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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, includ