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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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, 1998
Commission File Number: 001-11590
CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)
State of Delaware 51-0064146
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including zip code)
302-734-6799
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class: Common Stock - par value per share $.4867
Name of each exchange on which registered: New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Title of class: 8.25% Convertible Debentures Due 2014
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X]. No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendments to
this Form 10-K. [X]
As of March 26, 1999, 5,115,971 shares of common stock were outstanding. The
aggregate market value of the common shares held by non-affiliates of
Chesapeake Utilities Corporation, based on the last trade price on March 26,
1999, as reported by the New York Stock Exchange, was approximately $67
million.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 1999 Annual Meeting of Stockholders
are incorporated by reference in Part III.
CHESAPEAKE UTILITIES CORPORATION
FORM 10-K
YEAR ENDED DECEMBER 31, 1998
TABLE OF CONTENTS
Page
PART I ........................................................................1
Item 1. Business ..............................................................1
Item 2. Properties ...........................................................11
Item 3. Legal Proceedings ....................................................11
Item 4. Submission of
Matters to a Vote of Security Holders ................................14
Item 10. Executive Officers of the Registrant ................................14
PART II ......................................................................15
Item 5. Market for the Registrant's Common Stock
and Related Security Holder Matters ..................................15
Item 6. Selected Financial Data ..............................................16
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ........................17
Item 7a. Quantitative and Qualitative Disclosures
About Market Risk ...................................................24
Item 8. Financial Statements and Supplemental Data ...........................24
Item 9. Changes In and Disagreements With Accountants
on Accounting and Financial Disclosure ...............................44
PART III .....................................................................44
Item 10. Directors and Executive Officers
of the Registrant ...................................................44
Item 11. Executive Compensation ..............................................44
Item 12. Security Ownership of Certain
Beneficial Owners and Management ....................................44
Item 13. Certain Relationships and Related Transactions ......................44
PART IV.......................................................................44
Item 14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K.....................................44
Signatures ...................................................................47
PART I
Item 1. Business
(a) General Development of Business
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a
diversified utility company engaged primarily in natural gas distribution and
transmission, propane distribution and marketing and advanced information
services.
Chesapeake's three natural gas distribution divisions serve approximately
37,100 residential, commercial and industrial customers in southern Delaware,
Maryland's Eastern Shore and Central Florida. The Company's natural gas
transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"),
operates a 273-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 Delaware and on the Eastern Shore of Maryland. The Company's propane
distribution operation serves approximately 35,000 customers in southern
Delaware and on the Eastern Shore of Maryland and Virginia. The advanced
information services segment provides consulting, custom programming, training
and development tools for national and international clients.
(b) Financial Information about Industry Segments
Financial information by business segment is included in Item 7 under the
heading "Notes to Consolidated Financial Statements - Note C".
(c) Narrative Description of Business
The Company is engaged in four primary business activities: natural gas
transmission, natural gas distribution, propane distribution and marketing and
advanced information services. In addition to the four primary groups,
Chesapeake has four subsidiaries engaged in other service-related businesses.
(i) (a) Natural Gas Transmission
General
Eastern Shore, the Company's wholly owned transmission subsidiary, operates
an interstate natural gas pipeline and provides open access transportation
services for affiliated and non-affiliated companies through an integrated
gas pipeline extending from southeastern Pennsylvania to Delaware and the
Eastern Shore of Maryland. Eastern Shore also provides contract storage
services as well as the purchase and sale of small quantities of gas for
system balancing purposes ("swing gas"). Eastern Shore's rates are subject
to regulation by the Federal Energy Regulatory Commission ("FERC").
Adequacy of Resources
Eastern Shore has 4,916 thousand cubic feet ("Mcf") of firm transportation
capacity under Rate Schedule FT under contract with Transcontinental Gas
Pipe Line Corporation ("Transco") which expires in 2005. Eastern Shore also
has 7,046 Mcf of firm peak day entitlements and total storage capacity of
278,264Mcf under Rate Schedules GSS, LSS and LGA, respectively, under
contract with Transco. The GSS and LSS contracts expire in 2013 and the LGA
contract expires in 2006.
Eastern Shore also has firm storage service under Rate Schedule FSS and
firm storage transportation capacity under Rate Schedule SST under contract
with Columbia Gas Transmission ("Columbia"). These contracts, which expire
in 2004, provide for 1,073 Mcf of firm peak day entitlement and total
storage capacity of 53,738 Mcf.
Eastern Shore has retained the firm transportation capacity and firm
storage services described above in order to provide swing transportation
service to those customers that requested such service.
Competition
Under the open access environment, interstate pipeline companies have
unbundled the traditional components of their service - gas gathering,
transportation and storage - from the sale of the commodity. Pipelines that
choose to be merchants of gas must form separate marketing operations
independent of their pipeline operations. Hence, gas marketers have
developed as a viable option for many companies because they are providing
expertise in gas purchasing along with collective purchasing capabilities
which, when combined, may reduce the end-user cost. Additional discussion
on competition is included in Item 7 under the heading "Management's
Discussion and Analysis - Competition".
Rates and Regulation
General. Eastern Shore is subject to regulation by the FERC as an
interstate pipeline. The FERC regulates the provision of service, terms and
conditions of service, and the rates and fees Eastern Shore can charge to
its transportation customers. In addition, the FERC regulates the rates
Eastern Shore is charged for transportation and transmission line capacity
and services provided by Transco and Columbia.
Regulatory Proceedings
Amendment to Rt. 72 and Porter Road filing. On March 6, 1998, the FERC
authorized Eastern Shore to replace 2.3 miles of 6-inch pipeline with 10-
inch pipeline along Route 72 and Power Road, all in conjunction with a
Delaware Department of Transportation highway relocation project. On
September 15, 1998, Eastern Shore filed an amendment in Docket No. CP97-
279-001 requesting that the FERC authorize an increase in the diameter of
the previously approved 2.3-mile pipeline from 10 inches to 16 inches.
Eastern Shore filed this amendment in connection with the 1999 System
Expansion described below. The FERC issued an Order Amending Certificate in
this docket on October 16, 1998, approving Eastern Shore's proposal.
Construction has started and is expected to be completed during 1999.
1999 System Expansion. On September 25, 1998, Eastern Shore filed an
application before the FERC requesting authorization to construct and
operate a total of eight miles (4.5 miles in Pennsylvania and 3.5 miles in
Delaware) of 16-inch pipeline looping on Eastern Shore's existing system
and to install 1,085 horsepower of additional compression at its Delaware
City compressor station. The purpose of these new facilities is to enable
Eastern Shore to provide 16,540 dekatherms of additional firm
transportation capacity on its system for two existing customers, Delmarva
Power and Light Company and Star Enterprise. The proposed expansion has
been targeted for completion on November 1, 1999. The estimated project
cost is approximately $7.0 million and is expected to generate
approximately $1.8 million in additional annual revenue. Eastern Shore also
requested the FERC to issue a preliminary determination of rolled-in
treatment of the costs incurred in this project into existing rates. The
Company is awaiting FERC approval.
Rate Case Filing. In October 1996, Eastern Shore filed for a general rate
increase with the FERC. The filing proposed an increase in Eastern Shore's
jurisdictional rates that would generate additional annual operating
revenue of approximately $1.4 million. Eastern Shore also stated in the
filing that it intended to use the cost-of-service submitted in the general
rate increase filing to develop rates in the pending Open Access Docket. In
September 1997, the FERC approved a rate increase of $1.2 million.
Open Access Filing. In December 1995, Eastern Shore filed its abbreviated
application for a blanket certificate of public convenience and necessity
authorizing the transportation of natural gas on behalf of others. Eastern
Shore proposed to unbundle the sales and storage services it had provided.
Customers who had previously received firm sales and storage services on
Eastern Shore (the "Converting Customers") would receive entitlements to
firm transportation service on Eastern Shore's pipeline in a quantity
equivalent to their existing service rights. Eastern Shore proposed to
retain some of its pipeline entitlements and storage capacity for
operational issues and to facilitate "no-notice" (no prior notification
required to receive service) transportation service on its pipeline system.
Eastern Shore would release or assign to the remaining Converting Customers
the firm transportation capacity, including contract storage, it held on
its upstream pipelines so that the Converting Customers would be able to
become direct customers of such upstream pipelines. Converting Customers
who previously received bundled sales service having no-notice
characteristics would have the right to elect no-notice firm transportation
service.
In connection with the rate increase settlement, the issues listed above
pertaining to Eastern Shore operating as an open access pipeline were also
settled in September 1997, with open access implementation occurring on
November 1, 1997.
Delaware City Compressor Station Filing. In December 1995, Eastern Shore
filed an application before the FERC pursuant to Sections 7(b) and (c) of
the Natural Gas Act for a certificate of public convenience and necessity
authorizing Eastern Shore to: (1) construct and operate a 2,170 horsepower
compressor station in Delaware City, New Castle County, Delaware on a
portion of its existing pipeline system known as the "Hockessin Line", such
new station to be known as the "Delaware City Compressor Station"; (2)
construct and operate slightly less than one mile of 16-inch pipeline in
Delaware City, New Castle County, Delaware to tie the suction side of the
proposed Delaware City Compressor Station into the Hockessin Line; and (3)
increase the maximum allowable operating pressure on 28.7 miles of Eastern
Shore's pipeline from Eastern Shore's existing Bridgeville Compressor
Station in Bridgeville, Sussex County, Delaware to its terminus in
Salisbury, Wicomico County, Maryland.
In September 1996 the FERC issued its Final Order, which: authorized
Eastern Shore to: (1) construct and operate the facilities requested in its
application: (2) roll-in the cost of the facilities into its existing rates
if the revenues from the increase in services exceed the cost associated
with the expansion portion of the project; and (3) abandon the 100 Mcf per
day of firm sale service to one of its direct sale customers. The FERC's
Final Order also denied Eastern Shore the authority to increase the level
of sales and storage service it provides its customers until it completes
its restructuring in its open access proceeding. The compressor facility
and associated piping were needed to stabilize capacity on Eastern Shore's
system as a result of steadily declining inlet pressures at the Hockessin
interconnect with Transcontinental Gas Pipe Line Corporation. Construction
of the facilities started during the second half of 1996 and was completed
during the first quarter of 1997.
(i) (b) Natural Gas Distribution
General
Chesapeake distributes natural gas to approximately 37,100 residential,
commercial and industrial customers in southern Delaware, the Salisbury and
Cambridge, Maryland areas on Maryland's Eastern Shore, and Central Florida.
These activities are conducted through three utility divisions, one
division in Delaware, another in Maryland and a third division in Florida.
In 1993, the Company started natural gas supply management services in the
state of Florida under the name of Peninsula Energy Services Company
("PESCO").
Delaware and Maryland. The Delaware and Maryland divisions serve an average
of approximately 27,900 customers, of which approximately 27,800 are
residential and commercial customers purchasing gas primarily for heating
purposes. Annually, residential and commercial customers account for
approximately 56% of the volume delivered by the divisions and 75% 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 an average of
approximately 9,100 residential and commercial and 90 industrial customers
in Polk, Osceola and Hillsborough Counties. Currently 41 of the division's
industrial customers, which purchase and transport gas on a firm and
interruptible basis, account for approximately 89% of the volume delivered
by the Florida division and 50% of the division's annual natural gas and
transportation revenues. These customers are primarily engaged in the
citrus and phosphate industries and electric cogeneration. The Company's
Florida division also provides natural gas supply management services to
compete in the open access environment. Currently, twenty-two customers
receive such services, which generated net income of $66,000 in 1998.
Adequacy of Resources
General. Chesapeake's Delaware and Maryland utility divisions ("Delaware",
"Maryland" or "the Divisions") have firm and interruptible contracts with
four (4) interstate "open access" pipelines. The Divisions are directly
interconnected with Eastern Shore and services upstream of Eastern Shore
are contracted with Transco, Columbia, and Columbia Gulf Transmission
Company ("Gulf"). The Divisions use their firm supply sources to meet a
significant percentage of their projected demand requirements. In order to
meet the difference between firm supply and firm demand, Delaware and
Maryland obtain gas supply on the "spot market" from various other
suppliers that is transported by the upstream pipelines and delivered to
the Divisions' interconnects with Eastern Shore as needed. The Company
believes that Delaware and Maryland's available firm and "spot market"
supply is ample to meet the anticipated needs of their customers.
Delaware. Delaware's contracts with Transco include: (a) firm
transportation capacity of 8,663 dekatherms ("Dt") per day, which expires
in 2005; (b) firm transportation capacity of 311 Dt per day for December
through February, expiring in 2006; and (c) firm storage service, providing
a total capacity of 142,830 Dt. Delaware and Transco are currently engaged
in negotiations with regard to an extension of the term of the firm storage
service. Although the original contract expired in 1998, Transco and
Delaware have continued under the previous terms and conditions until an
agreement is finalized.
Delaware's contracts with Columbia include: (a) firm transportation
capacity of 852 Dt per day, which expires in 2004; (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
storage service providing a peak day entitlement of 6,193 Dt and a total
capacity of 298,195 Dt, expiring in 2004; and (f) firm storage service,
providing a peak day entitlement of 583 Dt per day and a total capacity of
52,460 Dt, which expires in 2018. Delaware's contracts with Columbia for
storage related transportation provide quantities that are equivalent to
the peak day entitlement for the period of October through March and are
equivalent to fifty percent (50%) of the peak day entitlement for the
period of April through September. The terms of the storage related
transportation contracts mirror the storage services that they support.
Delaware's contract with Gulf, which expires in 2004, provides firm
transportation capacity of 868 Dt per day for the period November through
March and 798 Dt per day for the period April through October.
Delaware's contracts with Eastern Shore include: (a) firm transportation
capacity of 25,560 Dt per day for the period December through February,
24,338 Dt per day for the months of November, March and April, and 15,262
Dt per day for the period May through October, with various expiration
dates ranging from 2004 to 2017; (b) firm storage capacity under Eastern
Shore's Rate Schedule GSS providing a peak day entitlement of 2,655 Dt and
a total capacity of 131,370 Dt, which expires in 2013; (c) firm storage
capacity under Eastern Shore's Rate Schedule LSS providing a peak day
entitlement of 580 Dt and a total capacity of 29,000 Dt, which expires in
2013; and (d) firm storage capacity under Eastern Shore's Rate Schedule LGA
providing a peak day entitlement of 911 Dt and a total capacity of 5,708
Dt, which expires in 2006. Delaware's firm transportation contracts with
Eastern Shore also include Eastern Shore's provision of swing
transportation service. This service includes: (a) firm transportation
capacity of 1,846 Dt per day on Transco's pipeline system, retained by
Eastern Shore, in addition to Delaware's Transco capacity referenced
earlier and (b) an interruptible storage service under Transco's Rate
Schedule ESS that supports a swing supply service provided under Transco's
Rate Schedule FS.
Delaware currently has contracts for the purchase of firm natural gas
supply with four (4) suppliers. These contracts provide the availability of
a maximum firm daily entitlement of 12,200 Dt and the supplies are
transported by Transco, Columbia, Gulf and Eastern Shore under Delaware's
transportation contracts. The gas purchase contracts have various
expiration dates.
Maryland. Maryland's contracts with Transco include: (a) firm
transportation capacity of 4,738 Dt per day, which expires in 2005; (b)
firm transportation capacity of 155 Dt per day for December through
February, expiring in 2006; and (c) firm storage service providing a total
capacity of 33,120 Dt. Maryland and Transco are currently engaged in
negotiations with regard to an extension of the term of the firm storage
service. Although the original contract expired in 1998, Transco and
Maryland have continued under the previous terms and conditions until an
agreement is finalized.
Maryland's contracts with Columbia include: (a) firm transportation
capacity of 442 Dt per day, which expires in 2004; (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 2004; and (e) firm storage service providing a
peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which
expires in 2017. Maryland's contracts with Columbia for storage related
transportation provide quantities that are equivalent to the peak day
entitlement for the period October through March and are equivalent to
fifty percent (50%) of the peak day entitlement for the period April
through September. The terms of the storage related transportation
contracts mirror the storage services that they support.
Maryland's contract with Gulf, which expires in 2004, provides firm
transportation capacity of 590 Dt per day for the period November through
March and 543 Dt per day for the period April through October.
Maryland's contracts with Eastern Shore include: (a) firm transportation
capacity of 13,378 Dt per day for the period December through February,
12,654 Dt per day for the months of November, March and April, and 8,093 Dt
per day for the period May through October; (b) firm storage capacity under
Eastern Shore's Rate Schedule GSS providing a peak day entitlement of 1,428
Dt and a total capacity of 70,665 Dt, which expires in 2013; (c) firm
storage capacity under Eastern Shore's Rate Schedule LSS providing a peak
day entitlement of 309 Dt and a total capacity of 15,500 Dt, which expires
in 2013; and (d) firm storage capacity under Eastern Shore's Rate Schedule
LGA providing a peak day entitlement of 569 Dt and a total capacity of
3,560 Dt, which expires in 2006. Maryland's firm transportation contracts
with Eastern Shore also include Eastern Shore's provision of swing
transportation service. This service includes: (a) firm transportation
capacity of 969 Dt per day on Transco's pipeline system, retained by
Eastern Shore, in addition to Maryland's Transco capacity referenced
earlier and (b) an interruptible storage service under Transco's Rate
Schedule ESS that supports a swing supply service provided under Transco's
Rate Schedule FS.
Maryland currently has contracts for the purchase of firm natural gas
supply with four (4) suppliers. These contracts provide the availability of
a maximum firm daily entitlement of 7,239 Dt and the supplies are
transported by Transco, Columbia, Gulf and Eastern Shore under Maryland's
transportation contracts. The gas purchase contracts have various
expiration dates.
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
21,123 Dt in May through September, 27,105 Dt in October, and 27,519 Dt in
November through April under FGT's firm transportation service (FTS-1) rate
schedule; (b) daily firm transportation capacity of 5,100 Dt in May through
October, and 8,100 Dt in November through April under FGT's firm
transportation service (FTS-2) rate schedule; and (c) daily interruptible
transportation capacity of 20,000 Dt under FGT's interruptible
transportation services (ITS-1) rate schedule. The firm transportation
contract (FTS-1) expires on August 1, 2000 with the Company retaining a
unilateral right to extend the term for an additional ten years. After the
expiration of the primary or secondary term, Chesapeake has the right to
first refuse to match the terms of any competing bids for the capacity. The
firm transportation contract (FTS-2) expires on March 1, 2015. The
interruptible transportation contract is effective until August 1, 2010 and
month to month thereafter unless canceled by either party with thirty days
notice.
The Florida division currently receives its gas supply from various
suppliers. If needed, some supply is bought on the spot market; however,
the majority is bought under the terms of two firm supply contacts with
Dynergy Marketing and Trade and Duke Energy. Availability of gas supply to
the Florida division is also expected to be adequate under existing
arrangements.
Competition
Competition with Alternative Fuels. Historically, the Company's natural gas
distribution divisions have successfully competed with other forms of
energy such as electricity, oil and propane. The principal consideration in
the competition between the Company and suppliers of other sources of
energy is price and, to a lesser extent, accessibility. All of the
Company's divisions have the capability of adjusting their interruptible
rates to compete with alternative fuels.
The divisions have several large volume industrial customers that have the
capacity to use fuel oil as an alternative to natural gas. When oil prices
decline, these interruptible customers convert to oil to satisfy their fuel
requirements. Lower levels in interruptible sales occur when oil prices
remain depressed relative to the price of natural gas. However, oil prices
as well as the prices of other fuels are subject to change at any time for
a variety of reasons; therefore, there is always uncertainty in the
continuing competition among natural gas and other fuels. In order to
address this uncertainty, the Company uses flexible pricing arrangements on
both the supply and sales side of its business to maximize sales volumes.
To a lesser extent than price, availability of equipment and operational
efficiency are also factors in competition among fuels, primarily in
residential and commercial settings. Heating, water heating and other
domestic or commercial equipment is generally designed for a particular
energy source, and especially with respect to heating equipment, the cost
of conversion is a disincentive for individuals and businesses to change
their energy source.
Competition within the Natural Gas Industry. FERC Order 636 enables all
natural gas suppliers to compete for customers on an equal footing. Under
this open access environment, interstate pipeline companies have unbundled
the traditional components of their service such as gas gathering,
transportation and storage from the sale of the commodity. If they choose
to be a merchant of gas, they must form a separate marketing operation
independent of their pipeline operations. Hence, gas marketers have
developed as a viable option for many companies because they are providing
expertise in gas purchasing along with collective purchasing capabilities
which, when combined, may reduce end-user cost.
Also resulting from an open access environment, the distribution division
can be in competition with the interstate transmission company if the
distribution customer is located close to the transmission company's
pipeline. The customers at risk are usually large volume commercial and
industrial customers with the financial resources and capability to bypass
the distribution division. In certain situations the distribution divisions
may adjust rates and services for these customers to retain their business.
Rates and Regulation
General. Chesapeake's natural gas distribution divisions are subject to
regulation by the Delaware, Maryland and Florida Public Service Commissions
with respect to various aspects of the Company's business, including the
rates for sales to all of their customers in each jurisdiction. All of
Chesapeake's firm distribution rates are subject to purchased gas
adjustment clauses, which match revenues with gas costs and normally allow
eventual full recovery of gas costs. Adjustments under these clauses
require periodic filings and hearings with the relevant regulatory
authority, but do not require a general rate proceeding. Rates on
interruptible sales by the Florida division are also subject to purchased
gas adjustment clauses.
Management monitors the rate of return in each jurisdiction in order to
ensure the timely filing of rate adjustment applications.
Regulatory Proceedings
Maryland. During the month of March 1997, the Maryland Public Service
Commission ("MPSC") approved an order authorizing Chesapeake to implement
new service offerings and rate design for services rendered on and after
April 1, 1997. The approved changes included: (1) class revenue
requirements and restructured sales services which provide for separate
firm commercial and industrial rate schedules for general service, medium
volume, large volume and high load factor customer groups; (2) unbundling
of gas costs from distribution charges; (3) a new gas cost recovery
mechanism, which utilizes a projected period under which the fixed cost
portion of the gas rate will be forecasted on an annual basis and the
commodity cost portion of the gas rate will be estimated quarterly, based
on projected market prices; and (4) a new sharing agreement under which
interruptible margins will continue to be shared, 90% to customers and 10%
to the Company, but distribution costs incurred for incremental load
additions can be recovered with carrying charges utilizing 100% of the
incremental margin if the payback period is within three years.
At the request of the MPSC Staff, consideration of the Company's proposed
new transportation services was postponed until Eastern Shore Natural Gas
Company's open access filing was settled with the FERC. As mentioned
previously, Eastern Shore Natural Gas Company became an open access
pipeline on November 1, 1997.
Chesapeake's Maryland division was involved in a roundtable collaborative
process with the MPSC Staff, customer representatives, third party
suppliers or marketers and the Maryland Office of People's Counsel during
the last half of 1997 and the first half of 1998, developing initial
transportation services for its commercial and industrial customers. The
MPSC issued an order in July 1998 authorizing the Company to implement
transportation and balancing services effective October 1, 1998 for
commercial and industrial customers with annual consumption over 30,000 Ccf
per year to transport customer-owned gas on the Company's distribution
system.
Delaware. In September 1998, Chesapeake's Delaware division filed an
application with the Delaware Public Service Commission ("DPSC") to propose
certain rate design changes to its existing margin sharing mechanism which
was approved in the Company's 1997 rate restructuring. Chesapeake filed
this application as an alternative to a base rate proceeding in order to
provide the Company an opportunity to earn its allowed rate of return,
without increasing the price of its natural gas services from the Company's
last rate case in 1995.
The Company proposed certain rate design changes to its currently existing
margin sharing mechanism in order to address the level of recovery of fixed
distribution costs from the residential heating service customers and
smaller commercial heating customers. Chesapeake proposed to modify the
existing margin sharing thresholds to address the actual level of fixed
distribution cost recovered from the residential and smaller commercial
customers based on the base tariff rates established in PSC Docket No. 95-
73, Phase II. Chesapeake's base tariff rates established in the last rate
case were designed to recover a certain amount of fixed distribution costs
in order for Chesapeake to earn its authorized rate of return. The proposal
increases or decreases the current margin sharing thresholds based on the
actual level of recovery of fixed distribution costs from these respective
customer classes as compared to the level which the base tariff rates were
designed to recover in the last rate case.
The Company also proposed to change the existing margin sharing mechanism
to take into consideration the appropriate treatment of margins achieved by
the addition of new interruptible customers on the distribution system for
which the Company makes capital investments to serve these customers.
Currently, Chesapeake is required to include in its margin sharing
calculation the margins achieved from all of its interruptible customers.
Chesapeake does not have the opportunity to earn a return on its capital
investments until base tariff rates are established in the context of a
base rate proceeding. The Company proposes to exclude from the margin
sharing mechanism the margins achieved from the addition of new
interruptible customers in order to provide the Company a reasonable
opportunity to earn its authorized rate of return until the Company's next
base rate proceeding.
During October 1998, the DPSC suspended the Company's tariff filing,
pending the completion of full evidentiary hearing(s) and a final decision
by the DPSC during 1999. During February 1999, the scheduled evidentiary
hearing was convened to introduce the Company's testimony and exhibits, as
well as DPSC Staff's testimony, into the record of evidence. The parties
deferred any cross-examination in this docket until March 1999 when the
hearing will reconvene. At this time, the Company and the respective
parties are engaged in discussions in an effort to reach a settlement on
the issues beneficial to all parties prior to the next scheduled hearing.
If a settlement cannot be reached among the parties in this docket, then
the hearing will reconvene in March 1999 and the issues will be determined
based on a formal commission proceeding. The DPSC most likely would issue a
final order in this docket during May or June 1999.
In February 1997, the DPSC approved an order authorizing Chesapeake to
implement new service offerings and rate design for services rendered on
and after March 1, 1997. The approved changes included: (1) restructured
sales services which provided commercial and industrial customers with
various service classifications such as general service, medium volume,
large volume, and high load factor services; (2) a modified purchased gas
cost recovery mechanism which takes into consideration the unbundling of
gas costs from distribution charges as well as charging certain firm
service classifications different gas cost rates based on the service
classification's load factor; (3) the implementation of a mechanism for
sharing interruptible, capacity release and off-system sales margins
between firm sales customers and the Company, with changing margin sharing
percentages based on the level of total margin achieved; and (4) a
provision for transportation and balancing services for commercial and
industrial customers with annual consumption over 30,000 Ccf per year to
transport customer-owned gas on the Company's distribution system. The
Company's Delaware division implemented these initial transportation and
balancing services on December 1, 1997 as a result of its pipeline
supplier, Eastern Shore Natural Gas Company, becoming an open access
pipeline on November 1, 1997.
Florida. On August 7, 1998, the Florida Division filed an administrative
request for approval to revise its tariff sheets to include Citrus County,
Florida in its service territory. On August 19, 1998, we received
notification that the tariff sheets had been approved by the PSC Staff. The
Company has executed service agreements with several customers in the area
and is in the process of securing franchise agreements with the cities of
Crystal River and Inverness. The Company's approved tariff sheets became
effective on September 10, 1998.
On July 15, 1998, the Florida Division filed a petition seeking the
authority to implement a flexible gas service tariff. This tariff is
designed to meet the Company's need to compete for potential customers who
have other viable energy options and to increase load by working with
customers with regard to specific terms and conditions of service. Approval
of this tariff would enable the Company to provide potential and existing
customers with flexible pricing and contract terms which would be precluded
under our existing tariff. On October 6, 1998, the Commission voted to
approve our Flexible Gas Service tariff. The tariff became effective upon
approval and is now available for use in negotiations with customers at the
sole option of the Company.
On May 7, 1998, the Company filed for approval of two transportation
agreements with Quincy Farms and Fernlea Nurseries. Both customers are
located in Gadsden County, Florida. The agreements provide for a
transportation rate equal to the non-fuel rate in existence prior to the
rate restructuring for the first two years of each contract. The majority
of our negotiations with these two customers took place prior to the rate
restructuring proceeding. The Company also requested modification of its
tariff sheets to include Gadsden County in its service territory. PSC Staff
issued its recommendation supporting the petition on June 18, 1998. The
Commission voted to approve the contracts and tariff sheet revisions on
June 30, 1998.
On November 26, 1997, the Florida Division filed a request with the Florida
Public Service Commission (FPSC) in Docket No. 971559-GU, for a Limited
Proceeding to Restructure Rates and for Approval of Gas Transportation
Agreements. The Florida Division has entered into Gas Transportation
Contracts with its two largest customers which resulted in retaining these
two customers on the Company's distribution system at rates lower than
previously achieved. As a result of this reduction in non-fuel revenue, the
Company has proposed in its application to restructure rates for its
remaining customers to more closely reflect the cost of service for each
rate class and to recover the level of revenues previously generated by the
two Contract customers.
The Company's restructuring proposal is revenue neutral. Approval of this
request would not result in additional revenues to the Company; however,
FPSC approval would enable the Company to retain its two largest customers
while providing the Company with the opportunity to achieve its FPSC
authorized rate of return.
FPSC Staff issued their recommendation in this docket on March 12, 1998.
The Commission voted to approve the Company's restructuring proposal on
March 24, 1998. A Commission Order on this docket was issued on March 31,
1998.
(i) (c) Propane Distribution and Marketing
General
Chesapeake's propane distribution group consists of Sharp Energy, Inc.
("Sharp Energy"), a wholly owned subsidiary of Chesapeake, its wholly owned
subsidiary, Sharpgas, Inc. ("Sharpgas") and Tri-County Gas Company, Inc.
("Tri-County") a wholly owned subsidiary of Chesapeake. The propane
marketing group consists of Xeron, Inc. ("Xeron"), a wholly owned
subsidiary of Chesapeake.
On May 30, 1998, Chesapeake acquired Xeron, a natural gas liquids trading
company located in Houston, Texas. Xeron markets propane to a number of
large independent and petrochemical companies, resellers, and southeastern
retail propane companies.
On March 6, 1997, the Company acquired Tri-County, a family-owned and
operated propane distribution business located in Salisbury and Pocomoke,
Maryland. The combined operations of the Company and Tri-County served
approximately 35,000 propane customers on the Delmarva Peninsula and
delivered approximately 26 million retail and wholesale gallons of propane
during 1998.
The propane distribution business is affected by many factors such as
seasonality, the absence of price regulation and competition among local
providers. The propane marketing business is affected by wholesale price
volatility and the demand and supply of propane at a wholesale level.
Propane is a form of liquefied petroleum gas which is typically extracted
from natural gas or separated during the crude oil refining process.
Although propane is gaseous at normal pressures, it is easily compressed
into liquid form for storage and transportation. Propane is a clean-burning
fuel, gaining increased recognition for its environmental superiority,
safety, efficiency, transportability and ease of use relative to
alternative forms of energy. Propane is sold primarily in suburban and
rural areas which are not served by natural gas pipelines. Demand is
typically much higher in the winter months and is significantly affected by
seasonal variations, particularly the relative severity of winter
temperatures, because of its use in residential and commercial heating.
Adequacy of Resources
Sharp Energy and Tri-County 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 a take-or-pay premiums) and maximum
purchase provisions.
Sharp Energy and Tri-County 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 Companies, to tanks located at the customer's premises.
Xeron has no physical storage facilities or equipment to transport propane;
however, they contract for storage and pipeline capacity to facilitate the
sale of propane on a wholesale basis.
Competition
Sharp Energy and Tri-County compete with several other propane distributors
in their service territories, primarily on the basis of service and price,
emphasizing reliability of service and responsiveness. Competition is
generally local because distributors located in close proximity to
customers incur lower costs of providing service. Propane competes with
electricity as an energy source, because it is typically less expensive
than electricity, based on equivalent BTU value. Since natural gas has
historically been less expensive than propane, propane is generally not
distributed in geographic areas serviced by natural gas pipeline or
distribution systems.
Xeron competes against various marketers that may have significantly great
resources and are able to obtain price or volumetric advantages over Xeron.
The Company's propane distribution and marketing activities are not subject
to any federal or state pricing regulation. Transport operations are
subject to regulations concerning the transportation of hazardous materials
promulgated under the Federal Motor Carrier Safety Act, which is
administered by the United States Department of Transportation and enforced
by the various states in which such operations take place. Propane
distribution operations are also subject to state safety regulations
relating to "hook-up" and placement of propane tanks.
The Company's propane operations are subject to all operating hazards
normally associated with the handling, storage and transportation of
combustible liquids, such as the risk of personal injury and property
damage caused by fire. The Company carries general liability insurance in
the amount of $35,000,000 per occurrence, but there is no assurance that
such insurance will be adequate.
(i) (d) Advanced Information Services
General
Chesapeake's advanced information services segment is comprised of United
Systems, Inc. ("USI") and Capital Data Systems, Inc. ("CDS"), both wholly
owned subsidiaries of the Company. CDS provided programming support for
application software, until the first quarter of 1997, at which time it
disposed of substantially all of its assets.
USI is an Atlanta-based company that primarily provides support for users
of PROGRESST, a fourth generation computer language and Relational Database
Management System. USI offers consulting, training, software development
"tools", web development and customer software development for its client
base, which includes many large domestic and international corporations.
Competition
The advanced information services businesses face significant competition
from a number of larger competitors having substantially greater resources
available to them than the Company. In addition, changes in the advanced
information services businesses are occurring rapidly, which could
adversely impact the markets for the Company's products and services.
(i) (e) Other Subsidiaries
Skipjack, Inc. ("Skipjack") and Chesapeake Investment Company ("Chesapeake
Investment"), are wholly owned subsidiaries of Chesapeake Service Company.
Skipjack owns and leases two office buildings in Dover, Delaware to
affiliates. Chesapeake Investment is a Delaware affiliated investment
company.
On March 30, 1998, the Company acquired Sam Shannahan Well Co., based in
Salisbury, Maryland, operating as Tolan Water Service ("Tolan"). Tolan was
a privately owned company serving 3,000 customers on the Delmarva Peninsula
with divisions supporting residential, commercial and industrial water
treatment.
On March 6, 1997, in connection with the acquisition of Tri-County, the
Company acquired Eastern Shore Real Estate, Inc. ("ESR"), which became a
wholly owned subsidiary of Chesapeake Service Company. ESR owns and leases
office buildings to affiliates and external companies.
(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
Chesapeake has 456 employees, including 165 in natural gas distribution and
transmission, 135 in propane distribution, 7 in propane marketing, 81 in
advanced information services and 25 in water conditioning. The remaining
43 employees are considered general and administrative and include officers
of the Company, treasury, accounting, information technology, human
resources and other administrative personnel. The acquisition of Tolan
Water Service added 25 employees, while the Xeron acquisition added 7
employees.
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, Delaware; Plant City, Florida; Chincoteague and Belle
Haven, Virginia; Easton and Pocomoke, Maryland; Detroit, Michigan; Houston,
Texas and Atlanta, Georgia. In general, the properties of the Company are
adequate for the uses for which they are employed. Capacity and utilization of
the Company's facilities can vary significantly due to the seasonal nature of
the natural gas and propane distribution businesses.
(b) Natural Gas Distribution
Chesapeake owns over 576 miles of natural gas distribution mains (together
with related service lines, meters and regulators) located in its Delaware and
Maryland service areas, and 474 miles of such mains (and related equipment) in
its Central Florida service areas. Chesapeake also owns facilities in Delaware
and Maryland for propane-air injection during periods of peak demand. Portions
of the properties constituting Chesapeake's distribution system are encumbered
pursuant to Chesapeake's First Mortgage Bonds.
(c) Natural Gas Transmission
Eastern Shore owns approximately 273 miles of transmission lines extending
from Parkesburg, Pennsylvania to Salisbury, Maryland. Eastern Shore also owns
three compressor stations located in Delaware City, Delaware; Daleville,
Pennsylvania and Bridgeville, Delaware. The Delaware City compressor facility
and associated piping are needed to stabilize capacity on Eastern Shore's
system as a result of steadily declining inlet pressures at the Hockessin
interconnect with Transco. The Daleville station is used to increase Columbia
supply pressures to match Transco supply pressures, and to increase Eastern
Shore's pressures in order to serve Eastern Shore's firm customers' demands,
including those of Chesapeake's Delaware and Maryland divisions. The
Bridgeville station is being used to provide increased pressures required to
meet demands on the system.
(d) Propane Distribution and Marketing
Sharpgas and Tri-County own bulk propane storage facilities with an aggregate
capacity of approximately 1.9 million gallons at 32 plant facilities in
Delaware, Maryland and Virginia, located on real estate they either own or
lease. Xeron has no physical storage facilities or equipment to transport
propane.
Item 3. Legal Proceedings
(a) General
The Company and its subsidiaries are involved in certain legal actions and
claims arising in the normal course of business. The Company is also involved
in certain legal and administrative proceedings before various governmental
agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings will not have a material effect on the
consolidated financial position of the Company.
(b) Environmental
Dover Gas Light Site
In 1984, the State of Delaware notified the Company that a parcel of land it
purchased in 1949 from Dover Gas Light Company, a predecessor gas company,
contained hazardous substances. The State also asserted that the Company is
responsible for any clean-up and prospective environmental monitoring of the
site. The Delaware Department of Natural Resources and Environmental Control
("DNREC") investigated the site and surroundings, finding coal tar residue and
some ground-water contamination.
In October 1989, the Environmental Protection Agency Region III ("EPA") listed
the Dover site on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA" or
"Superfund"). At that time under CERCLA, both the State of Delaware and the
Company were named as potentially responsible parties ("PRPs") for clean-up of
the site.
The EPA issued the site Record of Decision ("ROD") dated August 16, 1994. The
remedial action selected by the EPA in the ROD addressed the ground-water
contamination with a combination of hydraulic containment and natural
attenuation. Remediation selected for the soil at the site was to meet
stringent cleanup standards for the first two feet of soil and less stringent
standards for the soil below two feet. The ROD estimated the costs of selected
remediation of ground-water and soil at $2.7 million and $3.3 million,
respectively.
In May 1995, EPA issued an order to the Company under section 106 of CERCLA
(the "Order"), which required the Company to fund or implement the ROD. The
Order was also issued to General Public Utilities Corporation, Inc. ("GPU"),
which both EPA and the Company believe is liable under CERCLA. Other PRPs such
as the State of Delaware were not ordered to perform the ROD. EPA may seek
judicial enforcement of its Order, as well as significant financial penalties
for failure to comply. Although notifying EPA of objections to the Order, the
Company agreed to comply. GPU informed EPA that it did not intend to comply
with the Order.
In March 1995, the Company commenced litigation against the State of Delaware
for contribution to the remedial costs being incurred to carry out the ROD. In
December of 1995, this case was dismissed without prejudice based on a
settlement agreement between the parties (the "Settlement"). Under the
Settlement, the State agreed to: support the Company's proposal to reduce the
soil remedy for the site, described below; contribute $600,000 toward the cost
of implementing the ROD and reimburse the EPA for $400,000 in oversight costs.
The Settlement is contingent upon a formal settlement agreement between EPA
and the State of Delaware. Upon satisfaction of all conditions of the
Settlement, the litigation will be dismissed with prejudice.
In June 1996, the Company initiated litigation against GPU for contribution to
the remedial costs incurred by Chesapeake in connection with complying with
the ROD. At this time, management cannot predict the outcome of the litigation
or the amount of proceeds to be received, if any.
In July 1996, the Company began the design phase of the ROD, on-site pre-
design and investigation. A pre-design investigation report ("the report") was
filed in October 1996 with the EPA. The report, which required EPA approval,
provided up to date status on the site, which the EPA used to determine if the
remedial design selected in the ROD was still the appropriate remedy.
In the report, the Company proposed a modification to the soil clean-up remedy
selected in the ROD to take into account an existing land use restriction
banning future development at the site. In April of 1997, the EPA issued a
fact sheet stating that the EPA was considering the proposed modification. The
fact sheet included an overall cost estimate of $5.7 million for the proposed
modified remedy and a new overall cost estimate of $13.2 million for the
remedy selected in the ROD. On August 28, 1997, the EPA issued a Proposed Plan
to modify, with respect to soil remediation only, the current clean-up plan
that would involve the following three elements: (1) excavation and off-site
thermal treatment of the contents of the former subsurface gas holders; (2)
implementation of soil vaporization extraction; and (3) pavement of the
parking lot. The overall estimated clean-up cost of the site under the
proposed plan was $4.2 million ($1.5 million for soil remediation and $2.7
million for ground-water remediation) as compared to the ROD cleanup estimate
of $6.0 million ($3.3 million for soil remediation and $2.7 million for
ground-water remediation). In January 1998, the EPA issued a ROD Amendment,
which modified the soil remediation to conform to the proposed plan and
included the estimated soil clean-up costs of $4.2 million.
During the fourth quarter of 1998 the Company completed the first element of
the soil remediation at the Dover site at a cost of $450,000. Over the next
twelve to eighteen months the Company will finalize the remaining two elements
of the soil remediation and initiate the ground-water remedial activities.
The Company's independent consultants have prepared preliminary cost estimates
of two potentially acceptable alternatives to complete the ground-water
remediation activities at the site. The costs range from a low of $390,000 in
capital and $37,000 per year of operating costs for 30 years for natural
attenuation to a high of $4.0 million in capital and $500,000 per year in
operating costs for 30 years for a pump and treat system. A decision by the
EPA as to the most appropriate ground-water remediation method is likely in
1999. The capital costs necessary to begin ground-water remediation are
expected to be incurred over the next twelve to eighteen months.
The Company cannot predict which ground-water remediation method will be
selected by the EPA and accordingly, has accrued $2.1 million at December 31,
1998 for the Dover site, as well as a regulatory asset for an equivalent
amount. Of this amount, $1.5 million is for ground-water remediation and
$600,000 is for the remaining soil remedition. The $1.5 million represents the
low end of the ground-water remedy estimates described above. As of December
31, 1997, the Company had accrued both a liability and a regulatory asset of
$4.2 million. The Company is currently engaged in investigations related to
additional parties who may be PRPs. Based upon these investigations, the
Company will consider suit against other PRPs. The Company expects continued
negotiations with PRPs in an attempt to resolve these matters.
Management believes that in addition to the $600,000 expected to be
contributed by the State of Delaware under the Settlement, the Company will be
equitably entitled to contribution from other responsible parties for a
portion of the expenses to be incurred in connection with the remedies
selected in the ROD. The Company expects that it will be able to recover
actual costs incurred (exclusive of carrying costs), which are not recovered
from other responsible parties, through the ratemaking process in accordance
with the existing environmental cost recovery rider provisions described
below.
As of December 31, 1998, the Company has incurred approximately $6.6 million
in costs relating to environmental testing and remedial action studies. In
1990, the Company entered into settlement agreements with a number of
insurance companies resulting in proceeds to fund actual environmental costs
incurred over a five to seven-year period. In 1995, the Delaware Public
Service Commission, authorized recovery of all unrecovered environmental costs
incurred by a means of a rider (supplement) to base rates, applicable to all
firm service customers. The costs, exclusive of carrying costs, would be
recovered through a five-year amortization offset by the deferred tax benefit
associated with those environmental costs. The deferred tax benefit equals the
projected cash flow savings realized by the Company in connection with a
reduced income tax liability due to the possibility of accelerated deduction
allowed on certain environmental costs when incurred. Each year a new rider
rate is calculated to become effective December 1. The rider rate is based on
the amortization of expenditures through September of the filing year plus
amortization of expenses from previous years. The advantage of the rider is
that it is not necessary to file a rate case every year to recover expenses
incurred. As of December 31, 1998, the unamortized balance and amount of
environmental costs not included in the rider, effective January 1, 1999 were
$2.5 million and $679,000, respectively. With the rider mechanism established,
it is management's opinion that these costs and any future cost, net of the
deferred income tax benefit, will be recoverable in rates.
Salisbury Town Gas Light Site
In cooperation with the Maryland Department of the Environment ("MDE"), the
Company completed assessment of the Salisbury manufactured gas plant site,
determining that there was localized ground-water contamination. During 1996,
the Company completed construction and began the Air Sparging and Soil-Vapor
Extraction remediation procedures. Chesapeake has been reporting the
remediation and monitoring results to the Maryland Department of the
Environment on an ongoing basis since 1996.
The cost of remediation is estimated at $136,000 per year for operating
expenses for five years. Based on these estimated costs, the Company recorded
both a liability and a deferred regulatory asset of $600,000 on December 31,
1998, to cover the Company's projected remediation costs for this site. As of
December 31, 1998, the Company has incurred approximately $2.5 million for
remedial actions and environmental studies and has charged such costs to
accumulated depreciation. In January 1990, the Company entered into settlement
agreements with a number of insurance companies resulting in proceeds to fund
actual environmental costs incurred over a three to five-year period beginning
in 1990. The final insurance proceeds were requested and received in 1992. In
December 1995, the Maryland Public Service Commission approved recovery of all
environmental cost incurred through September 30, 1995 less amounts previously
amortized and insurance proceeds. The amount approved for a 10-year
amortization was $964,251. Of the $2.5 million in costs reported above,
approximately $770,000 has not been recovered through insurance proceeds or
received ratemaking treatment. It is management's opinion that these costs
incurred and future costs incurred, if any, will be recoverable in rates.
Winter Haven Coal Gas Site
In May 1996, the Company filed an Air Sparging and Soil Vapor Extraction Pilot
Study Work Plan for the Winter Haven site with the Florida Department of
Environmental Protection ("FDEP"). The Work Plan described the Company's
proposal to undertake an Air Sparging and Soil Vapor Extraction ("AS/SVE")
pilot study to evaluate at the site. After discussions with the FDEP, the
Company filed a modified AS/SVE Pilot Study Work Plan, scope of work to
complete the site assessment activities and a report describing a limited
sediment investigation performed recently. The Company is awaiting FDEP's
comments to the modified Work Plan. It is not possible to determine whether
remedial action will be required by FDEP and, if so, the cost of such
remediation.
The Company has spent and received ratemaking treatment of approximately
$697,000 on these investigations as of December 31, 1998. The Company has been
allowed by the Florida Public Service Commission to continue to accrue for
future environmental costs. At December 31, 1998, the Company had $501,000
accrued. It is management's opinion that future costs, if any, will be
recoverable in rates.
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 10. Executive Officers of the Registrant
Information pertaining to the Executive Officers of the Company is as follows:
Ralph J. Adkins (age 56) Mr. Adkins is Chairman of the Board of Chesapeake.
He has served as Chairman of the Board since August 1997. Previously, Mr.
Adkins served as Chairman of the Board and Chief Executive Officer,
President and Chief Executive Officer, President and Chief Operating
Officer, Executive Vice President, Senior Vice President, Vice President
and Treasurer of Chesapeake. Mr. Adkins is Chairman of Chesapeake Service
Company, Sharp Energy, Inc., Tri-County Gas Company, Inc., Chesapeake
Investment Company, Xeron, Inc., Sam Shannahan Well Co. and Eastern Shore
Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He has
been a director of Chesapeake since 1989.
John R. Schimkaitis (age 51) Mr. Schimkaitis is President and Chief
Executive Officer. He has served in this position since January 1, 1999.
Mr. Schimkaitis is also Chief Executive Officer of Chesapeake Service
Company, Sharp Energy, Inc., Tri-County Gas Company, Chesapeake Investment
Company, Xeron, Inc., Sam Shannahan Well Co. and Eastern Shore Natural Gas
Company, all wholly owned subsidiaries of Chesapeake. He previously served
as President and Chief Operating Officer, Executive Vice President, Chief
Financial Officer, Senior Vice President, Treasurer and Assistant
Secretary. From 1983 to 1986, Mr. Schimkaitis was Vice President of Cooper
& Rutter, Inc., a consulting firm providing financial services to the
utility and cable industries. He was appointed as a director of Chesapeake
in February 1996.
Michael P. McMasters (age 40) Mr. McMasters is Vice President, Chief
Financial Officer and Treasurer of Chesapeake Utilities Corporation. He has
served as Vice President, Chief Financial Officer and Treasurer since
December 1996. He previously served as Vice President of Eastern Shore,
Director of Accounting and Rates and Controller. From 1992 to May 1994, Mr.
McMasters was employed as Director of Operations Planning for Equitable Gas
Company.
Stephen C. Thompson (age 38) Mr. Thompson is Vice President of the Natural
Gas Operations, as well as Vice President of Chesapeake Utilities
Corporation. He has served as Vice President since May 1997. He has served
as President, Vice President, Manager, Director of Gas Supply and
Marketing, Superintendent of Eastern Shore and Regional Manager for the
Florida distribution Operations.
Philip S. Barefoot (age 51) Mr. Barefoot joined Chesapeake as Division
Manager of Florida Operations in July 1988. In May 1994, he was elected
Vice President of Chesapeake Utilities Corporation. Prior to joining
Chesapeake, he was employed by Peoples Natural Gas Company where he held
the positions of Division Sales Manager, Division Manager and Vice
President of Florence Operations.
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
1998 and 1997 were as follows:
- ----------------------------------------------------------------------------
Dividends
Declared
Quarter Ended High Low Close Per Share
- ----------------------------------------------------------------------------
1998
March 31 $20.500 $18.250 $18.375 $0.2500
June 30 18.500 17.125 17.625 0.2500
September 30 18.500 16.500 17.938 0.2500
December 31 18.500 17.000 18.938 0.2500
- ----------------------------------------------------------------------------
1997
March 31 $18.000 $16.500 $17.375 $0.2425
June 30 17.500 16.000 17.000 0.2425
September 30 18.500 16.250 18.375 0.2425
December 31 21.750 18.375 20.500 0.2425
- ----------------------------------------------------------------------------
In addition to the dividends declared by the Company, Xeron paid total
dividends of $27,000 during 1998.
Indentures to the long-term debt of the Company and its subsidiaries contain a
restriction that the Company cannot, until the retirement of its Series I Bonds,
pay any dividends after December 31, 1988 which exceed the sum of $2,135,188
plus consolidated net income recognized on or after January 1, 1989. As of
December 31, 1998, the amounts available for future dividends permitted by the
Series I covenant are $14.7 million.
At December 31, 1998, there were approximately 2,271 shareholders of record.
(b) Issuance of shares:
On May 29, 1998, in conjunction with the acquisition of Xeron, Inc., the Company
issued 475,000 shares of common stock to J. Phillip Keeter, Earnest Allen Jr.
and Patrick E. Armand in reliance on the private placement exemption provided by
Section 4(c) of the Securities Act of 1933 and Regulation D, thereunder.
On March 31, 1998, in conjunction with the acquisition of Sam Shannahan Well
Co., the Company issued 25,000 shares of company stock to Deshield J. Shannahan
and Joyce C. Shannahan in reliance on the private placement exemption provided
by Section 4(c) of the Securities Act of 2933 and Regulation D, thereunder.
Item 6. Selected Financial Data
- -----------------------------------------------------------------------------------------------------------------
(dollars in thousands except stock data)
For the Years Ended December 31, 1998 1997 1996 1995 1994 (1)
- -----------------------------------------------------------------------------------------------------------------
Operating
Operating revenues $183,569 $222,489 $260,102 $235,285 $ 98,572
Operating income $ 8,441 $ 8,666 $ 10,099 $ 9,962 $ 7,227
Net income $ 5,303 $ 5,868 $ 7,782 $ 7,696 $ 4,460
- -----------------------------------------------------------------------------------------------------------------
Balance Sheet
Gross plant $152,991 $144,251 $134,001 $120,746 $110,023
Net plant $104,266 $ 99,879 $ 94,014 $ 85,055 $ 75,313
Total assets $145,234 $145,719 $155,786 $130,998 $108,271
Long-term debt, net $ 37,597 $ 38,226 $ 28,984 $ 31,619 $ 24,329
Common stockholders' equity $ 56,356 $ 53,656 $ 50,699 $ 45,587 $ 37,063
Capital expenditures $ 12,650 $ 13,471 $ 15,399 $ 12,887 $ 10,653
- -----------------------------------------------------------------------------------------------------------------
Common Stock
Earnings per share:
Basic $ 1.05 $ 1.18 $ 1.58 $ 1.59 $ 1.23
Diluted $ 1.04 $ 1.17 $ 1.55 $ 1.56 $ 1.20
Average shares outstanding 5,060,328 4,972,086 4,912,136 4,836,430 3,628,056
Cash dividends per share $ 1.00 $ 0.97 $ 0.93 $ 0.90 $ 0.88
Book value per share $ 11.06 $ 10.72 $ 10.26 $ 9.38 $ 10.15
Common equity/Total capitalization 59.98% 58.40% 63.63% 59.05% 60.37%
Return on equity 9.41% 10.94% 15.35% 16.88% 12.03%
- -----------------------------------------------------------------------------------------------------------------
Other
Number of employees 456 429 418 415 320
Number of registered shareholders 2,271 2,178 2,213 2,098 1,721
Heating degree days 3,704 4,430 4,717 4,594 4,398
Heating degree days (10-year average) 4,579 4,596 4,586 4,564 4,588
- -----------------------------------------------------------------------------------------------------------------
(1) 1994 has not been restated to include the business combinations with Tri-County Gas
Company, Inc., Tolan Water Service or Xeron, Inc.
[GRAPH APPEARS HERE]
Growth in Book Value
Compared to Dividend Growth
Book Dividends
Year Value Per Share
---- ----- ---------
1994 $10.15 $0.88
1995 $9.37 $0.90
1996 $10.26 $0.93
1997 $10.72 $0.97
1998 $11.06 $1.00
[GRAPH APPEARS HERE]
Earnings Compared to Heating
Degree Days
Heating
Degree
Year Earnings Days
---- -------- -------
1994 $1.23 4,398
1995 $1.59 4,594
1996 $1.58 4,717
1997 $1.18 4,430
1998 $1.05 3,704
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Liquidity and Capital Resources
The capital requirements of Chesapeake Utilities Corporation ("Chesapeake" or
"the Company") reflect the capital-intensive nature of its business and are
attributable principally 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 finance capital expenditures. During 1998, net cash provided by
operating activities was $11.0 million, cash used by investing activities was
$12.5 million and cash used by financing activities was $737,000.
The Board of Directors has authorized the Company to borrow up to $20.0
million from various banks and trust companies. As of December 31, 1998,
Chesapeake had three unsecured bank lines of credit, totaling $28.0 million,
for short-term cash needs to meet seasonal working capital requirements and to
temporarily fund portions of its capital expenditures. The outstanding
balances of short-term borrowing at December 31, 1998 and 1997 were $11.6
million and $7.6 million, respectively.
In 1998, Chesapeake used cash provided by operations and short-term borrowing
to fund capital expenditures. During 1997, the Company used cash provided by
operations and the issuance of long-term debt to fund capital expenditures and
reduce short-term borrowing.
During 1998, 1997 and 1996, capital expenditures were approximately $12.0
million, $12.4 million and $14.0 million, respectively. Chesapeake has
budgeted $22.7 million for capital expenditures during 1999. This amount
includes $10.5 million and $8.6 million for natural gas distribution and
transmission, respectively, $1.8 million for propane distribution and
marketing, $336,000 for advanced information services and $1.5 million for
general plant. The natural gas distribution expenditures are for expansion and
improvement of facilities in existing service territories. Natural gas
transmission expenditures are for improvement and expansion of the pipeline
system, specifically, the construction of eight miles of pipeline to provide
additional firm transportation capacity to two existing customers. The propane
expenditures are to support customer growth and the replacement of older
equipment. The advanced information services expenditures are for computer
hardware, software and related equipment. General expenditures are for
building improvements, computer software and hardware. Financing for the 1999
construction program is expected to be provided from short-term borrowing and
cash from operations. The construction program is subject to continuous review
and modification. Actual construction expenditures may vary from the above
estimates due to a number of factors including acquisition opportunities,
changing economic conditions, customer growth in existing areas, regulation
and new growth opportunities.
Chesapeake has budgeted $2.2 million for environmental related expenditures
during 1999 and expects to incur additional expenditures in future years, a
portion of which may need to be financed through external sources (see Note L
to the Consolidated Financial Statements). Management does not expect such
financing to have a material adverse effect on the financial position or
capital resources of the Company.
Capital Structure
As of December 31, 1998, common equity represented 60.0% of permanent
capitalization, compared to 58.4% in 1997 and 63.6% in 1996. 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, helps to ensure that Chesapeake
will be able to attract capital from outside sources at a reasonable cost. The
achievement of these objectives will provide benefits to customers and
creditors, as well as to the Company's investors.
Financing Activities
On March 31, 1998, Chesapeake acquired Sam Shannahan Well Co., Inc., operating
as Tolan Water Service ("Tolan" or "Tolan Water") in exchange for 25,000
shares of Chesapeake's common stock. Tolan provides water conditioning
services to approximately 3,000 residential, commercial and industrial
customers on the Delmarva Peninsula.
All of the outstanding common stock of Xeron, Inc. ("Xeron") was acquired by
Chesapeake on May 29, 1998. Xeron markets propane to a number of large
independent oil and petrochemical companies, resellers, and southeastern
retail propane companies. Four hundred seventy-five thousand shares of the
Company's common stock were exchanged in the transaction.
On March 6, 1997, the Company acquired all of the outstanding common stock of
Tri-County Gas Company, Inc. ("Tri-County") and associated properties. Tri-
County distributes propane to both retail and wholesale customers on the
Delmarva Peninsula. The transaction was effected through the exchange of
639,000 shares of the Company's common stock.
Each of these business combinations was accounted for as a pooling of
interests.
During 1998, Chesapeake repaid approximately $1.1 million of long-term debt.
In December 1997, Chesapeake finalized a private placement of $10 million of
6.85% Senior Notes due January 1, 2012. Debt repayments during 1997 totaled
$3.1 million. In 1996, Chesapeake repaid $881,000 in long-term debt.
Chesapeake issued 32,925, 32,169 and 33,926 shares of common stock in
connection with its Automatic Dividend Reinvestment and Stock Purchase Plan
during the years of 1998, 1997 and 1996, respectively.
Results of Operations
Net income for 1998 was $5.3 million as compared to $5.9 million for 1997 and
$7.8 million for 1996. The decrease in net income is primarily related to
warmer temperatures in the Company's northern service territory, partially
offset by a one-time reduction in pension costs of $1.2 million resulting from
Chesapeake's 1998 restructuring of the Company's retirement benefits plans.
Temperatures in 1998, based upon heating degree days, were 19% warmer than
normal, 16% warmer than 1997 and 21% warmer than 1996. Temperatures in 1997
were approximately 6% warmer than those experienced in 1996. Normal weather
conditions are calculated from the most recent ten years of temperature data
measured in heating degree days. The warmer weather resulted in a reduction in
volumes sold by both the natural gas distribution and propane segments. The
lower volumes contributed to the reduction in Earnings Before Interest and
Taxes ("EBIT") for both segments as shown in the table below.
EARNINGS BEFORE INTEREST AND TAXES (in thousands):
- ------------------------------------------------------------------------------------------------
Increase Increase
For the Years Ended December 31, 1998 1997 (decrease) 1997 1996 (decrease)
- ------------------------------------------------------------------------------------------------
EBIT by Business Segment:
Natural gas distribution $ 4,697 $ 5,498 $ (801) $ 5,498 $ 7,167 $(1,669)
Natural gas transmission 4,117 3,721 396 3,721 2,458 1,263
Propane distribution and marketing 971 1,158 (187) 1,158 2,669 (1,511)
Advanced information services 1,316 1,046 270 1,046 1,056 (10)
Other 522 671 (149) 671 633 38
- ------------------------------------------------------------------------------------------------
Total EBIT $11,623 $12,094 $ (471) $12,094 $13,983 $(1,889)
================================================================================================
Natural Gas Distribution
The $801,000 reduction in EBIT from 1997 to 1998 was primarily the result of a
reduction in gross margin, as indicated in the following table. Exclusive of
the expense reductions related to the restructuring of the Company's
retirement benefits plans, the decrease in EBIT of $1.5 million or 27% was
attributable to warmer than normal weather conditions. The reduction in gross
margin of $832,000 from the prior year is primarily due to the negative impact
of warmer temperatures on volumes sold, partially offset by customer growth
during the year. After taking into account customer growth of 4% for
residential and commercial customers in the northern service territory,
overall volumes declined by 12% for these customer classifications. Under
normal temperatures and customer usage, the 4% customer growth is estimated to
generate an additional margin of $550,000 annually within this segment. Also
contributing to the decline in margin is an 11% reduction in volumes sold and
transported to industrial customers in the Florida service territory. Although
operating expenses remained relatively unchanged, specific expense categories
such as marketing, building rent, legal costs and depreciation and
amortization increased. These were offset by decreases in pension expense,
administrative fees associated with the pension plan, compensation and outside
services.
The reduction in EBIT of $1.7 million from 1996 to 1997 is primarily related
to a decline in total gross margin, as indicated in the following table,
coupled with an overall increase in expenses. The reduction in gross margin is
primarily the result of a 4% decline in volumes sold to residential and
commercial customers and a 5% decrease in volumes sold and transported to
industrial customers in Chesapeake's Florida service territory. The reduction
in volumes sold to residential and commercial customers was directly related
to warmer temperatures, primarily during the first quarter of 1997. Operating
expenses increased $996,000 due to increases in compensation, regulatory
commission expenses, and costs related to data processing and billable service
revenue. In addition, there was a greater level of maintenance to the gas
pipeline system and increased depreciation and amortization due to additional
plant being placed in service.
NATURAL GAS DISTRIBUTION GROSS MARGIN SUMMARY (in thousands)
- -----------------------------------------------------------------------------------------------
Increase Increase
For the Years Ended December 31, 1998 1997 (decrease) 1997 1996 (decrease)
- -----------------------------------------------------------------------------------------------
Revenues:
Gas sold $50,466 $54,205 $ (3,739) $54,205 $52,290 $ 1,915
Gas transported 2,875 3,061 (186) 3,061 2,991 70
Gas marketed 11,683 18,419 (6,736) 18,419 19,382 (963)
Other 401 275 126 275 193 82
- -----------------------------------------------------------------------------------------------
Total Revenues $65,425 $75,960 $(10,535) $75,960 $74,856 $ 1,104
===============================================================================================
Cost of Sales: *
Gas sold $32,529 $35,507 $ (2,978) $35,507 $32,846 $ 2,661
Gas marketed 11,508 18,233 (6,725) 18,233 19,117 (884)
- -----------------------------------------------------------------------------------------------
Total Cost of Sales $44,037 $53,740 $ (9,703) $53,740 $51,963 $ 1,777
===============================================================================================
Gross Margin:
Gas sold $17,937 $18,698 $ (761) $18,698 $19,444 $ (746)
Gas transported 2,875 3,061 (186) 3,061 2,991 70
Gas marketed 175 186 (11) 186 265 (79)
Other 401 275 126 275 193 82
- -----------------------------------------------------------------------------------------------
Total Gross Margin $21,388 $22,220 $ (832) $22,220 $22,893 $ (673)
===============================================================================================
* Transportation service does not have an associated cost of sales.
Natural Gas Transmission
The Earnings Before Interest and Taxes of the Company's natural gas
transmission segment increased $396,000 from 1997 to 1998. This was the result
of an increase in gross margin of $468,000 offset by an $87,000 increase in
operating expenses. Exclusive of the expense reduction related to the
restructuring of the Company's retirement benefits plans, EBIT increased
$221,000 or 6%. Gross margin increased under a full year of open access
pipeline operations, as well as the full year's effect of both a rate increase
and the implementation of new services which were both effective in 1997.
Operating expenses were higher due to increases in regulatory commission
expenses, legal fees, pipeline system maintenance and depreciation. These
costs were offset by declines in pension costs, compensation and
administrative fees associated with the pension plan.
The transmission segment's EBIT increased $1.3 million from 1996 to 1997. The
rise in EBIT was partially attributable to a rate increase and an increase in
firm services implemented in 1997, as well as an overall reduction in
expenses. Also contributing to the increase in EBIT were additional revenues
generated by the increase in transportation services that were effective with
the implementation of open access. Operating expenses decreased by $124,000 or
3%, primarily due to reduced compensation, relocation costs, property
insurance and pipeline system maintenance. These reductions were offset by
higher depreciation expenses generated by capital additions during the year.
Propane Distribution and Marketing
In May 1998, the Company acquired Xeron, Inc., a wholesale marketer of
propane, expanding Chesapeake's propane operations (see Note B to the
Consolidated Financial Statements). The EBIT contribution of the propane
distribution and marketing segment declined by $187,000 from 1997 to 1998 due
to a decrease in gross margin which was partially offset by a decline in
operating expenses. Exclusive of the expense reduction related to the
restructuring of the Company's retirement benefits plans, EBIT decreased
$463,000 or 40%. The propane distribution operation was negatively affected by
the warmer temperatures realized in 1998, resulting in a decline in sales
volumes of 8%, after taking into account a 3% increase in customer growth.
Somewhat offsetting this volume-related decline in margin was an increase of
6% in the margin earned per gallon delivered as compared to the prior year. In
addition, the lack of volatility in the wholesale propane market resulted in a
reduction to propane marketing margins due to fewer gallons being marketed.
Wholesale marketing is a high volume, low margin business. During 1998,
marketing revenues declined by $18.1 million or 18% while margins declined by
$250,000 or 16%. Operating expenses declined primarily due to compensation
linked to Xeron's earnings, pension expense and administrative fees associated
with the pension plan.
The Company estimates that the warm temperatures experienced in 1998 reduced
EBIT by $1.9 million when compared to normal temperatures. In addition,
margins during 1998 were lower than historical norms, further reducing EBIT by
approximately $1.6 million.
The reduction in EBIT of $1.5 million from 1996 to 1997 was primarily due to a
reduction in gross margin earned by the distribution operation, partially
offset by a reduction in operating expenses. Distribution margins decreased
due to a 14% reduction in sales volumes coupled with a 13% lower margin per
gallon sold. The decline in sales volumes is directly related to the warmer
temperatures which averaged 6% warmer than those experienced in 1996.
Furthermore, during the first quarter of 1997, temperatures were 14% warmer
than normal. The marketing operation contributed an additional $240,000 to
EBIT due to a reduction in compensation expense.
Advanced Information Services
The results of the advanced information services segment consisted primarily
of those of United Systems, Inc. ("USI"). Exclusive of the expense reductions
related to the restructuring of the Company's retirement benefits plans, EBIT
contributed by USI increased 15% or $156,000 from 1997 to 1998. Due to
increased opportunities in areas such as website development, training and
consulting, gross margin increased 38%, or $1.5 million from 1997 to 1998.
Although the EBIT contribution of this segment remained virtually unchanged
from 1996 to 1997, USI's gross margin increased by $970,000 or 34%. Operating
expenses increased due to the opening of a new office in Detroit, Michigan and
the expansion of staff training and marketing efforts to position USI to be
able to provide new services and for future growth of current services. Since
the rise in operating costs offset most of the growth in gross margin, EBIT
remained constant.
Income Taxes
Operating income taxes decreased $245,000 in 1998 due to the reduction in
EBIT. Income taxes also decreased in 1997 due to the reduction in EBIT. This
was partially offset by a one-time expense to establish the deferred income
tax liability in connection with the 1997 acquisition of Tri-County. The 1996
financial statements do not include any income tax expense for the acquisition
due to its subchapter S status during that year.
Other
Non-operating income was $241,000, $545,000 and $688,000 for the years 1998,
1997 and 1996, respectively. The decrease in 1998 is primarily attributable to
one-time pre-tax gains of $452,000 and $300,000 on the sale of fixed assets
included in 1997 and 1996, respectively. Also contributing to the 1998 decline
is a reduction in interest income from $288,000 for 1997 to $188,000 for 1998.
Environmental Matters
The Company continues to work with federal and state environmental agencies to
assess the environmental impact and explore corrective action at several
former gas manufacturing plant sites (see Note L to the Consolidated Financial
Statements). The Company believes that future costs associated with these
sites will be recoverable in rates.
Market Risk
Market risk represents the potential loss arising from adverse changes in
market rates and prices. The Company's long-term debt consists of first
mortgage bonds, senior notes and convertible debentures (see Note G to the
Consolidated Financial Statements for annual maturities of consolidated long-
term debt). All of Chesapeake's long-term debt is fixed rate debt and was not
entered into for trading purposes. The carrying value of the Company's long-
term debt was $38.1 million at December 31, 1998. The fair value was $41.6
million at December 31, 1998, based mainly on current market prices or
discounted cash flows using current rates for similar issues with similar
terms and remaining maturities. The Company is exposed to changes in interest
rates as a result of financing through its issuance of fixed rate long-term
debt. The Company evaluates whether to refinance existing debt or permanently
finance existing short-term borrowing based on the fluctuation in interest
rates.
At December 31, 1998, the wholesale propane marketing operation was a party to
natural gas liquids ("NGL") forward contracts, primarily propane contracts,
with various third parties. These contracts require that the wholesale propane
marketing operation purchase or sell NGL at a fixed price at fixed future
dates. At expiration, the contracts are settled by the delivery of NGL to the
respective party. The wholesale propane marketing operation also enters into
futures contracts that are traded on the New York Mercantile Exchange. In
certain cases, the futures contracts are settled by the payment of a net
amount equal to the difference between the current market price of the futures
contract and the original contract price.
The forward and futures contracts are entered into for trading and wholesale
marketing purposes. The wholesale propane marketing operation is subject to
commodity price risk on their open positions to the extent that NGL market
prices deviate from fixed contract settlement amounts. Market risks associated
with the trading of futures and forward contracts are monitored daily for
compliance with Chesapeake's Risk Management Policy, which includes volumetric
limits for open positions. In order to manage exposures to changing market
prices, open positions are marked to market and reviewed by oversight
officials on a daily basis. Additionally, the Risk Management Committee
reviews periodic reports on market and credit risk, approves any exceptions to
the Risk Management policy (within the limits established by the Board of
Directors) and authorizes the use of any new types of contracts. Listed below
is quantitative information on the forward and futures contracts at December
31, 1998. All of the contracts mature during 1999.
- ----------------------------------------------------------------------
Quantity Estimated Weighted Average
At December 31, 1998 in gallons Market Prices Contract Prices
- ----------------------------------------------------------------------
Forward Contracts
Sale 20,647,200 $.2125 - $.2550 $0.2569
Purchase 24,263,400 $.2125 - $.2550 $0.2424
Futures Contracts
Sale 4,200,000 $.2125 - $.2550 $0.2194
Purchase 714,000 $.2125 - $.2550 $0.2110
- ----------------------------------------------------------------------
Estimated market prices and weighted average contract prices are in dollars
per gallon.
The Year 2000
Chesapeake is dependent upon a variety of information systems to operate
efficiently and effectively. In order to address the impact of the Year 2000
("Year 2000" or "Y2K") on its information systems, Chesapeake is in the
process of evaluating and remediating any deficiencies. The Company's
evaluation of its readiness and the potential impact of the Year 2000 on its
systems have been separated into five components: primary internal
applications, embedded systems, vendors/suppliers, end-user computing systems
and customers.
- - Chesapeake's primary internal applications include company maintained
software systems for its financial information; natural gas customer
information and billing; and propane customer information, billing
and delivery. The Company completed testing of these three
applications in 1998 and deems them Year 2000 ready.
- - Embedded systems include the supervisory control and data acquisition
("SCADA") system for the natural gas transmission segment,
telecommunications, metering and other facilities related systems.
Chesapeake has currently identified 64 vendors that support the
Company's embedded systems. Chesapeake expects to finalize the review
for additional vendors and/or embedded systems by the end of the
first quarter of 1999. The Company has prioritized these vendors into
three potential impact classifications: 15 high impact vendors,
supporting items such as the SCADA system; 19 medium impact vendors,
supporting systems such as telecommunications; and 30 low impact
vendors, supporting items such as copiers and postage meters. The
Company has been testing these systems and has contacted all of the
vendors currently identified, with 85% responding. Of the vendors
contacted, a total of 20 vendors - four high impact, six medium
impact and ten low impact vendors - indicated they were Y2K ready.
The Company has been either working with vendors to reach a state of
readiness with the applicable systems or has changed to vendors or
systems that are Y2K ready. The SCADA system, the most critical
embedded system, is scheduled to be Y2K ready during the second
quarter of 1999. Chesapeake will continue to follow up with vendors
that are not Y2K ready and will consider alternate providers as
necessary to the extent available.
- - Chesapeake has identified 101 vendors/suppliers that supply the
Company with products and services that impact various elements of
the Company's business. The Company has classified these vendors into
three impact classifications: 27 high impact vendors such as
suppliers of natural gas or propane; 31 medium impact vendors such as
regional communication vendors; and 43 low impact vendors. The
Company has requested a Y2K status statement from each of these
vendors. The Company has received 72 responses, which indicated that
nine medium impact and 13 low impact vendors were Y2K ready. The
Company will continue to follow up with vendors that are not Y2K
ready and will consider alternate providers as necessary to the
extent available.
- - End-user computing systems are upgraded periodically through the
Company's ongoing replacement program. Almost all of the Company's
personal computers are currently Year 2000 ready. Additional personal
computers will be replaced during the first quarter of 1999.
Chesapeake's local area network is Year 2000 ready as is all PC-based
and network-based software.
- - Customers, primarily industrial interruptible natural gas customers,
must ensure that their plant controls are Year 2000 ready for their
alternative fuel. The Company has identified 107 interruptible
customers and will contact each of them by the end of the first
quarter of 1999. The Company will take into account the results of
the survey in developing the natural gas contingency plan.
The Company believes the most significant potential risks with respect to its
internal operations, those over which it has direct control, are its ability
to: (1) use electronic devices to control and operate its natural gas delivery
systems; (2) maintain continuous operation of its computer systems; (3) render
timely bills to its customers; and (4) enforce tariffs and contracts
applicable to interruptible customers.
The Company relies on the producers of natural gas and suppliers of interstate
transportation capacity to deliver natural gas to the Company's natural gas
delivery systems. The Company is also dependent on propane producers,
suppliers and railroad facilities to receive propane supply. Chesapeake is
also dependent on various suppliers of communication services. Should any of
these critical vendors fail, the impact of any such failure could become a
significant challenge to the Company's ability to meet the demands of its
customers, to operate its delivery systems and to communicate with its
customers. It could also have a material adverse financial impact, including
but not limited to, lost sales revenues, increased operating costs and claims
from customers related to business interruptions. The Company's Year 2000
evaluation process is addressing each of these risks and the required
remediation. The Company is developing its contingency plan for the Year 2000,
which will address various alternatives and will include assessing a variety
of scenarios that could emerge and require the Company to react. Chesapeake
expects to have its contingency plan finalized by the end of the second
quarter of 1999. The contingency plan will continue to be modified as
warranted by changing events.
The costs incurred as of December 31, 1998 in addressing Year 2000 issues have
been immaterial. The Company has estimated costs of $270,000 to replace and/or
remediate specific embedded systems. However, until the Company has completed
further analysis of the impact of the Year 2000 issue on its embedded systems,
vendors/suppliers, end-user computing systems, customers and contingency
planning; it is unable to estimate any additional costs it may incur as a
result of its efforts.
Presently, no Year 2000-impacted internal applications or embedded systems
have been identified that cannot be upgraded or modified within acceptable
time frames. The target date for completion of all Year 2000-related
activities remains at mid-1999.
Competition
Historically, the Company's natural gas operations have successfully competed
with other forms of energy such as electricity, oil and propane. The principal
considerations have been price, and to a lesser extent, accessibility. As a
result of Eastern Shore's recent conversion to open access, the Company
expects to be subject to competitive pressures from other sellers of natural
gas. With open access transportation services available on Eastern Shore's
system, third party suppliers will compete with Chesapeake to sell gas to the
local distribution companies and the end-users on Eastern Shore's system.
Eastern Shore has shifted from providing sales service to providing
transportation and contract storage services.
The Company's natural gas distribution operation located in Maryland began to
offer transportation services to certain industrial customers during 1998.
During 1997, the distribution operation located in Delaware also began
offering transportation services. The Company expects to expand the
availability of transportation services to additional customers in the future.
The Florida distribution operation has been open to certain industrial
customers since 1994. The Company established a natural gas brokering and
supply operation in Florida to compete for these customers.
Both the propane and advanced information services businesses face significant
competition from a number of larger competitors with substantially greater
resources available to them than those of the Company. In addition, in the
advanced information services business, changes are occurring rapidly which
could adversely affect the markets for the Company's services.
Inflation
Inflation affects the cost of labor and other goods and services required for
operation, maintenance and capital improvements. While the impact of inflation
has lessened in recent years, natural gas prices are subject to rapid
fluctuations. These fluctuations are passed on to customers through the gas
cost recovery mechanism in the Company's tariffs. To help cope with the
effects of inflation on its capital investments and returns, the Company seeks
rate relief from regulatory commissions for regulated operations while
monitoring the returns of its unregulated business operations.
Cautionary Statement
We make statements in this report that are considered forward-looking
statements within the meaning of the Private Securities Litigation Reform Act
of 1995. 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. These statements relate to such topics as
customer growth, increases in revenues or margins, Year 2000 readiness,
regulatory approvals, market risk associated with the Company's new propane
marketing operation, the competitive position of the Company and other
matters. It is important to understand that these forward-looking statements
are not guarantees, but are subject to certain risks and uncertainties and
other important factors that could cause actual results to differ materially
from those in the forward-looking statements. These factors include, among
other things:
- - the seasonality and temperature sensitivity of Chesapeake's natural
gas and propane businesses (that is, the Company's earnings vary
depending on the season and, in the winter months, how cold the
weather is);
- - consumption patterns of the Company's existing and expected customers
in these businesses;
- - the wholesale price of propane and market movements in these prices,
which affect both the margins in the Company's propane business and
the profitability of the propane marketing operation;
- - the relative price of alternative energy sources, to which some of
Chesapeake's customers have access;
- - the effects of competition on both unregulated and regulated
businesses;
- - the ability of the transmission segment to attract new customers in
an open access environment;
- - the ability of the Company's new and planned facilities to generate
expected revenues;
- - the Company's ability to obtain the rate relief requested from
utility regulators and the timing of that rate relief; and
- - the Company's ability to identify and address Year 2000 issues
successfully, in a timely manner and at a reasonable cost, as well as
the ability of the Company's vendors, suppliers, and other service
providers and customers to successfully address their own Year 2000
issues in a timely manner.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.
Information related to quantitative and qualitative disclosure about market
risk is included in Item 7 under the heading "Management's Discussion and
Analysis - Market Risk".
Item 8. Financial Statements and Supplemental Data
REPORT OF INDEPENDENT ACCOUNTANTS
________
To the Stockholders of Chesapeake Utilities Corporation
In our opinion, the consolidated financial statements listed in the index
appearing under item 14(a)(1) of this Form 10-K present fairly, in all
material respects, the financial position of Chesapeake Utilities Corporation
and its subsidiaries at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles.
In addition, in our opinion, the consolidated financial statement schedule
listed in the index appearing under item 14(a)(2) of this Form 10-K presents
fairly, in all material respects, the information set forth therein when read
in conjunction with the related consolidated financial statements. These
financial statements and financial statement schedule are the responsibility
of the Company's management; our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our
audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Washington, D.C.
February 12, 1999
CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 183,568,795 $ 222,489,264 $ 260,102,200
Cost of Sales 136,019,813 175,191,090 207,655,979
Gross Margin 47,548,982 47,298,174 52,446,221
- --------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations 23,669,514 23,686,774 26,485,013
Maintenance 2,123,456 2,068,114 2,550,197
Depreciation and amortization 6,109,202 5,475,417 5,605,930
Other taxes 4,024,129 3,974,097 3,822,200
Income taxes 3,181,599 3,427,308 3,884,377
- --------------------------------------------------------------------------------------------------------------------
Total operating expenses 39,107,900 38,631,710 42,347,717
- --------------------------------------------------------------------------------------------------------------------
Operating Income 8,441,082 8,666,464 10,098,504
- --------------------------------------------------------------------------------------------------------------------
Other Income
Interest income 188,394 288,339 248,632
Other income, net 97,005 533,704 642,238
Income taxes (44,145) (276,888) (202,239)
- --------------------------------------------------------------------------------------------------------------------
Total other income 241,254 545,155 688,631
- --------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 8,682,336 9,211,619 10,787,135
- --------------------------------------------------------------------------------------------------------------------
Interest Charges
Interest on long-term debt 2,966,043 2,387,641 2,434,321
Amortization of debt expense 123,335 119,401 120,345
Other 290,372 836,965 450,536
- --------------------------------------------------------------------------------------------------------------------
Total interest charges 3,379,750 3,344,007 3,005,202
- --------------------------------------------------------------------------------------------------------------------
Net Income $ 5,302,586 $ 5,867,612 $ 7,781,933
===================================================================================================================
Earnings Per Share of Common Stock :
Basic $ 1.05 $ 1.18 $ 1.58
Diluted $ 1.04 $ 1.17 $ 1.55
Consolidated Statements of Comprehensive Income
- --------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Net Income $ 5,302,586 $ 5,867,612 $ 7,781,933
Unrealized gain on marketable securities,
net of income taxes 566,472 258,274 111,437
- --------------------------------------------------------------------------------------------------------------------
Total Comprehensive Income $ 5,869,058 $ 6,125,886 $ 7,893,370
===================================================================================================================
See accompanying notes
CONSOLIDATED BALANCE SHEETS
Assets
- ---------------------------------------------------------------------------------------------------
At December 31, 1998 1997
- ---------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Natural gas distribution $ 81,844,066 $ 75,564,462
Natural gas transmission 35,388,440 33,856,873
Propane distribution and marketing 27,287,807 27,091,102
Advanced information services 1,087,910 841,757
Other plant 7,382,965 6,896,899
- ---------------------------------------------------------------------------------------------------
Total property, plant and equipment 152,991,188 144,251,093
Less: Accumulated depreciation and amortization (48,725,412) (44,371,890)
- ---------------------------------------------------------------------------------------------------
Net property, plant and equipment 104,265,776 99,879,203
- ---------------------------------------------------------------------------------------------------
Investments, at fair market value 4,165,194 2,721,443
- ---------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 2,598,084 4,829,176
Accounts receivable (less allowance for uncollectibles
of $302,513 and $331,775 in 1998 and 1997, respectively) 14,861,255 16,415,922
Materials and supplies, at average cost 1,728,513 1,424,312
Propane inventory, at average cost 1,787,038 2,436,200
Storage gas prepayments 2,152,605 2,926,618
Underrecovered purchased gas costs 1,552,265 1,673,389
Income taxes receivable 344,311 766,178
Deferred income taxes - 247,487
Prepaid expenses 1,596,595 1,107,825
- ---------------------------------------------------------------------------------------------------
Total current assets 26,620,666 31,827,107
- ---------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets
Environmental regulatory assets 2,700,000 4,865,073
Environmental expenditures 3,418,166 2,372,929
Other deferred charges and intangible assets 4,063,811 4,053,068
- ---------------------------------------------------------------------------------------------------
Total deferred charges and other assets 10,181,977 11,291,070
- ---------------------------------------------------------------------------------------------------
Total Assets $145,233,613 $145,718,823
==================================================================================================
See accompanying notes
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities
- ---------------------------------------------------------------------------------------------------
At December 31, 1998 1997
- ---------------------------------------------------------------------------------------------------
Capitalization
Stockholders' equity
Common stock $ 2,479,019 $ 2,435,142
Additional paid-in capital 24,192,188 22,581,463
Retained earnings 28,892,384 28,533,145
Less: Unearned compensation related to restricted stock awarded (71,041) (190,886)
Accumulated other comprehensive income 863,344 296,872
- ---------------------------------------------------------------------------------------------------
Total stockholders' equity 56,355,894 53,655,736
Long-term debt, net of current portion 37,597,000 38,226,000
- ---------------------------------------------------------------------------------------------------
Total capitalization 93,952,894 91,881,736
- ---------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 520,000 1,051,241
Short-term borrowings 11,600,000 7,600,010
Accounts payable 11,070,642 16,397,691
Refunds payable to customers 636,153 357,041
Accrued interest 553,444 784,533
Dividends payable 1,273,446 1,092,168
Deferred income taxes 56,100 -
Other accrued liabilities 3,754,231 3,829,497
- ---------------------------------------------------------------------------------------------------
Total current liabilities 29,464,016 31,112,181
- ---------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 13,260,282 11,490,358
Deferred investment tax credits 766,802 821,617
Environmental liability 2,700,000 4,865,073
Accrued pension costs 1,536,304 2,338,201
Other liabilities 3,553,315 3,209,657
- ---------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 21,816,703 22,724,906
- ---------------------------------------------------------------------------------------------------
Commitments and Contingencies
(Notes L and M)
Total Capitalization and Liabilities $145,233,613 $145,718,823
==================================================================================================
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income $ 5,302,586 $ 5,867,612 $ 7,781,933
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization 6,864,063 6,168,777 6,248,618
Investment tax credit adjustments (54,815) (54,815) (54,815)
Deferred income taxes, net 1,711,510 1,437,206 1,794,146
Mark-to-market adjustments (242,757) 1,144,966 (1,109,416)
Employee benefits (801,898) (238,826) 471,870
Employee compensation from lapsing of stock restrictions 119,845 173,643 334,745
Other, net (171,616) (286,147) (32,133)
Changes in assets and liabilities:
Accounts receivable, net 1,797,425 10,914,969 (8,597,772)
Other current assets 630,202 1,368,006 (2,766,414)
Other deferred charges 215,119 (623,138) (977,257)
Accounts payable, net (5,327,052) (12,525,992) 12,048,169
Refunds payable to customers 279,112 3,307 (613,206)
Overrecovered (underrecovered) purchased gas costs 121,123 518,781 (2,245,544)
Other current liabilities 584,558 (2,193,548) 1,739,020
- -----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 11,027,405 11,674,801 14,021,944
- -----------------------------------------------------------------------------------------------------------------------
Investing Activities
Property, plant and equipment expenditures, net (12,021,735) (12,370,932) (14,025,373)
Purchases of investments (500,000) (36,167) (129,406)
- -----------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (12,521,735) (12,407,099) (14,154,779)
- -----------------------------------------------------------------------------------------------------------------------
Financing Activities
Common stock dividends, net of amounts reinvested of $463,231,
$382,932 and $346,308 in 1998, 1997 and 1996, respectively (4,298,837) (3,846,264) (3,368,545)
Issuance of stock - Dividend Reinvestment Plan optional cash 146,716 167,337 208,813
Issuance of stock - Retirement Savings Plan 466,759 404,297 349,031
Net borrowings (repayments) under line of credit agreements 3,999,990 (5,134,990) 7,334,990
Proceeds from issuance of long-term debt - 9,929,711 -
Repayment of long-term debt (1,051,390) (3,098,455) (881,467)
- -----------------------------------------------------------------------------------------------------------------------
Net cash (used) provided by financing activities (736,762) (1,578,364) 3,642,822
- -----------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (2,231,092) (2,310,662) 3,509,987
Cash and Cash Equivalents at Beginning of Year 4,829,176 7,139,838 3,629,851
- -----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 2,598,084 $ 4,829,176 $ 7,139,838
======================================================================================================================
Supplemental Disclosure of Cash Flow Information
Cash paid for interest $ 3,490,993 $ 3,243,981 $ 2,872,973
Cash paid for income tax $ 2,670,580 $ 3,500,160 $ 2,059,441
See accompanying notes
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- -----------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------
Common Stock
Balance - beginning of year $ 2,435,142 $ 2,403,978 $ 2,365,562
Dividend Reinvestment Plan 16,240 15,398 16,514
Retirement Savings Plan 12,663 11,305 9,928
Conversion of debentures 3,115 4,461 429
USI restricted stock award agreements - - 10,639
Performance shares 11,859 - -
Exercised stock options - - 906
- -----------------------------------------------------------------------------------------------------------
Balance - end of year 2,479,019 2,435,142 2,403,978
- -----------------------------------------------------------------------------------------------------------
Additional Paid-in Capital
Balance - beginning of year 22,581,463 21,507,577 20,250,967
Dividend Reinvestment Plan 593,706 529,453 538,607
Retirement Savings Plan 454,096 392,992 328,465
Conversion of debentures 105,736 151,441 14,557
USI restricted stock award agreements - - 344,570
Performance shares 457,187 - -
Exercised stock options - - 30,411
- -----------------------------------------------------------------------------------------------------------
Balance - end of year 24,192,188 22,581,463 21,507,577
- -----------------------------------------------------------------------------------------------------------
Retained Earnings
Balance - beginning of year 28,533,145 27,113,764 23,458,776
Net income 5,302,586 5,867,612 7,781,933
Cash dividends - Chesapeake (4,943,347) (4,341,964) (3,514,694)
Cash dividends - Pooled companies - (106,267) (612,251)
- -----------------------------------------------------------------------------------------------------------
Balance - end of year 28,892,384 28,533,145 27,113,764
- -----------------------------------------------------------------------------------------------------------
Unearned Compensation
Balance - beginning of year (190,886) (364,529) (415,107)
Issuance of award - - (284,167)
Amortization of prior years' awards 119,845 173,643 334,745
- -----------------------------------------------------------------------------------------------------------
Balance - end of year (71,041) (190,886) (364,529)
- -----------------------------------------------------------------------------------------------------------
Accumulated Other Comprehensive Income
Net of income tax expense of approximately
$552,000, $190,000 and $25,000 for the years
1998, 1997 and 1996, respectively 863,344 296,872 38,598
- -----------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $56,355,894 $53,655,736 $50,699,388
==========================================================================================================
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME TAXES
- -------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
Current Income Tax Expense
Federal $ 1,553,839 $ 2,076,235 $1,940,430
State 307,654 442,563 356,576
Investment tax credit adjustments, net (54,815) (54,815) (54,815)
- --------------------------------------------------------------------------------------------------------------------
Total current income tax expense 1,806,678 2,463,983 2,242,191
- --------------------------------------------------------------------------------------------------------------------
Deferred Income Tax Expense
Property, plant and equipment 887,175 1,335,802 581,373
Deferred gas costs (111,416) (204,170) 873,904
Pensions and other employee benefits 546,237 (19,508) 107,131
Unbilled revenue (16,198) (104,632) 54,320
Contributions in aid of construction (104,003) (33,028) (6,979)
Environmental expenditures 415,845 249,417 108,578
Other (198,574) 16,332 126,098
- --------------------------------------------------------------------------------------------------------------------
Total deferred income tax expense (1) 1,419,066 1,240,213 1,844,425
- --------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 3,225,744 $ 3,704,196 $4,086,616
===================================================================================================================
Reconciliation of Effective Income Tax Rates
Federal income tax expense at 34% $ 2,899,632 $ 3,254,412 $4,035,307
State income taxes, net of Federal benefit 363,041 399,213 537,566
Acquisition of subchapter S Corporation (2) - 317,821 (268,211)
Other (36,929) (267,250) (218,046)
- --------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 3,225,744 $ 3,704,196 $4,086,616
====================================================================================================================
Effective income tax rate 37.8% 38.7% 34.4%
- ----------------------------------------------------------------------------------------------------
At December 31, 1998 1997
- ----------------------------------------------------------------------------------------------------
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment $13,222,141 $12,095,782
Deferred gas costs 546,391 649,681
Environmental costs 1,358,443 855,997
Other 1,077,008 704,991
- ----------------------------------------------------------------------------------------------------
Total deferred income tax liabilities 16,203,983 14,306,451
- ----------------------------------------------------------------------------------------------------
Deferred income tax assets:
State operating loss carryforwards 72,041 57,303
Unbilled revenue 984,510 968,311
Pension and other employee benefits 884,286 831,735
Self insurance 625,602 585,995
Other 321,162 620,236
- ----------------------------------------------------------------------------------------------------
Total deferred income tax assets 2,887,601 3,063,580
- ----------------------------------------------------------------------------------------------------
Deferred Income Taxes
Per Consolidated Balance Sheet $13,316,382 $11,242,871
===================================================================================================
(1) Includes $156,000, $208,000 and $392,000 of deferred state income taxes
for the years 1998, 1997 and 1996, respectively.
(2) Accounted for as a pooling of interests (see Note B to the Consolidated
Financial Statements).
See accompanying notes
A. Summary of Accounting Policies
Nature of Business
Chesapeake Utilities Corporation (the "Company") is engaged in natural gas
distribution to approximately 37,100 customers located in southern Delaware,
Maryland's Eastern Shore and Central Florida. The Company's natural gas
transmission subsidiary operates a pipeline from various points in
Pennsylvania and northern Delaware to the Company's Delaware and Maryland
distribution divisions, as well as other utility and industrial customers in
Delaware and the Eastern Shore of Maryland. The Company's propane distribution
and marketing segment provides distribution service to approximately 35,000
customers in southern Delaware, the Eastern Shore of Maryland and Virginia,
and markets propane to a number of large independent oil and petrochemical
companies, resellers, and propane distribution companies in the southeastern
United States. The advanced information services segment provides consulting,
custom programming, training and development tools for national and
international clients.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and
its wholly owned subsidiaries. Investments in entities in which the Company
owns more than 20 percent but 50 percent or less, are accounted for by the
equity method. All significant intercompany transactions have been eliminated
in consolidation.
System of Accounts
The natural gas distribution divisions of the Company located in Delaware,
Maryland and Florida are subject to regulation by the Delaware, Maryland and
Florida Public Service Commissions with respect to their rates for service,
maintenance of their accounting records and various other matters. Eastern
Shore Natural Gas Company ("Eastern Shore") is an open access pipeline and is
subject to regulation by the Federal Energy Regulatory Commission ("FERC").
The Company's financial statements are prepared on the basis of generally
accepted accounting principles which give appropriate recognition to the
ratemaking and accounting practices and policies of the various commissions.
The propane distribution and marketing and advanced information services
segments are not subject to regulation with respect to rates or maintenance of
accounting records.
Cash and Cash Equivalents
The Company's policy is to invest cash in excess of operating requirements in
overnight income producing accounts. Such amounts are stated at cost, which
approximates market value. Investments with an original maturity of three
months or less are considered cash equivalents.
Property, Plant, Equipment and Depreciation
Utility property is stated at original cost while the assets of the propane
segment are valued at cost. The costs of repairs and minor replacements are
charged to income as incurred and the costs of major renewals and betterments
are capitalized. Upon retirement or disposition of utility property, the
recorded cost of removal, net of salvage value, is charged to accumulated
depreciation. Upon retirement or disposition of non-utility property, the gain
or loss, net of salvage value, is charged to income. The provision for
depreciation is computed using the straight-line method at rates which will
amortize the unrecovered cost of depreciable property over the estimated
useful life. Depreciation and amortization expense for financial statement
purposes is provided at an annual rate for each segment. Average rates for
1998 were 5% and 3% for the natural gas distribution and transmission
segments, respectively, 5% for propane distribution and marketing, 16% for
advanced information services and 6% for general plant.
Environmental Regulatory Assets
Environmental regulatory assets represent amounts related to environmental
liabilities for which cash expenditures have not been made. As expenditures
are incurred, the environmental liability is reduced along with the
environmental regulatory asset. These amounts, awaiting ratemaking treatment,
are recorded to either environmental expenditures as an asset or accumulated
depreciation as cost of removal. Environmental expenditures are amortized
and/or recovered through a rider to base rates in accordance with the
ratemaking treatment granted in each jurisdiction.
Other Deferred Charges and Intangible Assets
Other deferred charges include discount, premium and issuance costs associated
with long-term debt and rate case expenses. The discount, premium and issuance
costs are deferred, then amortized over the original lives of the respective
debt issues. Gains and losses on the reacquisition of debt are amortized over
the remaining lives of the original issuances. Rate case expenses are
deferred, then amortized over periods approved by the applicable regulatory
authorities. Intangible assets are associated with the acquisition of non-
utility companies, and are amortized on a straight-line basis over a period of
five to 40 years. A summary of intangible assets is as follows:
- -------------------------------------------------
At December 31, 1998 1997
- -------------------------------------------------
Gross intangibles $2,776,000 $2,776,000
Accumulated amortization (1,288,000) (1,133,000)
- -------------------------------------------------
Net unamortized balance $1,488,000 $1,643,000
=================================================
Income Taxes and Investment Tax Credit Adjustments
The Company files a consolidated federal income tax return. Income tax expense
allocated to the Company's subsidiaries is based upon their respective taxable
incomes and tax credits.
Deferred tax assets and liabilities are recorded for the tax effect of
temporary differences between the financial statements and tax bases of assets
and liabilities, and are measured using current effective income tax rates.
The portion of the Company's deferred tax liabilities applicable to utility
operations which has not been reflected in current service rates represents
income taxes recoverable through future rates. Investment tax credits on
utility property have been deferred and are allocated to income ratably over
the lives of the subject property.
The Company had state tax loss carryforwards of $980,000 and $818,000 at
December 31, 1998 and 1997, respectively. The Company expects to use all of
the loss carryforwards; therefore, no valuation allowance was recorded at
December 31, 1998 or 1997. The loss carryforwards expire in 2006 through 2013.
Financial Instruments
Xeron, the Company's wholesale propane marketing operation, engages in trading
activities using forward and futures contracts which have been accounted for
using the mark-to-market method of accounting. Under mark-to-market
accounting, the Company's trading contracts are recorded at fair value, net of
future servicing costs. Changes in market price are recognized as gains or
losses in the period of change. The resulting unrealized gains and losses are
recorded as assets or liabilities.
Operating Revenues
Revenues for the natural gas distribution divisions of the Company are based
on rates approved by the various public service commissions. Customers' base
rates may not be changed without formal approval by these commissions. With
the exception of the Company's Florida division, the Company recognizes
revenues from meters read on a monthly cycle basis. This practice results in
unbilled and unrecorded revenue from the cycle date through month-end. The
Florida division recognizes revenues based on services rendered and records an
amount for gas delivered but not billed.
Chesapeake's natural gas distribution divisions each have a gas cost recovery
mechanism that provides for the adjustment of rates charged to customers as
gas costs fluctuate. These amounts are collected or refunded through
adjustments to rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution segment's
industrial interruptible customers to make them competitive with alternative
types of fuel. Based on pricing, these customers can choose natural gas or
alternative types of supply. Neither the Company nor the customer is
contractually obligated to deliver or receive natural gas.
The natural gas transmission segment became an open access pipeline on
November 1, 1997 with revenues based on rates approved by FERC. Before open
access, only portions of revenues were based on rates approved by FERC.
The propane distribution operation records revenues on either an "as
delivered" or on a "metered" basis depending on the customer type. The
wholesale propane marketing operation calculates revenues daily on a mark-to-
market basis for open contracts.
Earnings Per Share
The calculations of both basic and diluted earnings per share are presented
below.
- --------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------
Calculation of Basic Earnings Per Share:
Net Income $5,302,586 $5,867,612 $7,781,933
Weighted Average Shares Outstanding 5,060,328 4,972,089 4,912,136
- --------------------------------------------------------------------------------
Basic Earnings Per Share $ 1.05 $ 1.18 $ 1.58
================================================================================
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income - basic $5,302,586 $5,867,612 $7,781,933
Effect of 8.25% Convertible debentures 196,333 204,070 207,825
- --------------------------------------------------------------------------------
Adjusted numerator - diluted $5,498,919 $6,071,682 $7,989,758
- --------------------------------------------------------------------------------
Reconcilation of Denominator:
Weighted Shares Outstanding - basic 5,060,328 4,972,089 4,912,136
Effect of 8.25% Convertible debentures 226,203 238,353 242,742
- --------------------------------------------------------------------------------
Adjusted denominator - diluted 5,286,531 5,210,442 5,154,878
- --------------------------------------------------------------------------------
Diluted Earnings per Share $ 1.04 $ 1.17 $ 1.55
================================================================================
Certain Risks and Uncertainties
The financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates in measuring
assets and liabilities and related revenue and expenses (see Note L to the
Consolidated Financial Statements for significant estimates). These estimates
involve judgements with respect to, among other things, various future
economic factors that are difficult to predict and are beyond the control of
the Company; therefore, actual results could differ from those estimates.
The Company records certain assets and liabilities in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 71. If the Company
were required to terminate application of SFAS No. 71 for regulated
operations, all such deferred amounts would be recognized in the income
statement at that time, resulting in a charge to earnings, net of applicable
income taxes.
FASB Statements and Other Authoritative Pronouncements Issued
Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, establishing accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. This statement does not allow
retroactive application to financial statements for prior periods.
Chesapeake will adopt the requirements of this standard in the first
quarter of 2000, as required. The Company believes that adoption of this
statement will not have a material impact on the Company's financial
position or results of operations.
The Emerging Issues Task Force released Issue 98-10, "Accounting for Energy
Trading and Risk Management Activities." The Company records its use of
derivatives in accordance with the standard by marking open positions to
market value. The adoption of the pronouncement is not expected to have a
material impact on the financial position or results of operations of the
Company.
Restatement and Reclassification of Prior Years' Amounts
Certain prior years' amounts have been reclassified to conform to current year
presentation. Additionally, prior year amounts have been restated to reflect
acquisitions accounted for as poolings of interests.
B. Business Combinations
In May 1998, Chesapeake acquired all of the outstanding common stock of Xeron,
Inc, based in Houston, Texas for 475,000 shares of Chesapeake common stock.
Xeron markets propane to a number of large independent oil and petrochemical
companies, resellers, and southeastern retail propane companies. The
transaction was accounted for as a pooling of interests.
In March 1998, the Company acquired Sam Shannahan Well Co., Inc., operating as
Tolan Water Service in exchange for 25,000 shares of Chesapeake's common
stock. Tolan provides water conditioning services to approximately 3,000
residential, commercial and industrial customers on the Delmarva Peninsula.
This transaction was also accounted for as a pooling of interests.
The results of operations for the separate companies and the combined amounts
are presented in the consolidated financial statements as follows.
- ------------------------------------------------------------------------------
Five months ended Year Ended Year Ended
May 31, 1998 * December 31, 1997 December 31, 1996
- ------------------------------------------------------------------------------
Operating Revenues
Chesapeake $ 54,750,771 $ 122,774,593 $ 130,213,409
Xeron 37,136,067 98,164,932 128,633,042
Tolan 719,523 1,549,739 1,255,749
- ------------------------------------------------------------------------------
Combined $ 92,606,361 $ 222,489,264 $ 260,102,200
==============================================================================
Net Income
Chesapeake $ 4,385,817 $ 5,682,946 $ 7,604,915
Xeron 21,704 128,910 158,991
Tolan 2,346 55,756 18,027
- ------------------------------------------------------------------------------
Combined $ 4,409,867 $ 5,867,612 $ 7,781,933
==============================================================================
* Statements for the five months ended May 31, 1998 are unaudited.
In March 1997, the Company acquired all of the outstanding common stock of
Tri-County Gas Company, Inc. and associated properties. Tri-County's principal
business was the distribution of propane to both retail and wholesale
customers in southern Delaware, the Eastern Shore of Maryland and Virginia.
Six hundred thirty-nine thousand shares of the Company's common stock were
exchanged in the transaction, which was accounted for as a pooling of
interests.
All prior period consolidated financial statements presented have been
restated to include the combined results of operations, financial position and
cash flows of each of the business combinations discussed above. All material
intercompany transactions have been eliminated in consolidation.
C. Segment Information
Chesapeake uses the management approach to identify operating segments.
Chesapeake organizes its business around differences in products or services
and the operating results of every segment are regularly reviewed by the
Company's chief operating decision maker in order to make decisions about
resources and to assess performance.
The following table presents information about the Company's
reportable segments.
- --------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------
Operating Revenues, Unaffiliated Customers
Natural gas distribution $ 65,384,413 $ 75,940,968 $ 74,904,100
Natural gas transmission 3,199,032 12,164,369 15,188,752
Propane distribution and marketing 102,872,909 125,159,336 161,812,156
Advanced information services 10,330,703 7,636,407 6,903,246
Other 1,781,738 1,588,184 1,293,946
- --------------------------------------------------------------------------------------------------------------
Total operating revenues, unaffiliated customers $183,568,795 $222,489,264 $260,102,200
==============================================================================================================
Intersegment Revenues *
Natural gas distribution $ 40,494 $ 18,970 $ 12,232
Natural gas transmission 7,269,620 19,282,359 21,543,352
Propane distribution and marketing - 52,230 2,059
Advanced information services - 149,602 326,913
Other 634,032 523,007 332,512
- --------------------------------------------------------------------------------------------------------------
Total intersegment revenues $ 7,944,146 $ 20,026,168 $ 22,217,068
===============================================================================================================
Operating Income Before Income Taxes
Natural gas distribution $ 4,696,759 $ 5,498,471 $ 7,167,237
Natural gas transmission 4,117,366 3,721,148 2,458,442
Propane distribution and marketing 971,215 1,157,543 2,668,839
Advanced information services 1,316,158 1,045,912 1,056,201
Other 461,174 637,971 478,571
- --------------------------------------------------------------------------------------------------------------
Total 11,562,672 12,061,045 13,829,290
Eliminations 60,009 32,727 153,591
- --------------------------------------------------------------------------------------------------------------
Total operating income before income taxes $ 11,622,681 $ 12,093,772 $ 13,982,881
==============================================================================================================
Depreciation and Amortization
Natural gas distribution $ 3,330,624 $ 3,076,654 $ 2,907,831
Natural gas transmission 1,050,714 892,258 697,834
Propane distribution and marketing 1,334,414 1,214,918 1,720,631
Advanced information services 183,553 122,081 131,877
Other 209,897 169,506 147,757
- --------------------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 6,109,202 $ 5,475,417 $ 5,605,930
==============================================================================================================
Capital Expenditures
Natural gas distribution $ 8,512,661 $ 6,569,865 $ 6,961,652
Natural gas transmission 1,505,830 2,959,019 5,567,509
Propane distribution and marketing 1,544,992 2,820,166 2,189,368
Advanced information services 246,153 273,351 162,189
Other 840,186 848,680 517,997
- --------------------------------------------------------------------------------------------------------------
Total capital expenditures $ 12,649,822 $ 13,471,081 $ 15,398,715
==============================================================================================================
Identifiable Assets, at December 31,
Natural gas distribution $ 77,756,422 $ 78,732,860 $ 77,426,232
Natural gas transmission 24,862,165 24,781,292 23,981,989
Propane distribution and marketing 27,526,019 31,831,616 44,073,080
Advanced information services 2,304,609 1,751,192 1,496,419
Other 12,784,398 8,621,863 8,808,724
- --------------------------------------------------------------------------------------------------------------
Total identifiable assets $145,233,613 $145,718,823 $155,786,444
==============================================================================================================
* All significant intersegment revenues have been eliminated from consolidated revenues.
D. Fair Value of Financial Instruments
Various items within the balance sheet are considered to be financial
instruments because they are cash or are to be settled in cash. The carrying
values of these items generally approximate their fair value (see Note E to
the Consolidated Financial Statements for disclosure of fair value of
investments). The fair value of the Company's open forward and futures
contracts at December 31, 1998 and December 31, 1997 based on market rates
were $207,000 and $36,000, respectively. The fair value of the Company's long-
term debt is estimated using a discounted cash flow methodology. The estimated
fair value of the Company's long-term debt at December 31, 1998, including
current maturities, is approximately $41.6 million as compared to a carrying
value of $38.1 million. At December 31, 1997, the estimated fair value was
approximately $40.7 million as compared to a carrying value of $38.8 million.
These estimates are based on published corporate borrowing rates for debt
instruments with similar terms and average maturities.
E. Investments
The investment balance at December 31, 1998 and 1997 consists primarily of a
7.3% ownership interest in the common stock of Florida Public Utilities
Company ("FPU"). The Company has classified its investment in FPU as an
"Available for Sale" security, which requires that all unrealized gains and
losses be excluded from earnings and be reported net of income tax as a
separate component of stockholders' equity. At December 31, 1998 and 1997, the
market value exceeded the aggregate cost basis of the Company's portfolio by
$1,552,000 and $487,000, respectively.
In August 1998, the Company entered into an agreement to sell its investment
in FPU for $16.50 per share to The Southern Company. The execution of the
agreement is contingent on the approval of the Securities and Exchange
Commission, which is expected to be obtained in 1999. Once regulatory approval
is received, the Company will recognize a $1,415,000 pre-tax gain or $863,000,
after taxes.
F. Common Stock and Additional Paid-in Capital
The following is a schedule of changes in the Company's shares of common
stock.
- ---------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996 (1)
- ---------------------------------------------------------------------------------------
Common Stock: Shares issued and outstanding (2)
Balance - beginning of year 5,004,078 4,939,515 4,860,588
Dividend Reinvestment Plan (3) 32,925 32,169 33,926
Sale of stock to Company's Retirement Savings Plan 26,018 23,228 20,398
Conversion of debentures 6,401 9,166 881
Performance shares 24,366 - -
USI restricted stock award agreements - - 21,859
Exercised stock options - - 1,863
- ---------------------------------------------------------------------------------------
Balance - end of year 5,093,788 5,004,078 4,939,515
=======================================================================================
(1) The 1996 beginning balance has been restated to include 639,000,
25,000 and 475,000 shares of Common Stock that were issued to effect
the business combinations with Tri-County Gas Company, Inc., Tolan
Water Service and Xeron, Inc., respectively.
(2) 12,000,000 shares are authorized at a par value of $.4867 per share.
(3) Includes dividends and reinvested optional cash payments.
G. Long-term Debt
The outstanding long-term debt, net of current maturities, is as follows:
- ---------------------------------------------------------------------------
At December 31, 1998 1997
- ---------------------------------------------------------------------------
First mortgage sinking fund bonds:
9.37% Series I, due December 15, 2004 $ 3,780,000 $ 4,300,000
8.25% Convertible debentures, due March 1, 2014 3,817,000 3,926,000
Uncollateralized senior notes:
7.97% note, due February 1, 2008 10,000,000 10,000,000
6.91% note, due October 1, 2010 10,000,000 10,000,000
6.85% note, due January 1, 2012 10,000,000 10,000,000
- ---------------------------------------------------------------------------
Total long-term debt $37,597,000 $38,226,000
===========================================================================
Annual maturities of consolidated long-term debt for the next five years are
as follows: $1,520,000 for 1999, $2,665,091 for the years 2000 through 2002
and $3,665,091 for 2003.
On December 15, 1997, the Company issued $10 million of 6.85% senior notes due
January 1, 2012. The Company used the proceeds to repay a portion of the
Company's short-term borrowing.
The convertible debentures may be converted, at the option of the holder, into
shares of the Company's common stock at a conversion price of $17.01 per
share. During 1998, $109,000 of debentures were converted. The debentures are
redeemable at the option of the holder, subject to an annual non-cumulative
maximum limitation of $200,000 in the aggregate. At the Company's option, the
debentures may be redeemed at the stated amounts.
Indentures to the long-term debt of the Company and its subsidiaries contain
various restrictions. The most stringent restrictions state that the Company
must maintain equity of at least 40% of total capitalization, the times
interest earned ratio must be at least 2.5 and the Company cannot, until the
retirement of its Series I bonds, pay any dividends after December 31, 1988
which exceed the sum of $2,135,188 plus consolidated net income recognized on
or after January 1, 1989. As of December 31, 1998, the amounts available for
future dividends permitted by the Series I covenant approximated $14.7
million.
A portion of the natural gas distribution plant assets owned by the Company
are subject to a lien under the mortgage pursuant to which the Company's first
mortgage sinking fund bonds are issued.
H. Short-term Borrowing
The Board of Directors has authorized the Company to borrow up to $20.0
million from various banks and trust companies. As of December 31, 1998, the
Company had three unsecured bank lines of credit totaling $28.0 million, none
of which required compensating balances. Under these lines of credit at
December 31, 1998 and 1997, the Company had short-term debt outstanding of
$11.6 million and $7.6 million, respectively, with a weighted average interest
rate of 5.56% and 5.63%, respectively.
I. Lease Obligations
The Company has entered several operating lease arrangements for office space
at various locations. Rent expense related to these leases was $309,000,
$343,000 and $359,000 for 1998, 1997 and 1996, respectively. Future minimum
payments under the Company's current lease agreements are $309,000, $297,000,
$261,000, $187,000 and $169,000 for the years of 1999 through 2003,
respectively; and $299,000 thereafter.
J. Employee Benefits Plans
Pension Plan
Through December 31, 1998, the Company sponsored a defined benefit pension
plan covering substantially all of its employees (see Enhanced Retirement
Savings Plan). Benefits under the plan are based on each participant's years
of service and highest average compensation. The Company's funding policy
provides that payments to the trustee shall be equal to the minimum funding
requirements of the Employee Retirement Income Security Act of 1974.
In December 1998, the Company restructured the employee benefits plans to be
competitive with employers in similar industries. Chesapeake offered current
participants of the defined benefit plan the option to remain in the current
plan or receive a one-time payout and enroll in an enhanced retirement savings
plan. Chesapeake closed the defined benefit plan to new participants,
effective December 31, 1998. Based on the election options selected by the
employees, the Company reduced their accrued pension liability to $1,283,088.
Based on the change in the accrued liability, the Company was able to record a
curtailment gain of $1,224,298 in 1998.
The following schedule sets forth the funded status of the pension plan at
December 31, 1998 and 1997:
- --------------------------------------------------------------------------
At December 31, 1998 1997
- --------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of year $11,534,355 $10,265,987
Service cost 838,177 680,192
Interest cost 803,727 732,188
Effect of curtailment (1,224,298) -
Change in discount rate 952,552 -
Actuarial (gain) loss (384,492) 146,559
Benefits paid (332,136) (290,571)
- --------------------------------------------------------------------------
Benefit obligation at end of year 12,187,885 11,534,355
- --------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year 13,592,699 10,720,514
Actual return on plan assets 1,324,606 2,427,768
Employer contribution - 734,988
Benefits paid (332,136) (290,571)
- --------------------------------------------------------------------------
Fair value of plan assets at end of year 14,585,169 13,592,699
- --------------------------------------------------------------------------
Funded Status 2,397,284 2,058,344
Unrecognized transition obligation (111,371) (126,475)
Unrecognized prior service cost (67,152) (71,851)
Unrecognized net gain (3,501,849) (4,038,679)
- --------------------------------------------------------------------------
Accrued pension cost $(1,283,088) $(2,178,661)
==========================================================================
Assumptions:
Discount rate 6.75% 7.25%
Rate of compensation increase 4.75% 4.75%
Expected return on plan assets 8.50% 8.50%
- --------------------------------------------------------------------------
Net periodic pension costs for the defined pension benefit plan for 1998, 1997
and 1996 include the following components:
- --------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------
Components of net periodic pension cost:
Service cost $ 838,177 $ 680,192 $ 656,985
Interest cost 803,727 732,188 658,238
Expected return on assets (1,149,754) (898,037) (784,924)
Amortization of:
Transition assets (15,104) (15,104) (15,104)
Prior service cost (4,699) (4,699) (4,699)
Actuarial gain (143,622) (88,900) (68,425)
- --------------------------------------------------------------------------------
Net periodic pension cost 328,725 405,640 442,071
Curtailment gain (1,224,298) - -
Amounts capitalized as construction costs (31,107) (33,942) (38,860)
- --------------------------------------------------------------------------------
Total pension cost accruals $ (926,680) $ 371,698 $ 403,211
================================================================================
Retirement Savings Plan
The Company sponsors a Retirement Savings Plan, a 401(k) plan, that provides
participants a mechanism for making contributions for retirement savings. Each
participant may make pre-tax contributions up to 15% of eligible base
compensation subject to IRS limitations. Based on each participant's years of
service, the Company makes a contribution matching 60% or 100% of each
participant's pre-tax contributions, not to exceed 6% of the participant's
eligible compensation for the plan year. The Company's contributions totaled
$495,000, $404,000 and $353,000 for the years ended December 31, 1998, 1997
and 1996, respectively. As of December 31, 1998, there are 30,356 shares
reserved to fund future contributions to the Retirement Savings Plan.
Enhanced Retirement Savings Plan
Effective January 1, 1999, the Company will offer an enhanced 401(k) plan to
all new employees, as well as existing employees that elected to no longer
participate in the defined benefit plan. The Company will make a matching
contribution of each employee's pre-tax contribution of up to 6% of the
eligible compensation for the year. The match will be between 100% and 200%
based on a combination of the employee's age and years of service. The first
100% of the funds will be matched with Chesapeake common stock. The remaining
match will be invested in the Company's 401(k) plan according to each
employee's election options.
Other Post-retirement Benefits
The Company sponsors a defined benefit post-retirement health care and life
insurance plan that covers substantially all natural gas and corporate
employees. The Company had deferred approximately $126,000, which represented
the difference between the Maryland division's SFAS No. 106 expense and its
actual pay-as-you-go cost. The amount is being amortized over five years
starting in 1995. The unamortized balance was $50,000 at December 31, 1998.
Net periodic post-retirement costs for 1998, 1997 and 1996 include the
following components:
- -----------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------
Components of net periodic post-retirement cost:
Service cost $ 3,361 $ 3,287 $ 2,820
Interest cost 59,321 60,221 54,651
Amortization of:
Transition obligation 27,859 27,859 27,859
Actuarial loss 6,071 1,554 -
- -----------------------------------------------------------------------
Net periodic post-retirement cost 96,612 92,921 85,330
Amounts capitalized as construction costs (22,459) (16,274) (16,672)
Amounts amortized (deferred) 25,254 25,254 25,254
- -----------------------------------------------------------------------
Total post-retirement cost accruals $99,407 $101,901 $93,912
=======================================================================
The following schedule sets forth the funded status of the post-retirement
health care and life insurance plan:
- ---------------------------------------------------------------
At December 31, 1998 1997
- ---------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of year $ 868,899 $ 791,871
Retirees 14,236 53,604
Fully-eligible active employees 674 7,978
Other active 3,251 15,446
- ---------------------------------------------------------------
Benefit obligation at end of year $ 887,060 $ 868,899
===============================================================
Funded Status $(887,060) $(868,899)
Unrecognized transition obligation 217,295 245,154
Unrecognized net loss 165,160 147,422
- ---------------------------------------------------------------
Accrued post-retirement cost $(504,605) $(476,323)
===============================================================
Assumptions:
Discount rate 6.75% 7.25%
- ---------------------------------------------------------------
The health care inflation rate for 1998 is assumed to be 9.0%. This rate is
projected to gradually decrease to an ultimate rate of 5% by the year 2007. A
one percentage point increase in the health care inflation rate from the
assumed rate would increase the accumulated post-retirement benefit obligation
by approximately $105,000 as of January 1, 1999, and would increase the
aggregate of the service cost and interest cost components of net periodic
post-retirement benefit cost for 1999 by approximately $8,000.
K. Executive Incentive Plans
The Performance Incentive Plan ("the Plan") adopted in 1992, provides for the
granting of stock options to certain officers of the Company over a 10-year
period. The Plan provides participants an option to purchase shares of the
Company's common stock, exercisable in cumulative installments of up to one-
third on each anniversary of the commencement of the award period. The Plan
also enables participants the right to earn performance shares upon the
Company's achievement of certain performance goals as set forth in the
specific agreements associated with particular options and/or performance
shares.
The Company has executed Stock Option Agreements for a three-year performance
period ending December 31, 2000 with certain executive officers. One-half of
these options become exercisable over time and the other half become
exercisable if certain performance targets are achieved. Chesapeake also
executed Performance Share Agreements for the same period with certain other
executive officers. Each year participants are eligible to earn a maximum
number of performance shares equal to one-third of the total number of
performance shares granted, based on the Company's achievement of certain
performance goals. The Company recorded $49,000 of compensation expense
associated with these performance shares in 1998.
In November 1994, the Company executed Tandem Stock Option and Performance
Share Agreements ("Agreements") with certain executive officers. During the
three-year period ended December 31, 1997, the performance goals set forth in
the Agreements were achieved. Following the approval of the Board of Directors
on February 27, 1998, the Company issued 44,081 performance shares. At that
time, 44,906 stock options expired. The Company recorded $416,000 and $227,000
to recognize the compensation expense associated with these performance shares
in 1997 and 1996, respectively.
Changes in outstanding options were as follows:
- ------------------------------------------------------------------------------------------------------------
1998 1997 1996
Number Option Number Option Number Option
of shares Price of shares Price of shares Price
- ------------------------------------------------------------------------------------------------------------
Balance - beginning of year 208,543 $12.625 - $20.50 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75
Options granted 95,492 $20.50
Options expired (44,906) $12.625
Options exercised (12,135) $12.75
- ------------------------------------------------------------------------------------------------------------
Balance - end of year 163,637 $12.75 - $20.50 208,543 $12.625 - $20.50 113,051 $12.625 - $12.75
============================================================================================================
Exercisable 68,145 $12.75 98,083 $12.625 - $12.75 83,114 $12.625 - $12.75
- ------------------------------------------------------------------------------------------------------------
In December 1997, the Company granted stock options to certain executive
officers of the Company. As required by SFAS No. 123, the pro forma
information as if fair value based accounting had been used to account for the
stock-based compensation costs is shown below.
- ---------------------------------------------------------
For the Years Ended December 31, 1998 1997
- ---------------------------------------------------------
Pro forma Net Income $5,262,468 $5,864,269
Pro forma Earnings Per Share:
Basic $ 1.04 $ 1.18
Diluted $ 1.03 $ 1.16
Assumptions:
Dividend yield 4.73% 4.73%
Expected volatility 15.53% 15.53%
Risk-free interest rate 5.89% 5.89%
Expected lives 4 years 4 years
- ---------------------------------------------------------
Certain key USI employees entered into restricted stock award agreements under
which shares of Chesapeake common stock were issued over a five-year period
beginning in 1992 as certain targets were met. Restrictions lapse over a five
to ten-year period from the award date. At December 31, 1998 and 1997,
respectively, 4,371 and 12,515 shares valued at $71,041 and $190,886 remain
restricted.
L. Environmental Commitments and Contingencies
The Company is currently participating in the investigation, assessment or
remediation of three former gas manufacturing plant sites located in different
jurisdictions, including the exploration of corrective action options to
remove environmental contaminants. The Company has accrued liabilities for two
of these sites, the Dover Gas Light and Salisbury Town Gas Light sites.
With respect to the Dover Gas Light site, the Company and General Public
Utilities Corporation, Inc. ("GPU") have been ordered by the Environmental
Protection Agency ("EPA") to fund or implement the EPA's Record of Decision
("ROD") on the appropriate remedial activities to be performed, which include
both soil and ground-water remedies.
During the fourth quarter of 1998, the Company started the soil remediation
process at that site at a cost of $450,000. Over the next twelve to eighteen
months, the Company will finalize the soil remediation and initiate the
ground-water remedial activities.
The Company's independent consultants have prepared preliminary estimates of
the costs of two potentially acceptable alternatives to complete the ground-
water remediation activities at the site. The costs to remediate the ground-
water range from a low of $390,000 in capital and $37,000 per year of
operating costs; to a high of $4.0 million in capital and $500,000 per year in
operating costs. In both cases, the operating costs are assumed to last for 30
years. A decision by the EPA as to the most appropriate ground-water
remediation method is likely in 1999. The capital costs necessary to begin
remediation are expected to be incurred over the next twelve to eighteen
months.
Chesapeake cannot predict the ground-water remediation the EPA will select;
therefore, the Company has accrued $2.1 million at December 31, 1998 for the
Dover site and has recorded a regulatory asset for an equivalent amount. Of
this amount, $1.5 million is for ground-water remediation and $600,000 is for
the remaining soil remedition. The $1.5 million represents the low end of the
ground-water remedy estimates described above.
The Company initiated litigation against one of the other potentially
responsible parties for contribution to the remedial costs incurred by
Chesapeake in connection with complying with the ROD. At this time, management
cannot predict the outcome of the litigation or the amount of proceeds to be
received, if any. Management believes that the Company will be equitably
entitled to contribution from other responsible parties for a portion of the
expenses to be incurred in connection with the remedies selected in the ROD.
The Company expects that it will be able to recover actual costs incurred,
which are not recovered from other responsible parties, exclusive of
associated carrying costs, through the ratemaking process in accordance with
environmental cost recovery rider provisions currently in effect.
In cooperation with the Maryland Department of the Environment ("MDE"), in
1996 the Company completed construction and began remediation procedures at
the Salisbury site. In addition, the Company began quarterly reporting of the
remediation and monitoring results to the MDE. The Company has established a
liability with respect to the Salisbury site of $600,000 as of December 31,
1998. This amount is based on the estimated operating costs of the remediation
facilities over the next five years. A corresponding regulatory asset has been
recorded, reflecting the Company's belief that costs incurred will be
recoverable in base rates.
In addition, the Company has a site located in the state of Florida which is
currently being evaluated. At this time, no estimate of liability can be made.
It is management's opinion that any unrecovered current costs and any other
future costs incurred will be recoverable through future rates or sharing
arrangements with other responsible parties.
ENVIRONMENTAL COSTS INCURRED
- -------------------------------------------------------------------------
At December 31, 1998 1997
- -------------------------------------------------------------------------
Delaware $6,846,722 $5,317,380
Maryland 2,541,263 2,368,168
Florida 696,847 692,391
- -------------------------------------------------------------------------
Total costs incurred 10,084,832 8,377,939
Less: Amounts, net of insurance proceeds, which
have been approved for ratemaking treatment (8,391,953) (7,319,496)
- -------------------------------------------------------------------------
Amounts pending ratemaking recovery $1,692,879 $1,058,443
=========================================================================
M. Other Commitments and Contingencies
Natural Gas Supply
The Company's natural gas distribution operations have entered into
contractual commitments for daily entitlements of natural gas from various
suppliers. The contracts have various expiration dates.
Other
The Company is involved in certain legal actions and claims arising in the
normal course of business. The Company is also involved in certain legal and
administrative proceedings before various governmental agencies concerning
rates. In the opinion of management, the ultimate disposition of these
proceedings will not have a material effect on the consolidated financial
position of the Company.
N. Quarterly Financial Data (Unaudited)
In the opinion of the Company, the quarterly financial information shown below
includes all adjustments necessary for a fair presentation of the operations
for such periods. Due to the seasonal nature of the Company's business, there
are substantial variations in operations reported on a quarterly basis.
- -------------------------------------------------------------------------------
For the Quarters Ended, March 31 June 30 September 30 December 31*
- -------------------------------------------------------------------------------
1998
Operating Revenue $60,169,102 $43,594,944 $36,231,924 $43,572,825
Operating Income 4,744,218 962,101 (459,965) 3,194,728
Net Income 4,000,602 263,751 (1,266,498) 2,304,731
Earnings per share:
Basic $ 0.80 $ 0.05 $ (0.25) $ 0.45
Diluted $ 0.77 $ 0.05 $ (0.25) $ 0.44
- -------------------------------------------------------------------------------
1997
Operating Revenue $76,302,285 $44,918,820 $41,680,719 $59,587,440
Operating Income 4,148,755 1,392,667 (7,026) 3,132,068
Net Income 3,433,648 707,300 (762,784) 2,489,448
Earnings per share:
Basic $ 0.69 $ 0.14 $ (0.15) $ 0.50
Diluted $ 0.67 $ 0.14 $ (0.15) $ 0.49
- -------------------------------------------------------------------------------
* Results for the fourth quarter of 1998 reflect a one-time pension plan
curtailment gain of approximately $750,000, net of income tax
expense. See Note J to the Consolidated Financial Statements.
OPERATING STATISTICS
- ---------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996 1995 1994 (1)
- ---------------------------------------------------------------------------------------------------------------------
Revenues (in thousands)
Natural gas
Residential $ 19,274 $ 21,540 $ 18,256 $ 14,857 $15,228
Commercial 15,243 16,557 14,339 11,383 11,594
Industrial 15,953 22,625 28,546 36,898 32,718
Sale for resale 11,683 23,010 24,481 12,459 9,586
Transportation 6,120 4,212 3,369 2,993 2,639
Other 310 162 1,102 515 (50)
- ---------------------------------------------------------------------------------------------------------------------
Total natural gas revenues 68,583 88,106 90,093 79,105 71,715
Propane distribution and marketing (2) 102,873 125,159 161,812 147,596 17,789
Other 12,113 9,224 8,197 8,584 6,173
- ---------------------------------------------------------------------------------------------------------------------
Total revenues $183,569 $222,489 $260,102 $235,285 $95,677
===================================================================================================================
Volumes
Natural gas deliveries (in MMCF)
Residential 1,636 1,753 1,987 1,686 1,665
Commercial 1,907 2,113 2,059 1,792 1,771
Industrial 3,115 5,975 7,553 13,622 10,752
Sale for resale 1,194 1,200 1,065 990 998
Transportation 13,548 12,231 12,138 11,131 7,542
- ---------------------------------------------------------------------------------------------------------------------
Total natural gas deliveries 21,400 23,272 24,802 29,221 22,728
===================================================================================================================
Propane distribution
(in thousands of gallons) (2) 25,979 26,682 29,975 26,184 18,395
===================================================================================================================
Customers
Natural gas
Residential 32,473 31,277 30,349 29,285 28,260
Commercial 4,416 4,288 4,151 4,030 3,879
Industrial (3) 236 229 210 212 204
Sale for resale (3) 3 3 3 3 3
- ---------------------------------------------------------------------------------------------------------------------
Total natural gas customers 37,128 35,797 34,713 33,530 32,346
Propane distribution 34,988 33,998 32,218 31,372 22,180
- ---------------------------------------------------------------------------------------------------------------------
Total customers 72,116 69,795 66,931 64,902 54,526
====================================================================================================================
(1) 1994 has not been restated to include the business combinations with
Tri-County Gas Company, Inc., Tolan Water Service or Xeron, Inc.
(2) 1994 amounts exclude $2,895,000 in revenue and nine million gallons of
propane sold to one large wholesale customer.
(3) Includes transportation customers.
[GRAPH APPEARS HERE]
Natural Gas and Propane
Customer Growth
Natural Gas Propane
Year Customers Customers
---- --------- ---------
1994 32,346 22,180
1995 33,530 31,372
1996 34,713 32,218
1997 35,797 33,998
1998 37,152 34,988
[GRAPH APPEARS HERE]
Volumes Compared to Heating
Degree Days
Natural Propane Heating
Gas (in thousands Degree
Year (in MMCF) of gallons) Days
---- ------- ---------- -------
1994 22,728 18,395 4,398
1995 29,221 26,184 4,594
1996 24,741 29,975 4,717
1997 23,268 26,682 4,430
1998 21,400 26,029 3,704
Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure
None
PART III
Item 10. Directors and Executive Officers of the Registrant
Information pertaining to the Directors of the Company is incorporated herein
by reference to the Proxy Statement, under "Information Regarding the Board of
Directors and Nominees", dated and to be filed on or before March 30, 1999 in
connection with the Company's Annual Meeting to be held on May 18, 1999.
The information required by this item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Item 10 of Part I of this Form 10-K under "Executive Officers of the
Registrant."
Item 11. Executive Compensation
This information is incorporated herein by reference to the Proxy Statement,
under "Report on Executive Compensation", dated and to be filed on or before
March 30, 1999 in connection with the Company's Annual Meeting to be held on
May 18, 1999.
Item 12. Security Ownership of Certain Beneficial Owners and Management
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company's Securities", dated and to be
filed on or before March 30, 1999 in connection with the Company's Annual
Meeting to be held on May 18, 1999.
Item 13. Certain Relationships and Related Transactions
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company's Securities", dated and to be
filed on or before March 30, 1999 in connection with the Company's Annual
Meeting to be held on May 18, 1999.
PART IV
Item 14. Financial Statements, Financial Statement Schedules, Exhibits and
Reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements:
- - Accountants' Report dated February 12, 1999 of PricewaterhouseCoopers
LLP, Independent Accountants
- - Consolidated Statements of Income for each of the three years ended
December 31, 1998, 1997 and 1996
- - Consolidated Balance Sheets at December 31, 1998 and December 31, 1997
- - Consolidated Statements of Cash Flows for each of the three years ended
December 31, 1998, 1997 and 1996
- - Consolidated Statements of Common Stockholders' Equity for each of the
three years ended December 31, 1998, 1997 and 1996
- - Consolidated Statements of Income Taxes for each of the three years
ended December 31, 1998, 1997 and 1996
- - Notes to Consolidated Financial Statements
2. The following additional information for the years 1998, 1997 and 1996
is submitted herewith:
- - Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not required, are
inapplicable or the information is otherwise shown in the financial statements
or notes thereto.
(b) Reports on Form 8-K:
None.
(c) Exhibits:
Exhibit 2(a) Agreement and Plan of Merger by and between
Chesapeake Utilities Corporation and Tri-County Gas Company, Inc.,
filed on the Company's Form 8-K, File No. 001-11590 on January 13,
1997, is incorporated herein by reference.
Exhibit 3(a) Amended Certificate of Incorporation of
Chesapeake Utilities Corporation is incorporated herein by reference
to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for
the period ended June 30, 1998, File No. 001-11590.
Exhibit 3(b) Amended Bylaws of Chesapeake Utilities Corporation,
effective July 11, 1997, are incorporated herein by reference to
Exhibit 3.2 of the Quarterly Report on Form 10-Q for the period ended
June 30, 1998, File No. 001-11590.
Exhibit 4(a) Form of Indenture between the Company and Boatmen's
Trust Company, Trustee, with respect to the 8 1/4% Convertible
Debentures is incorporated herein by reference to Exhibit 4.2 of
the Company's Registration Statement on Form S-2, Reg. No. 33-26582,
filed on January 13, 1989.
Exhibit 4(b) Note Agreement dated February 9, 1993, by and
between the Company and Massachusetts Mutual Life Insurance Company
and MML Pension Insurance Company, with respect to $10 million of 7.97%
Unsecured Senior Notes due February 1, 2008, is incorporated
herein by reference to Exhibit 4 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1992, File No. 0-593.
Exhibit 4(c) Directors Stock Compensation Plan adopted by Chesapeake
Utilities Corporation in 1995 is incorporated herein by reference
to the Company's Proxy Statement dated April 17, 1995 in
connection with the Company's Annual Meeting held in May 1995.
Exhibit 4(d) Note Purchase Agreement entered into by the Company
on October 2, 1995, pursuant to which the Company privately placed $10
million of its 6.91% Senior Notes due in 2010, is not being filed
herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K.
The Company hereby agrees to furnish a copy of that agreement
to the Commission upon request.
Exhibit 4(e) Note Purchase Agreement entered into by the Company
on December 15, 1997, pursuant to which the Company privately placed
$10.million of its 6.85 senior notes due 2012, is not being filed
herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K.
The Company hereby agrees to furnish a copy of that agreement
to the Commission upon request.
Exhibit 10(a) Service Agreement dated November 1, 1989, by and between
Transcontinental Gas Pipe Line Corporation and Eastern Shore
Natural Gas Company, is incorporated herein by reference to
Exhibit 10 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1989, File No. 0-593.
Exhibit 10(b) Service Agreement dated November 1, 1989, by and
between Columbia Gas Transmission Corporation and Eastern Shore Natural
Gas Company, is incorporated herein by reference to Exhibit 10 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1989, File No. 0-593.
Exhibit 10(c) Service Agreement for General Service dated
November 1, 1989, by and between Florida Gas Transmission Company
and Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(d) Service Agreement for Preferred Service dated
November 1, 1989, by and between Florida Gas Transmission Company
and Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(e) Service Agreement for Firm Transportation Service
dated November 1, 1989, by and between Florida Gas Transmission
Company and Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(f) Form of Service Agreement for Interruptible
Sales Services dated May 11, 1990, by and between Florida Gas
Transmission Company and Chesapeake Utilities Corporation, is
incorporated herein by reference to Exhibit 10 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1990,
File No. 0-593.
Exhibit 10(g) Interruptible Transportation Service Agreement
dated February 23, 1990, by and between Florida Gas Transmission
Company and Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(h) Interruptible Transportation Service Agreement dated
November 30, 1990, by and between Florida Gas Transmission Company and
Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(i) Executive Employment Agreement dated March 26, 1997,
by and between Chesapeake Utilities Corporation and each Ralph J. Adkins
and John R. Schimkaitis is incorporated herein by reference to
Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the
period ended June 30, 1997, File No. 001-11590.
Exhibit 10(j) Form of Performance Share Agreement dated
January 1, 1998, pursuant to Chesapeake Utilities Corporation
Performance Incentive Plan by and between Chesapeake Utilities Corporation
and each of Ralph J. Adkins and John R. Schimkaitis is incorporated herein
by reference to Exhibit 10 of the Company's Annual Report on Form 10-K
for the year ended December 31, 1997, File No. 001-11590.
Exhibit 10(k) Chesapeake Utilities Corporation Cash Bonus
Incentive Plan dated January 1, 1992, is incorporated herein by reference
to Exhibit 10 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1991, File No. 0-593.
Exhibit 10(l) Chesapeake Utilities Corporation Performance
Incentive Plan dated January 1, 1992, is incorporated herein by
reference to the Company's Proxy Statement dated April 20, 1992,
in connection with the Company's Annual Meeting held on May 19, 1992.
Exhibit 10(m) Form of Stock Option Agreement dated January 1, 1998,
pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by
and between Chesapeake Utilities Corporation and each of Michael
P. McMasters, Stephen C. Thompson, William C. Boyles, Philip S.
Barefoot, Jeremy D. West, William P. Schneider and James R.
Schneider, is incorporated herein by reference to Exhibit 10 of
the Company's Annual Report on Form 10-K for the year ended
December 31, 1997, File No. 001-11590.
Exhibit 12 Computation of Ratio of Earning to Fixed Charges,
filed herewith.
Exhibit 21 Subsidiaries of the Registrant, filed herewith.
Exhibit 23 Consent of Independent Accountants, filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities
Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
CHESAPEAKE UTILITIES CORPORATION
By: /s/ JOHN R. SCHIMKAITIS
-------------------------
John R. Schimkaitis
President and Chief Executive Officer
Date: March 16, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ RALPH J. ADKINS /s/ JOHN R. SCHIMKAITIS
- ------------------------- -------------------------
Ralph J. Adkins, Chairman of the Board John R. Schimkaitis, President,
and Director Chief Executive Officer and Director
Date: March 16, 1999 Date: March 16, 1999
/s/ MICHAEL P. MCMASTERS /s/ RICHARD BERNSTEIN
- ------------------------- -------------------------
Michael P. McMasters, Vice President, Richard Bernstein, Director
Chief Financial Officer and Treasurer Date: March 16,1999
(Principal Financial Officer)
Date: March 16, 1999
/s/ WALTER J. COLEMAN /s/ John W. JARDINE, JR.
- ------------------------- -------------------------
Walter J. Coleman, Director John W. Jardine, Jr., Director
Date: March 16, 1999 Date: March 16, 1999
/s/ RUDOLPH M. PEINS, JR. /s/ ROBERT F. RIDER
- ------------------------- -------------------------
Rudolph M. Peins, Jr., Director Robert F. Rider, Director
Date: March 16, 1999 Date: March 16, 1999
/s/ JEREMIAH P. SHEA
- ------------------------- -------------------------
Jeremiah P. Shea, Director William G. Warden, III, Director
Date: March 16, 1999 Date: March 16, 1999
Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts
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Additions
-----------------------
Balance at Balance at
Beginning Charged to Other End of
For the Year Ended December 31, of Year Income Accounts(1) Deductions(2) Year
- --------------------------------------------------------------------------------------------
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
1998 $ 331,775 $280,391 $ 57,759 $ (367,412) $ 302,513
1997 $ 392,412 $203,624 $ 68,038 $ (332,299) $ 331,775
1996 $ 309,955 $364,622 $ 55,631 $ (337,796) $ 392,412
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(1) Recoveries.
(2) Uncollectible accounts charged off.