quarter. . . . . . . . . . . - - - - - -
Third quarter . . . . . . . . . . . - - - - - -
Fourth quarter. . . . . . . . . . . - - - - - -
- -----------------------------------------------------------------------------------------------------------------------------
Total Income from Change in
Accounting Principle. . . . . . . . . $ 0 $ 0 $ 0 $ (1,916) $ 0 $ (1,916)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income
First quarter . . . . . . . . . . . $ 6,628 $ (153) $ 6,475 $ 2,967 $ (112) $ 2,855
Second quarter. . . . . . . . . . . 1,176 (242) 934 530 (330) 200
Third quarter . . . . . . . . . . . (865) 5 (860) (939) 8 (931)
Fourth quarter. . . . . . . . . . . 2,349 394 2,743 1,171 426 1,597
- -----------------------------------------------------------------------------------------------------------------------------
Total Net Income. . . . . . . . . . . . $ 9,288 $ 4 $ 9,292 $ 3,729 $ (8) $ 3,721
- -----------------------------------------------------------------------------------------------------------------------------
(1) Operating Revenue, Operating Income and Income from Continuing Operations
for the quarters of 2002 and previously filed quarters of 2003
exclude the results of the operations discontinued in 2003 and include
minor reclassifications to conform with the presentation of the
year-end 2003 results.
----------------- 2003 ----------------- ----------------- 2002 -----------------
AS BILLED IMPACT OF ACCRUAL AS BILLED IMPACT OF ACCRUAL
METHOD REVENUE METHOD METHOD REVENUE METHOD
AS PREVIOUSLY RECOGNITION AS PREVIOUSLY RECOGNITION
REPORTED (1) CHANGE AS RESTATED REPORTED (1) CHANGE AS RESTATED
- -----------------------------------------------------------------------------------------------------------------------------
EARNINGS PER SHARE OF COMMON STOCK
Basic
- -----
From Continuing Operations
First quarter . . . . . . . . . . . $ 1.22 $ (0.03) $ 1.19 $ 0.93 $ (0.02) $ 0.91
Second quarter. . . . . . . . . . . $ 0.21 $ (0.04) $ 0.17 $ 0.11 $ (0.06) $ 0.05
Third quarter . . . . . . . . . . . $ (0.13) $ - $ (0.13) $ (0.13) $ - $ (0.13)
Fourth quarter. . . . . . . . . . . $ 0.50 $ 0.07 $ 0.57 $ 0.47 $ 0.07 $ 0.54
FISCAL YEAR . . . . . . . . . . . . $ 1.80 $ - $ 1.80 $ 1.37 $ - $ 1.37
From Discontinued Operations
First quarter . . . . . . . . . . . $ (0.03) $ - $ (0.03) $ (0.04) $ - $ (0.04)
Second quarter. . . . . . . . . . . $ - $ - $ - $ (0.01) $ - $ (0.01)
Third quarter . . . . . . . . . . . $ (0.02) $ - $ (0.02) $ (0.04) $ - $ (0.04)
Fourth quarter. . . . . . . . . . . $ (0.08) $ - $ (0.08) $ (0.25) $ - $ (0.25)
FISCAL YEAR . . . . . . . . . . . . $ (0.14) $ - $ (0.14) $ (0.34) $ - $ (0.34)
From Change in Accounting Principle
First quarter . . . . . . . . . . . $ - $ - $ - $ (0.35) $ - $ (0.35)
Second quarter. . . . . . . . . . . $ - $ - $ - $ - $ - $ -
Third quarter . . . . . . . . . . . $ - $ - $ - $ - $ - $ -
Fourth quarter. . . . . . . . . . . $ - $ - $ - $ - $ - $ -
FISCAL YEAR . . . . . . . . . . . . $ - $ - $ - $ (0.35) $ - $ (0.35)
Net Income
First quarter . . . . . . . . . . . $ 1.19 $ (0.03) $ 1.16 $ 0.55 $ (0.03) $ 0.52
Second quarter. . . . . . . . . . . $ 0.21 $ (0.04) $ 0.17 $ 0.10 $ (0.06) $ 0.04
Third quarter . . . . . . . . . . . $ (0.15) $ - $ (0.15) $ (0.17) $ - $ (0.17)
Fourth quarter. . . . . . . . . . . $ 0.42 $ 0.07 $ 0.49 $ 0.21 $ 0.08 $ 0.29
FISCAL YEAR . . . . . . . . . . . . $ 1.66 $ - $ 1.66 $ 0.68 $ - $ 0.68
Diluted
- -------
From Continuing Operations
First quarter . . . . . . . . . . . $ 1.19 $ (0.03) $ 1.16 $ 0.90 $ (0.02) $ 0.88
Second quarter. . . . . . . . . . . $ 0.21 $ (0.04) $ 0.17 $ 0.11 $ (0.06) $ 0.05
Third quarter . . . . . . . . . . . $ (0.13) $ - $ (0.13) $ (0.13) $ - $ (0.13)
Fourth quarter. . . . . . . . . . . $ 0.49 $ 0.07 $ 0.56 $ 0.47 $ 0.07 $ 0.54
FISCAL YEAR . . . . . . . . . . . . $ 1.76 $ - $ 1.76 $ 1.37 $ - $ 1.37
From Discontinued Operations
First quarter . . . . . . . . . . . $ (0.03) $ - $ (0.03) $ (0.03) $ - $ (0.03)
Second quarter. . . . . . . . . . . $ - $ - $ - $ (0.01) $ - $ (0.01)
Third quarter . . . . . . . . . . . $ (0.02) $ - $ (0.02) $ (0.04) $ - $ (0.04)
Fourth quarter. . . . . . . . . . . $ (0.08) $ - $ (0.08) $ (0.25) $ - $ (0.25)
FISCAL YEAR . . . . . . . . . . . . $ (0.13) $ - $ (0.13) $ (0.34) $ - $ (0.34)
From Change in Accounting Principle
First quarter . . . . . . . . . . . $ - $ - $ - $ (0.34) $ - $ (0.34)
Second quarter. . . . . . . . . . . $ - $ - $ - $ - $ - $ -
Third quarter . . . . . . . . . . . $ - $ - $ - $ - $ - $ -
Fourth quarter. . . . . . . . . . . $ - $ - $ - $ - $ - $ -
FISCAL YEAR . . . . . . . . . . . . $ - $ - $ - $ (0.35) $ - $ (0.35)
Net Income
First quarter . . . . . . . . . . . $ 1.16 $ (0.03) $ 1.13 $ 0.53 $ (0.02) $ 0.51
Second quarter. . . . . . . . . . . $ 0.21 $ (0.04) $ 0.17 $ 0.10 $ (0.06) $ 0.04
Third quarter . . . . . . . . . . . $ (0.15) $ - $ (0.15) $ (0.17) $ - $ (0.17)
Fourth quarter. . . . . . . . . . . $ 0.41 $ 0.07 $ 0.48 $ 0.21 $ 0.08 $ 0.29
FISCAL YEAR . . . . . . . . . . . . $ 1.63 $ - $ 1.63 $ 0.68 $ - $ 0.68
(1) Operating Revenue, Operating Income and Income from Continuing Operations
for the quarters of 2002 and previously filed quarters of 2003
exclude the results of the operations discontinued in 2003 and include
minor reclassifications to conform with the presentation of the
year-end 2003 results.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The Chief Executive Officer and Chief Financial Officer of the Company, with the
participation of other Company officials, have evaluated the Company's
"disclosure controls and procedures" (as such term is defined under Rule
13a-14(e) promulgated under the Securities Exchange Act of 1934, as amended) as
of December 31, 2003. Based upon their evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that the Company's disclosure controls and
procedures are effective.
CHANGES IN INTERNAL CONTROLS
During the fiscal quarter of the Company ended December 31, 2003, there was no
change in the Company's internal control over financial reporting that has
materially affected, or is reasonably likely to materially affect, the Company's
internal controls over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item is incorporated herein by reference to the
portions of the Proxy Statement, captioned "Information Regarding the Board of
Directors and Nominees," "Committees of the Board - Audit Committee" and Section
16(a) Beneficial Ownership Reporting Compliance" to be filed not later than
April 29, 2004 in connection with the Company's Annual Meeting to be held on May
6, 2004.
The information required by this Item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Part I of this Form 10-K under "Executive Officers of the Registrant."
The Company has adopted a Code of Ethics for Financial Officers, which applies
to its principal executive officer, principal financial officer, principal
accounting officer or controller, or persons performing similar functions. The
information set forth under Item 1 hereof concerning the Code of Ethics for
Financial Officers is incorporated herein by reference.
The following table sets forth information as of December 31, 2003, with respect
to compensation plans of Chesapeake and its subsidiaries under which shares of
Chesapeake common stock are authorized for issuance:
- -------------------------------------------------------------------------------------------------------------------
(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. . . . . . 29,490 (1) $20.500 341,215 (2)
- -------------------------------------------------------------------------------------------------------------------
Equity compensation
plans not approved by
security holders. . . . . . 30,000 (3) $18.125 0
- -------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . 59,490 $19.302 341,215
- -------------------------------------------------------------------------------------------------------------------
(1) Consists of options to purchase 29,490 shares under the 1992 Performance Incentive Plan, as amended.
(2) Includes 14,700 shares under the 1995 Directors Stock Compensation Plan and 326,515 shares under the 1992
Performance Incentive Plan. The 326,515 shares excludes 16,950 shares issued in March of 2004 related to
2003 performance. The corresponding expense for the 16,950 shares was recognized in 2003.
(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 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated herein by reference to the
portion of the Proxy Statement captioned "Director Compensation" and "Management
Compensation" in the Proxy Statement to be filed not later than April 29, 2004,
in connection with the Company's Annual Meeting to be held on May 6, 2004.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated herein by reference to the
portion of the Proxy Statement captioned "Beneficial Ownership of Chesapeake's
Securities" to be filed not later than April 29, 2004 in connection with the
Company's Annual Meeting to be held on May 6, 2004.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated herein by reference to the
portion of the Proxy Statement captioned "Fees and Services of
PricewaterhouseCoopers LLP" to be filed not later than April 29, 2004, in
connection with the Company's Annual Meeting to be held on May 6, 2004.
PART IV
ITEM 15. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND
REPORTS ON FORM 8-K
(A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:
1. Financial Statements:
o Auditors' Report dated February 19, 2004 of PricewaterhouseCoopers
LLP, Independent Auditors
o Consolidated Statements of Income for each of the three years ended
December 31, 2003, 2002 and 2001
o Consolidated Balance Sheets at December 31, 2003 and December 31, 2002
o Consolidated Statements of Cash Flows for each of the three years
ended December 31, 2003, 2002 and 2001
o Consolidated Statements of Common Stockholders' Equity for each of the
three years ended December 31, 2003, 2002 and 2001
o Consolidated Statements of Income Taxes for each of the three years
ended December 31, 2003, 2002 and 2001
o Notes to Consolidated Financial Statements
2. Financial Statement Schedules - Schedule II - Valuation and Qualifying
Accounts
All other schedules are omitted because they are not required, are inapplicable
or the information is otherwise shown in the financial statements or notes
thereto.
(B) REPORTS ON FORM 8-K:
Earnings press release dated November 4, 2003 (Items 7 and 12)
(C) EXHIBITS:
Exhibit 3(a) Amended Certificate of Incorporation of Chesapeake Utilities
Corporation is incorporated herein by reference to Exhibit 3.1 of the
Company's Quarterly Report on Form 10-Q for the period ended June 30, 1998,
File No. 001-11590.
Exhibit 3(b) Amended Bylaws of Chesapeake Utilities Corporation, effective
November 14, 2003, are incorporated herein by reference to Exhibit 3 of the
Company's Form 10-Q for the quarter ended September 30,2003, File No.
001-11590, filed November 14, 2003.
Exhibit 4(a) Form of Indenture between the Company and Boatmen's Trust Company,
Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated
herein by reference to Exhibit 4.2 of the Company's Registration Statement
on Form S-2, Reg. No. 33-26582, filed on January 13, 1989.
Exhibit 4(b) First Mortgage Sinking Fund Bonds dates December 15, 1989 between
the Company and The Prudential Insurance Company of America, with respect
to $8.2 million of 9.37% Series I Mortgage Bonds due December 15, 2004, is
not being filed herewith, in accordance with Item 601(b)(4)(iii) of
Regulation S-K. The Company hereby agrees to furnish a copy of that
agreement to the Commission upon request.
Exhibit 4(c) Note Agreement dated February 9, 1993, by and between the Company
and Massachusetts Mutual Life Insurance Company and MML Pension Insurance
Company, with respect to $10 million of 7.97% Unsecured Senior Notes due
February 1, 2008, is incorporated herein by reference to Exhibit 4 to the
Company's Annual Report on Form 10-K for the year ended December 31, 1992,
File No. 0-593.
Exhibit 4(d) Note Purchase Agreement entered into by the Company on October 2,
1995, pursuant to which the Company privately placed $10 million of its
6.91% Senior Notes due in 2010, is not being filed herewith, in accordance
with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to
furnish a copy of that agreement to the Commission upon request.
Exhibit 4(e) Note Purchase Agreement entered into by the Company on December 15,
1997, pursuant to which the Company privately placed $10 million of its
6.85% Senior Notes due 2012, is not being filed herewith, in accordance
with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to
furnish a copy of that agreement to the Commission upon request.
Exhibit 4(f) Note Purchase Agreement entered into by the Company on December 27,
2000, pursuant to which the Company privately placed $20 million of its
7.83% Senior Notes due 2015, is not being filed herewith, in accordance
with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to
furnish a copy of that agreement to the Commission upon request.
Exhibit 4(g) Note Agreement entered into by the Company on October 31, 2002,
pursuant to which the Company privately placed $30 million of its 6.64%
Senior Notes due 2017, is incorporated herein by reference to Exhibit 2 of
the Company's Current Report on Form 8-K, filed November 6, 2002, File No.
001-11590.
*Exhibit 10(a) Executive Employment Agreement dated March 26, 2002, by and
between Chesapeake Utilities Corporation and John R. Schimkaitis filed
herewith.
*Exhibit 10(b) Form of Executive Employment Agreement dated March 26, 2003, by
and between Chesapeake Utilities Corporation and each of Michael P.
McMasters, William C. Boyles and Stephen C. Thompson, filed herewith.
*Exhibit 10(c) Form of Executive Employment Agreement dated August 1, 2002, by
and between Sharp Energy, Inc. and S. Robert Zola, filed herewith.
*Exhibit 10(d) Executive Employment Agreement dated January 1, 2003, by and
between Chesapeake Utilities Corporation and Ralph J. Adkins is
incorporated herein by reference to Exhibit 10 of the Company's Annual
Report on Form 10-K for the year ended December 31, 2002, File No.
001-11590.
*Exhibit 10(e) Form of Performance Share Agreement dated January 1, 1998,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of Ralph J. Adkins
and John R. Schimkaitis is incorporated herein by reference to Exhibit 10
of the Company's Annual Report on Form 10-K for the year ended December 31,
1997, File No. 001-11590.
*Exhibit 10(f) Form of Performance Share Agreement dated January 1, 2002,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of Ralph J. Adkins,
John R. Schimkaitis, Michael P. McMasters, William C. Boyles and Stephen C.
Thompson is incorporated herein by reference to Exhibit 10 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001, File No.
001-11590.
*Exhibit 10(g) Form of Performance Share Agreement dated January 1, 2003,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of John R.
Schimkaitis, Michael P. McMasters, Stephen C. Thompson and William C.
Boyles is incorporated herein by reference to Exhibit 10 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2002, File No.
001-11590.
*Exhibit 10(h) Form of Performance Share Agreement dated January 1, 2003,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and S. Robert Zola, filed
herewith.
*Exhibit 10(i) Form of Performance Share Agreement dated December 4, 2003,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of John R.
Schimkaitis, Michael P. McMasters, filed herewith.
*Exhibit 10(j) Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated
January 1, 1992, is incorporated herein by reference to Exhibit 10 to the
Company's Annual Report on Form 10-K for the year ended December 31, 1991,
File No. 0-593.
*Exhibit 10(k) Chesapeake Utilities Corporation Performance Incentive Plan dated
January 1, 1992, is incorporated herein by reference to the Company's Proxy
Statement dated April 20, 1992, in connection with the Company's Annual
Meeting held on May 19, 1992.
*Exhibit 10(l) Amendments to Chesapeake Utilities Corporation Performance
Incentive Plan are incorporated herein by reference to the Company's Proxy
Statement dated April 1, 1998, in connection with the Company's Annual
Meeting held on May 19, 1998.
*Exhibit 10(m) Form of Stock Appreciation Rights Agreement dated January 1,
2001, pursuant to Chesapeake Utilities Corporation Performance Incentive
Plan by and between Chesapeake Utilities Corporation and each of Philip S.
Barefoot, William C. Boyles, Thomas A. Geoffroy, James R. Schneider and
William P. Schneider is incorporated herein by reference to Exhibit 10 of
the Company's Annual Report on Form 10-K for the year ended December 31,
2000, File No. 001-11590.
*Exhibit 10(n) Directors Stock Compensation Plan adopted by Chesapeake Utilities
Corporation in 1995 is incorporated herein by reference to the Company's
Proxy Statement dated April 17, 1995 in connection with the Company's
Annual Meeting held in May 1995.
*Exhibit 10(o) United Systems, Inc. Executive Appreciation Rights Plan dated
December 31, 2000 is incorporated herein by reference to Exhibit 10 of the
Company's Annual Report on Form 10-K for the year ended December 31, 2000,
File No. 001-11590.
Exhibit 12 Computation of Ratio of Earning to Fixed Charges, filed herewith.
Exhibit 21 Subsidiaries of the Registrant, filed herewith.
Exhibit 23 Consent of Independent Accountants, filed herewith.
Exhibit 31.1 Certificate of Chief Executive Office of Chesapeake Utilities
Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 15, 2004,
filed herewith.
Exhibit 31.2 Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 15, 2004,
filed herewith.
Exhibit 32.1 Certificate of Chief Executive Office of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated March 15, 2004, filed
herewith.
Exhibit 32.2 Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated March 15, 2004, filed
herewith.
* Management contract or compensatory plan or agreement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange
Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Chesapeake Utilities Corporation
By: /s/ John R. Schimkaitis
--------------------------
John R. Schimkaitis
President and Chief
Executive Officer
Date: March 15, 2004
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
/s/ Ralph J. Adkins /s/ John R. Schimkaitis
- ---------------------- --------------------------
Ralph J. Adkins, Chairman of John R. Schimkaitis, President,
the Board and Director Chief Executive Officer
and Director
Date: March 9, 2004 Date: March 9, 2004
/s/ Michael P. McMasters /s/ Richard Bernstein
- --------------------------- -----------------------
Michael P. McMasters, Richard Bernstein, Director
Vice President and Chief
Financial Officer
(Principal Financial and
Accounting Officer)
Date: March 9, 2004 Date: March 9, 2004
/s/ Thomas J. Bresnan /s/ Walter J. Coleman
- ------------------------ ------------------------
Thomas J. Bresnan, Director Walter J. Coleman, Director
Date: March 9, 2004 Date: March 9, 2004
/s/ J. Peter Martin /s/ Joseph E. Moore, Esq.
- ---------------------- -----------------------------
J. Peter Martin, Director Joseph E. Moore, Esq., Director
Date: March 9, 2004 Date: March 9, 2004
/s/ Calvert A. Morgan, Jr. /s/ Rudolph M. Peins, Jr.
- ------------------------------ -----------------------------
Calvert A. Morgan, Jr., Director Rudolph M. Peins, Jr., Director
Date: March 9, 2004 Date: March 9, 2004
/s/ Robert F. Rider
- ----------------------
Robert F. Rider, Director
Date: March 9, 2004
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
- --------------------------------------------------------------------------------------------------
ADDITIONS
BALANCE AT ----------------------- BALANCE AT
BEGINNING CHARGED TO OTHER END OF
FOR THE YEAR ENDED DECEMBER 31, OF YEAR INCOME ACCOUNTS (1) DEDUCTIONS (2) YEAR
- --------------------------------------------------------------------------------------------------
RESERVE DEDUCTED FROM RELATED ASSETS
RESERVE FOR UNCOLLECTIBLE ACCOUNTS
2003 . . . . . . . . . . . . . . . . $659,628 $637,435 $ 10,093 $ (648,109) $659,047
- --------------------------------------------------------------------------------------------------
2002 . . . . . . . . . . . . . . . . $621,516 $677,461 $210,735 $ (850,084) $659,628
- --------------------------------------------------------------------------------------------------
2001 . . . . . . . . . . . . . . . . $549,961 $592,590 $488,895 $(1,009,930) $621,516
- --------------------------------------------------------------------------------------------------
(1) Recoveries.
(2) Uncollectible accounts charged off.
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
EXHIBIT 12
RATIO OF EARNINGS TO FIXED CHARGES
- ----------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS . . . . . . . . . . . $10,079,483 $ 7,535,009 $ 7,340,563
Add:
Income taxes . . . . . . . . . . . . . . . . . . . 6,032,445 4,069,552 4,564,363
Portion of rents representative of interest factor 351,445 411,461 317,173
Interest on indebtedness . . . . . . . . . . . . . 5,616,756 4,867,520 4,914,459
Amortization of debt discount and expense. . . . . 89,155 87,502 101,183
- ----------------------------------------------------------------------------------------------
EARNINGS AS ADJUSTED. . . . . . . . . . . . . . . . . . $22,169,284 $17,511,044 $17,237,741
==============================================================================================
FIXED CHARGES
Portion of rents representative of interest factor $ 351,445 $ 411,461 $ 317,173
Interest on indebtedness . . . . . . . . . . . . . 5,616,756 4,867,520 4,914,459
Amortization of debt discount and expense. . . . . 89,155 87,502 101,183
- ----------------------------------------------------------------------------------------------
FIXED CHARGES . . . . . . . . . . . . . . . . . . . . . $ 6,057,356 $ 5,366,483 $ 4,332,815
==============================================================================================
RATIO OF EARNINGS TO FIXED CHARGES. . . . . . . . . . . 3.66 3.26 3.23
==============================================================================================
CHESAPEAKE UTILITIES CORPORATION
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
SUBSIDIARIES STATE INCORPORATED
------------ -------------------
Aquality Company, Inc. Delaware
Eastern Shore Natural Gas Company Delaware
Sharp Energy, Inc. Delaware
Chesapeake Service Company Delaware
Xeron, Inc. Mississippi
Sam Shannahan Well Company, Inc. Maryland
Sharp Water, Inc. Delaware
SUBSIDIARIES OF SHARP ENERGY, INC. STATE INCORPORATED
-------------------------------------- -------------------
Sharpgas, Inc. Delaware
Sharp Living, Inc. Delaware
Tri-County Gas Co., Incorporated Maryland
SUBSIDIARIES OF CHESAPEAKE SERVICE COMPANY STATE INCORPORATED
---------------------------------------------- -------------------
Skipjack, Inc. Delaware
BravePoint, Inc. Georgia
Chesapeake Investment Company Delaware
Eastern Shore Real Estate, Inc. Maryland
SUBSIDIARIES OF SHARP WATER, INC. STATE INCORPORATED
------------------------------------- -------------------
Aquality Solutions of Michigan, Inc. Michigan
Carroll Water Systems, Inc. Maryland
Absolute Water Care, Inc. Florida
Sharp Water of Florida, Inc. Delaware
Sharp Water of Idaho, Inc. Delaware
Sharp Water of Minnesota, Inc. Delaware
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
________
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-3 (Nos. 33-28391 and 33-64671) and Form S-8 (Nos. 333-01175
and 333-94159) of Chesapeake Utilities Corporation of our report dated February
19, 2004 relating to the financial statements and financial statement schedule,
which appears in this Form 10-K.
/S/PRICEWATERHOUSECOOPERS LLP
- -----------------------------
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
March 15, 2004
EXHIBIT 31.1
CERTIFICATE PURSUANT TO RULE 13A-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934
I, John R. Schimkaitis, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Utilities
Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we
have:
a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluations;
c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent function):
a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: March 15, 2004
/s/ John R. Schimkaitis
- --------------------------
John R. Schimkaitis
President and Chief Executive Officer
EXHIBIT 31.2
CERTIFICATE PURSUANT TO RULE 13A-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934
I, Michael P. McMasters, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Utilities
Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we
have:
a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluations;
c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent function):
a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: March 15, 2004
/s/ Michael P. McMasters
- ---------------------------
Michael P. McMasters
Vice President and Chief Financial Officer
EXHIBIT 32.1
CERTIFICATE OF CHIEF EXECUTIVE OFFICER
OF
CHESAPEAKE UTILITIES CORPORATION
(PURSUANT TO 18 U.S.C. SECTION 1350)
I, John R. Schimkaitis, President and Chief Executive Officer of Chesapeake
Utilities Corporation, certify that, to the best of my knowledge, the Annual
Report on Form 10-K of Chesapeake Utilities Corporation ("Chesapeake") for the
year ended December 31, 2003, filed with the Securities and Exchange Commission
on the date hereof (i) fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained therein fairly presents, in all material respects, the
financial condition and results of operations of Chesapeake.
/s/ John R. Schimkaitis
--------------------------
John R. Schimkaitis
March 15, 2004
A signed original of this written statement required by Section 906 of the
Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or
otherwise adopting the signature that appears in typed form within the
electronic version of this written statement required by Section 906, has been
provided to Chesapeake Utilities Corporation and will be retained by Chesapeake
Utilities Corporation and furnished to the Securities and Exchange Commission or
its staff upon request.
EXHIBIT 32.2
CERTIFICATE OF CHIEF FINANCIAL OFFICER
OF
CHESAPEAKE UTILITIES CORPORATION
(PURSUANT TO 18 U.S.C. SECTION 1350)
I, Michael P. McMasters, Vice President and Chief Financial Officer of
Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the
Annual Report on Form 10-K of Chesapeake Utilities Corporation ("Chesapeake")
for the year ended December 31, 2003, filed with the Securities and Exchange
Commission on the date hereof (i) fully complies with the requirements of
section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and
(ii) the information contained therein fairly presents, in all material
respects, the financial condition and results of operations of Chesapeake.
/s/ Michael P. McMasters
---------------------------
Michael P. McMasters
March 15, 2004
A signed original of this written statement required by Section 906 of the
Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or
otherwise adopting the signature that appears in typed form within the
electronic version of this written statement required by Section 906, has been
provided to Chesapeake Utilities Corporation and will be retained by Chesapeake
Utilities Corporation and furnished to the Securities and Exchange Commission or
its staff upon request.
Upon written request,
Chesapeake will provide, free of
charge, a copy of any exhibit to
the 2003 Annual Report on
Form 10-K not included
in this document.