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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, 1999 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:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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COMMON STOCK - PAR VALUE PER SHARE $.4867 NEW YORK STOCK EXCHANGE, INC.
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
8.25% CONVERTIBLE DEBENTURES DUE 2014
(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X]. No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendments to
this Form 10-K. [X]
As of March 27, 2000, 5,220,000 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 27, 2000, as
reported by the New York Stock Exchange, was approximately $69 million.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2000 Annual Meeting of Stockholders are
incorporated by reference in Part III.
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CHESAPEAKE UTILITIES CORPORATION
FORM 10-K
YEAR ENDED DECEMBER 31, 1999
TABLE OF CONTENTS
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PART I 1
Item 1. Business 1
Item 2. Properties 10
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 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 45
PART III 45
Item 10. Directors and Executive Officers of the Registrant 45
Item 11. Executive Compensation 45
Item 12. Security Ownership of Certain Beneficial Owners and Management 45
Item 13. Certain Relationships and Related Transactions 45
PART IV 45
Item 14. Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K 45
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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 providing advanced
information services.
Chesapeake's three natural gas distribution divisions serve approximately 39,000
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 281-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 35,300 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 three primary business activities: natural gas
distribution and transmission, propane distribution and marketing, and advanced
information services. In addition to the three primary groups, Chesapeake has
four subsidiaries engaged in other service-related businesses.
(i) (a) NATURAL GAS DISTRIBUTION AND TRANSMISSION
GENERAL
Chesapeake distributes natural gas to approximately 39,000 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.
The Company offers natural gas supply management services in the state of
Florida under the name of Peninsula Energy Services Company ("PESCO").
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions
("Delaware", "Maryland" or "the divisions") serve an average of
approximately 29,400 customers, of which approximately 29,230 are
residential and commercial customers purchasing gas primarily for heating
purposes. For the year, residential and commercial customers account for
approximately 53% of the volume delivered by the divisions and 69% 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 9,545 residential and commercial and 88 industrial customers
in Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union and Citrus
Counties. Currently 39 of the division's industrial customers, which
purchase and transport gas on a firm and interruptible basis, account for
approximately 86% of the volume delivered by the Florida division and 34%
of the revenues. These customers are primarily engaged in the citrus and
phosphate industries and electric cogeneration.
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The Company's Florida division also provides natural gas supply management
services to compete in the open access environment. Currently, 25 customers
receive such services, which generated net income of $97,000 in 1999.
Eastern Shore. The Company's wholly owned transmission subsidiary, Eastern
Shore, operates an interstate natural gas pipeline and provides open access
transportation services for affiliated and non-affiliated companies through
an integrated gas pipeline extending from southeastern Pennsylvania to
Delaware and the Eastern Shore of Maryland. Eastern Shore also provides
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
General. The Delaware and Maryland divisions have firm and interruptible
contracts with four interstate "open access" pipelines including Eastern
Shore. The divisions are directly interconnected with Eastern Shore and
services upstream of Eastern Shore are contracted with Transco Gas Pipeline
Corporation ("Transco"), Columbia Gas Transmission ("Columbia") and
Columbia Gulf Transmission Company ("Gulf"). The divisions use their firm
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, which expires in 2000, with provisions to
continue from year to year thereafter, subject to six (6) months notice for
termination.
Delaware's contracts with Columbia include: (a) firm transportation
capacity of 852 Dt per day, which expires in 2014; (b) firm transportation
capacity of 1,132 Dt per day, which expires in 2017; (c) firm
transportation capacity of 549 Dt per day, which expires in 2018; (d) firm
transportation capacity of 899 per day, which expires in 2019; (e) firm
storage service providing a peak day entitlement of 6,193 Dt and a total
capacity of 298,195 Dt, which expires in 2014; and (f) firm storage
service, providing a peak day entitlement of 635 Dt and a total capacity of
57,139 Dt, which expires in 2017; (g) firm storage service providing a peak
day entitlement of 583 Dt and a total capacity of 52,460 Dt, which expires
in 2018; and (h) firm storage service providing a peak day entitlement of
583 Dt and a total capacity of 52,460 Dt, which expires in 2019. Delaware's
contracts with Columbia for storage-related transportation provide
quantities that are equivalent to the peak day entitlement for the period
of October through March and are equivalent to fifty percent (50%) of the
peak day entitlement for the period of April through September. The terms
of the storage-related transportation contracts mirror the storage services
that they support.
Delaware's contract with Gulf, which expires in 2004, provides firm
transportation capacity of 868 Dt per day for the period November through
March and 798 Dt per day for the period April through October.
Delaware's contracts with Eastern Shore include: (a) firm transportation
capacity of 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
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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 five suppliers. These supply contracts provide the availability
of a maximum firm daily entitlement of 14,200 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 and daily quantities may vary from month to month.
Maryland. Maryland's contracts with Transco include: (a) firm
transportation capacity of 4,738 Dt per day, which expires in 2005; (b)
firm transportation capacity of 155 Dt per day for December through
February, expiring in 2006; and (c) firm storage service providing a total
capacity of 33,120 Dt, which expires in 2000 with provisions to continue
from year to year thereafter, subject to six months notice for termination.
Maryland's contracts with Columbia include: (a) firm transportation
capacity of 442 Dt per day, which expires in 2014; (b) firm transportation
capacity of 908 Dt per day, which expires in 2017; (c) firm transportation
capacity of 350 Dt per day, which expires in 2018; (d) firm storage service
providing a peak day entitlement of 3,142 Dt and a total capacity of
154,756 Dt, which expires in 2014; and (e) firm storage service providing a
peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which
expires in 2017. Maryland's contracts with Columbia for storage-related
transportation provide quantities that are equivalent to the peak day
entitlement for the period October through March and are equivalent to
fifty percent (50%) of the peak day entitlement for the period April
through September. The terms of the storage-related transportation
contracts mirror the storage services that they support.
Maryland's contract with Gulf, which expires in 2004, provides firm
transportation capacity of 590 Dt per day for the period November through
March and 543 Dt per day for the period April through October.
Maryland's contracts with Eastern Shore include: (a) firm transportation
capacity of 13,378 Dt per day for the period December through February,
12,654 Dt per day for the months of November, March and April, and 8,093 Dt
per day for the period May through October; (b) firm storage capacity under
Eastern Shore's Rate Schedule GSS providing a peak day entitlement of 1,428
Dt and a total capacity of 70,665 Dt, which expires in 2013; (c) firm
storage capacity under Eastern Shore's Rate Schedule LSS providing a peak
day entitlement of 309 Dt and a total capacity of 15,500 Dt, which expires
in 2013; and (d) firm storage capacity under Eastern Shore's Rate Schedule
LGA providing a peak day entitlement of 569 Dt and a total capacity of
3,560 Dt, which expires in 2006. Maryland's firm transportation contracts
with Eastern Shore also include Eastern Shore's provision of swing
transportation service. This service includes: (a) firm transportation
capacity of 969 Dt per day on Transco's pipeline system, retained by
Eastern Shore, in addition to Maryland's Transco capacity referenced
earlier and (b) an interruptible storage service under Transco's Rate
Schedule ESS that supports a swing supply service provided under Transco's
Rate Schedule FS.
Maryland currently has contracts for the purchase of firm natural gas
supply with four suppliers. These contracts provide the availability of a
maximum firm daily entitlement of 7,540 Dt and the supplies are transported
by Transco, Columbia, Gulf and Eastern Shore under Maryland's
transportation contracts. The gas purchase contracts have various
expiration dates and daily quantities may vary from month to month.
Florida. The Florida division receives transportation service from Florida
Gas Transmission Company ("FGT"), a major interstate pipeline. Chesapeake
has contracts with FGT for: (a) daily firm transportation capacity of
27,579 Dt in November through April, 21,458 Dt in May through September,
and 27,416 Dt in October under FGT's firm transportation service FTS-1 rate
schedule; (b) daily firm transportation capacity of 5,100 Dt in May through
October, and 8,100 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
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rate schedule. The firm transportation contract FTS-1 expires on August 1,
2000 with the Company retaining a right of first refusal on this capacity.
The firm transportation contract FTS-2 expires on March 1, 2015. Chesapeake
has requested and been approved for a turnback of all but 1,000 Dt per day
year round of it's FTS-2 capacity in two increments. These turnbacks
coincide with the in service dates of FGT's Phase 4 Project scheduled to be
in service in May 2001, and the Phase 5 Project scheduled to be in service
in the second quarter of 2002. 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. The
Company believes that the availability of gas supply to the Florida
division is adequate under existing arrangements to meet customer's needs.
Eastern Shore. Eastern Shore has 4,916 thousand cubic feet ("Mcf") of firm
transportation capacity under Rate Schedule FT under contract with Transco,
which expires in 2005. Eastern Shore also has 7,046 Mcf of firm peak day
entitlements and total storage capacity of 278,264 Mcf under Rate Schedules
GSS, LSS and LGA, respectively, under contract with Transco. The GSS and
LSS contracts expire in 2013 and the LGA contract expires in 2006.
Eastern Shore also has firm storage service under Rate Schedule FSS and
firm storage transportation capacity under Rate Schedule SST under contract
with Columbia. These contracts, which expire in 2004, provide for 1,073 Mcf
of firm peak day entitlement and total storage capacity of 53,738 Mcf.
Eastern Shore has retained the firm transportation capacity and firm
storage services described above in order to provide swing transportation
service to those customers that requested such service.
COMPETITION
See discussion on competition in Item 7 under the heading "Management's
Discussion and Analysis -- Competition".
RATES AND REGULATION
General. Chesapeake's natural gas distribution divisions are subject to
regulation by the Delaware, Maryland and Florida Public Service Commissions
with respect to various aspects of the Company's business, including the
rates for sales to all of their customers in each jurisdiction. All of
Chesapeake's firm distribution rates are subject to purchased gas
adjustment clauses, which match revenues with gas costs and normally allow
eventual full recovery of gas costs. Adjustments under these clauses
require periodic filings and hearings with the relevant regulatory
authority, but do not require a general rate proceeding. Rates on
interruptible sales by the Florida division are also subject to purchased
gas adjustment clauses.
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.
Management monitors the rate of return in each jurisdiction in order to
ensure the timely filing of rate adjustment applications.
REGULATORY PROCEEDINGS
Delaware. In September 1998, Chesapeake's Delaware division filed an
application with the Delaware Public Service Commission ("DPSC") to propose
certain rate design changes to its existing margin sharing mechanism which
was approved in Chesapeake's last rate case. Chesapeake filed this
application as an alternative to a full scale
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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 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 increased or decreased the existing 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 additional capital investments. Chesapeake is
required to include the margins achieved from its interruptible customers
in its margin sharing calculation. 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 proposed
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 hearings and a final decision by
the DPSC during 1999. On March 23, 1999 the Company, DPSC Staff and the
Division of the Public Advocate settled all the issues in this matter. An
evidentiary hearing was held on March 24, 1999 at which time the executed
proposed settlement agreement was entered into the record as evidence and
was supported by all the respective parties. The settlement allows the
Company to increase or decrease the current margin sharing thresholds based
on the actual level of recovery of fixed distribution costs from
residential service heating and general service heating customers as
compared to the level which the base tariff rates were designed to recover
in the last rate case. Per the settlement, the Company can implement an
adjustment to the margin sharing thresholds if the weather is at least 6.5%
warmer or colder than normal; however, the total increase or decrease in
the amount of additional gross margin that the Company will retain or
credit to the firm ratepayers cannot exceed a $500,000 cap.
The Company withdrew its blanket proposal relating to the exclusion of
interruptible margins from the existing margin sharing mechanism for all
new or existing interruptible customers for whom the Company made a new or
additional capital investment to serve the customer, with one exception.
Per the settlement, the Company will exclude the interruptible margins from
the existing margin sharing mechanism for one specific interruptible
customer on its distribution system for whom the Company made a capital
investment to serve and currently has under a contract for interruptible
service. Any additional margin retained for this customer will be included
in the $500,000 cap mentioned above. The DPSC issued its final approval of
the proposed settlement on May 25, 1999.
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Maryland. During the 1999 Maryland General Assembly legislative session,
taxation of electric and gas utilities was fundamentally changed by the
passage of The Electric and Gas Utility Tax Reform Act ("Tax Act").
Effective January 1, 2000, the Tax Act altered utility taxation to account
for the restructuring of the electric and gas industries by either
repealing and/or amending the existing Public Service Company Franchise
Tax, Corporate Income Tax and Property Tax. A summary of the major
modifications that affected Chesapeake's natural gas operations in Maryland
are listed below.
- Applies the existing Public Service Commission Franchise Tax of
2% of gross receipts only to natural gas distribution delivery
service revenues.
- Imposes a separate per unit distribution tax of $0.0042 per Ccf
measured on the amount of natural gas delivered for final
consumption in the State.
- Establishes credits to the per unit distribution tax based on
actual consumption by industrial customers.
- Gas utility income is now subject to the Maryland State Corporate
Income Tax rate of 7%, due to the elimination of the gross
receipts deduction.
Chesapeake submitted a regulatory filing with the Maryland Public Service
Commission ("MPSC") on December 30, 1999 to implement new tariff sheets
necessary to incorporate the changes necessitated by the passage of the Tax
Act. The tariff revisions (1) would implement new base tariff rates to
reflect the estimated state corporate income tax liability; (2) assess the
new per unit distribution franchise tax; and (3) repeal specified portions
of the tariff that related to the former 2% gross receipts tax.
On January 12, 2000, the Maryland Public Service Commission ("MPSC") issued
an order requiring the Company to file new tariff sheets, with an effective
date of January 12, 2000, to increase its natural gas delivery service
rates by $82,763 on an annual basis to recover the estimated impact of the
state corporate income tax. Also as part of the MPSC order, the Company was
directed to recover the new distribution franchise tax of $0.0042 per Ccf
as a separate line item charge on the customers' bills. On January 14,
2000, the Company filed new natural gas tariff sheets in compliance with
the MPSC order.
In 1997, the 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.
Florida. On July 15, 1999, the Florida Division filed a Joint Petition with
Tampa Electric / Peoples Gas System for approval of a territorial boundary
agreement in Hillsborough, Polk and Osceola Counties. On November 10, 1999,
the Florida Public Service Commission issued an order approving the terms
and conditions of the agreement. The agreement included the transfer of
facilities in Hillsborough County owned by Chesapeake to Peoples Gas System
and the transfer of facilities in Gilchrist and Union Counties owned by
Peoples Gas System to Chesapeake. The transfers were made at the
depreciated book value of the facilities.
On August 19,1999, the Florida Division filed a petition with the Florida
Public Service Commission for approval of a gas transportation agreement
with Citrosuco North America, Inc. located in Polk County, Florida. The
Florida Public Service Commission approved the agreement on October 25,
1999. The agreement provides for the Florida
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Division to lease an 8-inch steel natural gas pipeline from Citrosuco and
in return the Florida Division will provide natural gas service under its
CTS rate schedule as a special contract.
On January 28, 2000, the Florida Division filed a request for approval of a
rate increase with the Florida Public Service Commission. The Minimum
Filing Requirements ("MFRs") are expected to be filed on March 31, 2000.
Interim rates may go into effect approximately 60 days after the acceptance
by the Florida Public Service Commission of the MFRs. The full rate case
procedure is estimated to take from eight to twelve months after acceptance
of the MFRs.
The Florida Public Service Commission is expected to issue a proposed rule
for the unbundling of natural gas services on February 14, 2000. This rule
will require all natural gas LDC's to file a tariff providing for the
unbundling of service to all non-residential customers by July 1, 2000. The
Florida Division intends to include this service as part of the rate case
filing.
Eastern Shore. On December 9, 1999, Eastern Shore filed an application
before the FERC requesting authorization for the following: (1) construct
and operate approximately two miles of 16-inch mainline looping in
Pennsylvania, (2) abandonment of one mile of 2-inch lateral in Delaware and
Maryland and replacement of the segment with a 4-inch lateral, (3)
construct and operate approximately ten miles of 6-inch mainline extension
in Delaware, (4) construct and operate five delivery points on the new
6-inch mainline extension in Delaware, and (5) install certain minor
auxiliary facilities at the existing Daleville compressor station in
Pennsylvania. The purpose of the construction is to enable Eastern Shore to
provide 7,065 Dts of additional daily firm service capacity on Eastern
Shore's system. The proposed expansion targeted for completion by November
1, 2000 is estimated to cost approximately $4.2 million.
In September 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 expansion was completed during the fourth quarter of 1999.
The project cost was approximately $7.0 million.
In March 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. In September 1998, Eastern Shore filed an amendment requesting
that the FERC authorize an increase in the diameter of the previously
approved 2.3-mile pipeline from 10 inches to 16 inches. This proposal was
approved by the FERC in October 1998. Construction was completed during
1999.
(i) (c) PROPANE DISTRIBUTION AND MARKETING
GENERAL
Chesapeake's propane distribution group consists of (1) Sharp Energy, Inc.
("Sharp Energy"), a wholly owned subsidiary of Chesapeake, (2) Sharpgas,
Inc. ("Sharpgas"), a wholly owned subsidiary of Sharp Energy, and (3)
Tri-County Gas Company, Inc. ("Tri-County") a wholly owned subsidiary of
Chesapeake. The propane marketing group consists of Xeron, Inc. ("Xeron"),
a wholly owned subsidiary of Chesapeake.
In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading
company located in Houston, Texas. Xeron markets propane to large
independent and petrochemical companies, resellers and southeastern retail
propane companies.
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The Company's propane distribution operation served approximately 35,300
propane customers on the Delmarva Peninsula and delivered approximately 28
million retail and wholesale gallons of propane during 1999.
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, it contracts 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.
8 Chesapeake Utilities Corporation
<PAGE> 11
(i) (d) ADVANCED INFORMATION SERVICES
GENERAL
Chesapeake's advanced information services segment consists of United
Systems, Inc. ("USI") a wholly owned subsidiary of the Company.
USI is based in Atlanta and primarily provides support for users of
PROGRESS(TM), 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 business faces 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 business 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 are wholly
owned subsidiaries of Chesapeake Service Company. Skipjack owns and leases
two office buildings in Dover, Delaware to affiliates of Chesapeake.
Chesapeake Investment Company is a Delaware affiliated investment company.
In March 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. ESR owns and leases office buildings
to affiliates and external companies.
In March 1998, the Company acquired Sam Shannahan Well Co., based in
Salisbury, Maryland, doing business as Tolan Water Service ("Tolan"). Tolan
was a privately owned EcoWater dealership serving 3,000 customers on the
Delmarva Peninsula with divisions supporting residential, commercial and
industrial water treatment.
In 1999, the Company established Sharp Water, Inc., a wholly owned
subsidiary of Chesapeake, which in November 1999, acquired EcoWater Systems
of Michigan, Inc., doing business as Douglas Water Conditioning, an
EcoWater dealership that has serviced the Detroit, Michigan area for 11
years.
(ii) SEASONAL NATURE OF BUSINESS
Revenues from the Company's residential and commercial natural gas sales
and from its propane distribution activities are affected by seasonal
variations, since the majority of these sales are to customers using the
fuels for heating purposes. Revenues from these customers are accordingly
affected by the mildness or severity of the heating season.
(iii) CAPITAL BUDGET
A discussion of capital expenditures by business segment is included in
Item 7 under the heading "Management Discussion and Analysis -- Liquidity
and Capital Resources".
(iv) EMPLOYEES
As of December 31, 1999, Chesapeake had 522 employees, including 331 in
natural gas and propane, 102 in advanced information services and 59 in
water conditioning. The remaining 30 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 Douglas Water Conditioning added 28 employees.
Chesapeake Utilities Corporation 9
<PAGE> 12
(v) EXECUTIVE OFFICERS OF THE REGISTRANT
Information pertaining to the executive officers of the Company is as
follows:
Ralph J. Adkins (age 57) 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., Sharp Water, Inc.
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 52) 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., Sharp Water, Inc. 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 41) 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 39) Mr. Thompson is Vice President of the Natural
Gas Operations, as well as Vice President of Chesapeake Utilities
Corporation. He has served as Vice President since May 1997. He has served
as President, Vice President, Director of Gas Supply and Marketing,
Superintendent of Eastern Shore and Regional Manager for the Florida
distribution Operations.
Philip S. Barefoot (age 52) Mr. Barefoot is Vice President of Chesapeake
Utilities Corporation. He has served as Division Manager of the Florida
Operations from 1988 to 1994. 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.
William C. Boyles (age 42) Mr. Boyles is Vice President and Corporate
Secretary of Chesapeake Utilities Corporation. Mr. Boyles has served as
Corporate Secretary since 1998 and Vice President since 1997. He previously
served as Director of Administrative Services, Director of Accounting and
Finance, Treasurer, Assistant Treasurer and Treasury Department Manager.
Prior to joining Chesapeake, he was employed as a Manager of Financial
Analysis at Equitable Bank of Delaware and Group Controller at Irving Trust
Company of New York.
ITEM 2. PROPERTIES
(a) GENERAL
The Company owns offices and operates facilities in the following locations:
Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford,
Laurel and Georgetown, Delaware; 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.
10 Chesapeake Utilities Corporation
<PAGE> 13
(b) TOLAN WATER SERVICE
The Company owns and operates a resin regeneration facility in Salisbury,
Maryland to serve approximately 3,000 exchange tank and meter water customers.
(c) NATURAL GAS DISTRIBUTION
Chesapeake owns over 645 miles of natural gas distribution mains (together with
related service lines, meters and regulators) located in its Delaware and
Maryland service areas and 547 miles of such mains (and related equipment) in
its Central Florida service areas. Chesapeake also owns facilities in Delaware
and Maryland for propane-air injection during periods of peak demand. Portions
of the properties constituting Chesapeake's distribution system are encumbered
pursuant to Chesapeake's First Mortgage Bonds.
(d) NATURAL GAS TRANSMISSION
Eastern Shore owns approximately 281 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.
(e) PROPANE DISTRIBUTION AND MARKETING
Sharpgas and Tri-County own bulk propane storage facilities with an aggregate
capacity of approximately 1.8 million gallons at 31 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 they had discovered
contamination on a parcel of land it purchased in 1949 from Dover Gas Light
Company, a predecessor gas company. The State also asserted that the Company was
the responsible party for any clean-up and prospective environmental monitoring
of the site. The Delaware Department of Natural Resources and Environmental
Control ("DNREC") and Chesapeake conducted subsequent investigations and studies
in 1984 and 1985. Soil and ground-water contamination associated with the
operations of the former manufactured gas plant ("MGP"), the Dover Gas Light
Company, were found on the property.
In February 1986, the State of Delaware entered into an agreement ("the
1986-Agreement") with Chesapeake whereby Chesapeake reimbursed the State for its
costs to purchase an alternate property for construction of its Family Court
Building and the State agreed to never construct on the property of the former
manufactured gas plant.
In October 1989, the Environmental Protection Agency ("EPA") listed the Dover
Gas Light Site ("site") on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA" or
Chesapeake Utilities Corporation 11
<PAGE> 14
"Superfund"). EPA named both the State of Delaware and the Company as
potentially responsible parties ("PRPs") for the site.
The EPA issued a clean-up remedy for the site through a Record of Decision
("ROD") dated August 16, 1994. The remedial action selected by the EPA in the
ROD addressed the ground-water and soil. The ground-water remedy included a
combination of hydraulic containment and natural attenuation. The soil remedy
included complete excavation of the former MGP property. The ROD estimated the
costs of the selected remediation of ground-water and soil at $2.7 million and
$3.3 million, respectively.
In May 1995, EPA issued an order to the Company under section 106 of CERCLA (the
"Order"), which required the Company to implement the remedy described in the
ROD. The Order was also issued to General Public Utilities Corporation, Inc.
("GPU"), which both EPA and the Company believe is liable under CERCLA. Other
PRPs, such as the State of Delaware, were not ordered to perform the ROD.
Although notifying EPA of its objections to the Order, the Company agreed to
comply. GPU informed EPA that it did not intend to comply with the Order and to
this date has not complied with the EPA Order.
The Company performed field studies and investigations during 1995 and 1996 to
further characterize the extent of contamination at the site. In April 1997, the
EPA issued a fact sheet stating that the EPA was considering a modification to
the soil remedy that would take into account the site's future land use
restrictions, which prohibited future development on the site. The EPA proposed
a soil remediation that included some on-site excavation of contaminated soils
and use of institutional controls; EPA estimated the cost of its proposed soil
remedy at $5.7 million. Additionally, the fact sheet acknowledged that the soil
remedy described in the ROD would cost $10.5 million, instead of the $3.3
million estimated in the ROD, making the overall remedy cost $13.2 million
($10.5 million to perform the soil remedy and $2.7 million to perform the
ground-water remediation).
In June 1997, the Company submitted a supplement to the focused feasibility
study, which proposed an alternative soil remedy that would take into account
the 1986-Agreement between Chesapeake and the State restricting future
development at the site. On December 16, 1997, the EPA issued a ROD Amendment to
modify the soil remedy to include: (1) excavation and off-site thermal treatment
of the contents of the former subsurface gas holders; (2) implementation of soil
vapor extraction; (3) pavement of the parking lot and (4) use of institutional
controls restricting future development on the site. The overall clean-up cost
of the site was estimated at $4.2 million ($1.5 million for soil remediation and
$2.7 million for ground-water remediation) as compared to the ROD cleanup
estimate of $13.2 million ($10.5 million for soil remediation and $2.7 million
for ground-water remediation).
During the fourth quarter of 1998, the Company completed the field work
associated with the remediation of the gas holders (a major component of the
soil remediation). During the first quarter of 1999, the Company submitted
reports to the EPA documenting the gas holder remedial activities and requesting
closure of the gas holder remedial project. In April 1999, the EPA approved the
closure of the gas holder remediation project, certified that all performance
standards for the project were met and no additional work was needed for that
phase of the soil remediation. The gas holder remediation project was completed
at a cost of $550,000.
During 1999, the Company completed the construction of the soil vapor extraction
system (another major component of the soil remediation) and continued with the
ongoing operation of the system at a cost of $250,000. Over the next twelve to
eighteen months the Company expects to complete the soil vapor extraction
portion of the soil remediation, initiate final construction of a parking lot
and proceed with a ground-water remedial program.
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 $3.3 million in capital and $1.0 million per year in
operating costs to operate a pump-and-treat / ground-water containment system.
The pump-
12 Chesapeake Utilities Corporation
<PAGE> 15
and-treat / ground-water containment system is intended to contain the MGP
contaminants to allow the ground-water outside of the containment area to
naturally attenuate. The operating cost estimate for the containment system is
dependent upon the actual ground-water quality and flow conditions. The EPA has
also requested that the Company submit a design for a limited ground-water
containment system that is estimated to cost $2.8 million in capital and
$600,000 per year in operating costs. The EPA has requested that the design be
submitted in enough time to allow the EPA to approve it by July 14, 2000. The
Company continues to believe that a ground-water containment system is not
necessary for the MGP contaminants, that there is insufficient information to
design an overall ground-water containment program and that natural attenuation
is the appropriate remedial action for the MGP wastes.
The Company cannot predict what the EPA will require for the overall
ground-water program, and accordingly, has accrued $2.1 million at December 31,
1999 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 remediation. The $1.5 million represents the low end of the
ground-water remedy estimates described above.
In March 1995, the Company commenced litigation against the State of Delaware
for contribution to the remedial costs being incurred to implement the ROD. In
December of 1995, this case was dismissed without prejudice based on a
settlement agreement between the parties (the "Settlement"). Under the
Settlement, the State agreed to: reaffirm its 1986-Agreement with Chesapeake not
to construct on the MGP property and support the Company's proposal to reduce
the soil remedy for the site; contribute $600,000 toward the cost of
implementing the ROD and reimburse the EPA for $400,000 in oversight costs. The
Settlement is contingent upon a formal settlement agreement between EPA and the
State of Delaware. Upon satisfaction of all conditions of the Settlement, the
litigation will be dismissed with prejudice.
In June 1996, the Company initiated litigation against GPU for response costs
incurred by Chesapeake and a declaratory judgment as to GPU's liability for
future costs at the site. In August 1997, the United States Department of
Justice also filed a lawsuit against GPU seeking a Court Order to require GPU to
participate in the site clean-up, pay penalties for GPU's failure to comply with
the EPA Order, pay EPA's past costs and a declaratory judgment as to GPU's
liability for future costs at the site. In November 1998, Chesapeake's case was
consolidated with the United States' case against GPU. A case management order
has been set with a trial scheduled for February 2001. At this time, management
cannot predict the outcome of the litigation or the amount of proceeds to be
received, if any.
The Company is currently engaged in investigations related to additional parties
who may be PRPs. Based upon these investigations, the Company will consider
filings lawsuits against these 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
remedial costs. 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.
Through December 31, 1999, the Company has incurred approximately $7.4 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 associated deferred tax benefit. The deferred tax
benefit is simply the carrying cost savings associated with the timing of the
deduction of environmental costs for tax purposes as opposed to financial
reporting purposes. Each year an environmental surcharge rate is calculated to
become effective December 1. The surcharge or rider rate is based on the
amortization of expenditures through September of the filing year plus
amortization of expenses from previous years. The advantage of the rider is that
it is not necessary to file
Chesapeake Utilities Corporation 13
<PAGE> 16
a rate case every year to recover expenses incurred. Through December 31, 1999,
the unamortized balance and amount of environmental costs not included in the
rider; effective January 1, 2000 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 Air Sparging and Soil-Vapor
Extraction remediation procedures. Chesapeake has been reporting the remediation
and monitoring results to the MDE on an ongoing basis since 1996.
The estimated cost of the remaining remediation is approximately $100,000 per
year for operating expenses for a period of two years and capital costs of
$50,000 to shut down the remediation process in year 2. Based on these estimated
costs, the Company adjusted both its liability and related regulatory asset to
$240,000 on December 31, 1999, to cover the Company's projected remediation
costs for this site. Through December 31, 1999, the Company has incurred
approximately $2.7 million for remedial actions and environmental studies. Of
this amount, approximately $901,000 of incurred costs have not been recovered
through insurance proceeds or received ratemaking treatment. Chesapeake will
apply for the recovery of these and any future costs in the next base rate
filing with the Maryland Public Service Commission.
WINTER HAVEN COAL GAS SITE
Chesapeake has been working with the Florida Department of Environmental
Protection ("FDEP") in assessing a coal gas site in Winter Haven, Florida. In
May 1996, the Company filed an Air Sparging and Soil Vapor Extraction Pilot
Study Work Plan for the Winter Haven site with the FDEP. The Work Plan described
the Company's proposal to undertake an Air Sparging and Soil Vapor Extraction
("AS/SVE") pilot study to evaluate the site. After discussions with the FDEP,
the Company filed a modified AS/SVE Pilot Study Work Plan, the description of
the scope of work to complete the site assessment activities and a report
describing a limited sediment investigation performed in 1997. In December 1998
the FDEP approved the AS/SVE Pilot Study Work Plan, which the Company completed
during the third quarter of 1999. Chesapeake has reported the results of the
Work Plan to the FDEP for further discussion and review. It is not possible to
determine what remedial action will be required by FDEP or the cost of such
remediation.
The Company has recovered all environmental costs incurred to date,
approximately $765,000, through rates charged to customers. Additionally, the
Florida Public Service Commission has allowed the Company to continue to recover
amounts for future environmental costs that might be incurred. At December 31,
1999, Chesapeake had received $505,000 related to future costs, which might be
incurred.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
14 Chesapeake Utilities Corporation
<PAGE> 17
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 1999 and
1998 were as follows:
<TABLE>
<CAPTION>
DIVIDENDS
DECLARED
QUARTER ENDED HIGH LOW CLOSE PER SHARE
1999
<S> <C> <C> <C> <C> <C>
March 31 $19.5000 $15.8750 $16.0625 $0.2500
June 30 18.8750 14.8750 18.5625 0.2500
September 30 19.8125 17.1875 17.2500 0.2600
December 31 19.6250 17.1250 18.3750 0.2600
1998
March 31 $20.5000 $18.2500 $18.3750 $0.2500
June 30 18.5000 17.1250 17.6250 0.2500
September 30 18.5000 16.5000 17.9375 0.2500
December 31 18.5000 17.0000 18.9375 0.2500
</TABLE>
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 $17.6 million.
At December 31, 1999, there were approximately 2,212 shareholders of record of
the Common Stock.
Chesapeake Utilities Corporation 15
<PAGE> 18
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
(dollars in thousands except stock data)
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997 1996 1995
- -------------------------------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
OPERATING
Operating revenues ...................... $ 230,863 $ 183,569 $ 222,489 $ 260,102 $ 235,285
Operating income ........................ $ 10,669 $ 8,441 $ 8,666 $ 10,099 $ 9,962
Net income............................... $ 8,271 $ 5,303 $ 5,868 $ 7,782 $ 7,696
BALANCE SHEET
Gross property, plant and equipment ..... $ 172,088 $ 152,991 $ 144,251 $ 134,001 $ 120,746
Net property, plant and equipment ....... $ 117,663 $ 104,266 $ 99,879 $ 94,014 $ 85,055
Total assets ............................ $ 166,968 $ 145,234 $ 145,719 $ 155,786 $ 130,998
Long-term debt, net of current maturities $ 33,777 $ 37,597 $ 38,226 $ 28,984 $ 31,619
Total stockholders' equity .............. $ 60,165 $ 56,356 $ 53,656 $ 50,699 $ 45,587
Capital expenditures .................... $ 25,917 $ 12,650 $ 13,471 $ 15,399 $ 12,887
COMMON STOCK
Earnings per share:
Basic ................................... $ 1.61 $ 1.05 $ 1.18 $ 1.58 $ 1.59
Diluted ................................. $ 1.57 $ 1.04 $ 1.16 $ 1.55 $ 1.56
Average shares outstanding .............. 5,144,449 5,060,328 4,972,086 4,912,136 4,836,430
Number of registered shareholders ....... 2,212 2,271 2,178 2,213 2,098
Cash dividends per share ................ $ 1.02 $ 1.00 $ 0.97 $ 0.93 $ 0.90
Book value per share .................... $ 11.60 $ 11.06 $ 10.72 $ 10.26 $ 9.38
Common equity/Total capitalization ...... 64.04% 59.98% 58.40% 63.63% 59.05%
Return on average equity ................ 14.20% 9.64% 11.25% 16.16% 18.58%
NUMBER OF EMPLOYEES
Natural gas and propane ................. 331 322 307 263 256
Advanced information services ........... 102 81 63 49 55
Corporate and other ..................... 89 53 27 26 24
Total ................................... 522 456 397 338 335
</TABLE>
[GRAPHS APPEARS HERE]
<TABLE>
Growth in Book Value Earnings Compared to Heating
Compared to Dividend Growth Degree-Days
Dividends Heating
Year Book Value Per Share Earnings Degree-Days
- ---- ---------- --------- -------- -----------
<S> <C> <C> <C> <C>
1995 $9.37 $0.90 $1.59 4,594
1996 $10.26 $0.93 $1.58 4,717
1997 $10.72 $0.97 $1.18 4,430
1998 $11.06 $1.00 $1.05 3,704
1999 $11.60 $1.02 $1.61 4,082
</TABLE>
16 Chesapeake Utilities Corporation
<PAGE> 19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
BUSINESS DESCRIPTION
Chesapeake Utilities Corporation is a diversified utility company engaged in
natural gas distribution and transmission, propane distribution and wholesale
marketing and advanced information services.
LIQUIDITY AND CAPITAL RESOURCES
Chesapeake's capital requirements 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 to temporarily finance capital expenditures. During 1999, net cash provided
by operating activities was $16.6 million, cash used by investing activities was
$22.9 million and cash provided by financing activities was $6.1 million. Based
upon anticipated cash requirements in 2000, the Company may refinance its
short-term debt and capital requirements through the issuance of long-term debt.
The timing of such an issuance is dependent upon the nature of the securities
involved as well as current market and economic conditions.
The Board of Directors has authorized the Company to borrow up to $35.0 million
from various banks and trust companies. As of December 31, 1999, Chesapeake had
four unsecured bank lines of credit, totaling $36.0 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, 1999 and 1998 were $23.0 million and $11.6 million,
respectively. In 1999 and 1998, Chesapeake used cash provided by operations and
short-term borrowing to fund capital expenditures. The increase in the
short-term borrowing balance of $11.4 million was primarily due to capital
expenditures during 1999.
During 1999, 1998 and 1997, capital expenditures were approximately $25.1
million, $12.0 million and $12.4 million, respectively. The increase in capital
expenditures from 1998 to 1999, was primarily due to the expansion of both the
Company's natural gas transmission pipeline and its Florida natural gas
distribution system, as well as the acquisition of EcoWater Systems of Michigan.
Chesapeake has budgeted $23.0 million for capital expenditures during 2000. This
amount includes $17.2 million for natural gas distribution and transmission,
$4.1 million for propane distribution and marketing, $400,000 for advanced
information services and $1.3 million for general plant. The natural gas
distribution expenditures are for expansion and improvement of facilities.
Natural gas transmission expenditures are for improvement and expansion of the
pipeline system to increase the level of service provided to existing customers
and to provide service to customers in the City of Milford, Delaware. The
propane expenditures are to support customer growth and for the replacement of
equipment. The advanced information services expenditures are for computer
hardware, software and related equipment. Expenditures for general plant include
building improvements, computer software and hardware. Financing for the 2000
capital expenditure program is expected to be provided from short-term
borrowing, cash provided by operating activities and the potential issuance of
long-term debt. The capital expenditure program is subject to continuous review
and modification. Actual capital 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 $1.2 million for environmental related expenditures
during 2000 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, 1999, common equity represented 64.0 percent of permanent
capitalization, compared to 60.0 percent in 1998 and 58.4 percent in 1997.
Including short-term borrowing, capitalization would be 51.5 percent, 53.4
percent and 53.9 percent. Chesapeake remains committed to maintaining a sound
capital structure and strong credit
Chesapeake Utilities Corporation 17
<PAGE> 20
ratings to provide the financial flexibility needed to access the capital
markets when required. This commitment, along with adequate and timely rate
relief for the Company's regulated operations, is intended to ensure that
Chesapeake will be able to attract capital from outside sources at a reasonable
cost. The achievement of these objectives will provide benefits to customers and
creditors, as well as to the Company's investors.
FINANCING ACTIVITIES
During the past two years, the Company has utilized debt and equity financing
for the purpose of funding capital expenditures and acquisitions.
Chesapeake exchanged 25,000 shares of its common stock to acquire Sam Shannahan
Well Co., Inc., operating as Tolan Water Service ("Tolan"), on March 31, 1998.
Tolan provides water conditioning and treatment services and equipment to
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 in exchange for 475,000 shares of the Company's
common stock. Xeron markets propane to large independent oil and petrochemical
companies, resellers and southeastern retail propane companies. Each of these
business combinations was accounted for as a pooling of interests.
During 1999 and 1998, Chesapeake repaid approximately $1.5 million and $1.1
million of long-term debt, respectively.
In connection with its Automatic Dividend Reinvestment and Stock Purchase Plan,
Chesapeake issued 36,319, 32,925 and 32,169 shares of common stock during the
years of 1999, 1998 and 1997, respectively.
RESULTS OF OPERATIONS
Net income for 1999 was $8.3 million as compared to $5.3 million for 1998 and
$5.9 million for 1997. The increase in net income for 1999 reflected improved
pre-tax operating income for each of the Company's three business segments. The
natural gas and propane segments each benefited from increased deliveries
related to customer growth, averaging more than 4 percent in 1999, combined with
cooler temperatures. Based on heating degree-days, temperatures for 1999 were 10
percent cooler than 1998, but still 11 percent warmer than normal. The natural
gas segment also benefited from an increase in transportation services. Pre-tax
operating income for the advanced information services segment increased due to
additional consulting projects and product sales. Net income for 1999 includes
an after-tax gain of $863,000 on the sale of the Company's investment in Florida
Public Utilities Company (see Note E to the Consolidated Financial Statements).
Net income for 1998 includes an after-tax gain of $750,000 from the
restructuring of the Company's retirement benefit plans (see Note J to the
Consolidated Financial Statements).
The decline in net income from 1997 to 1998 is primarily related to warmer
temperatures, partially offset by the after-tax gain on the restructuring of the
Company's retirement plans. Based on heating degree-days, temperatures for 1998
were 16 percent warmer than 1997 and 19 percent warmer than normal.
PRE-TAX OPERATING INCOME (IN THOUSANDS)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 (DECREASE) 1998 1997 (DECREASE)
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
BUSINESS SEGMENT:
Natural gas distribution and transmission $10,300 $ 8,814 $1,486 $ 8,814 $ 9,219 $(405)
Propane distribution and marketing 2,627 971 1,656 971 1,158 (187)
Advanced information services 1,470 1,316 154 1,316 1,046 270
Other and Eliminations 446 522 (76) 522 671 (149)
- ----------------------------------------------------------------------------------------------------------------
TOTAL PRE-TAX OPERATING INCOME $14,843 $11,623 $3,220 $11,623 $12,094 $(471)
</TABLE>
18 Chesapeake Utilities Corporation
<PAGE> 21
NATURAL GAS DISTRIBUTION AND TRANSMISSION
Pre-tax operating income increased $1.5 million from 1998 to 1999. The increase
was a result of a $3.3 million increase in gross margin offset by a $1.8 million
increase in operating expenses. The principle factors responsible for this
increase in gross margin were:
- higher levels of firm transportation services provided on a
limited-term basis, combined with the 1999 expansion;
- customer growth of 5.1 percent, primarily residential and
commercial; and
- greater deliveries due to temperatures in 1999 which were 10
percent cooler than 1998.
These factors were offset somewhat by a decline in margins earned on volumes
sold and transported to industrial customers in the Florida service territory.
The customer growth and cooler temperatures resulted in an 11 percent increase
in volumes delivered to residential and commercial customers. Under normal
temperatures and customer usage, the 5.1 percent customer growth is estimated to
generate an additional margin of $870,000 on an annual basis.
In 1998, the Company restructured its retirement benefit plans ("the benefit
restructuring"), resulting in a one-time reduction of $1.2 million in pension
expenses. Exclusive of the benefit restructuring, operating expenses increased
by $1.0 million, or 4.7 percent. The principle costs that contributed to higher
operating expenses were depreciation, compensation, marketing and benefits.
NATURAL GAS GROSS MARGIN SUMMARY (IN THOUSANDS)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
INCREASE INCREASE
For the Years Ended December 31, 1999 1998 (decrease) 1998 1997 (decrease)
- --------------------------------------------------------------------------------------------------------------------
Gross Margin:
<S> <C> <C> <C> <C> <C> <C>
Sales $ 26,310 $ 25,186 $ 1,124 $ 25,186 $ 25,322 $ (136)
Transportation 5,793 3,969 1,824 3,969 4,284 (315)
Marketing 207 174 33 174 185 (11)
Non-gas sales 540 187 353 187 116 71
- --------------------------------------------------------------------------------------------------------------------
TOTAL GROSS MARGIN $ 32,850 $ 29,516 $ 3,334 $ 29,516 $ 29,907 $ (391)
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
The $405,000 reduction in pre-tax operating income from 1997 to 1998 was
primarily the result of a reduction in gross margin, as indicated in the
preceding table. The reduction in gross margin was due to a reduction in
transportation and sales revenues. Deliveries to residential and commercial
customers decreased by 12 percent, after taking into account customer growth of
4 percent. This reduction in deliveries was due to temperatures which were 19
percent warmer than normal and 16 percent warmer than 1997. Also contributing to
the decline in gross margin was an 11 percent reduction in volumes delivered to
industrial customers located in the Florida service territory.
Operating expenses for 1998 were higher primarily in the areas of marketing,
legal fees, building rent, pipeline system maintenance, depreciation and
amortization. These increases were substantially offset by decreases in
compensation and those due to the benefit restructuring.
Chesapeake Utilities Corporation 19
<PAGE> 22
PROPANE DISTRIBUTION AND MARKETING
Pre-tax operating income for 1999 was $2.6 million compared to $1.0 million for
1998. This increase of $1.6 million was the result of a $1.9 million increase in
gross margin, offset by an increase in operating expenses of $300,000.
Gross margin was higher due to the following:
- gallons delivered by the distribution operation increased by
11 percent;
- margin earned per gallon sold by the distribution operation
increased by 6.4 percent; and
- wholesale marketing margins earned increased by 28 percent.
The increase in gallons delivered by the distribution operation was directly
related to temperatures which were 10 percent cooler than 1998 coupled with a
3.4 percent growth in customers. During 1999, marketing revenues increased by
$35 million or 44 percent while margins increased $360,000. Wholesale marketing
is a high volume, low margin business. Operating expenses increased in 1999;
primarily in the areas of incentive compensation, marketing and benefits costs.
The Company estimates that the warm temperatures experienced in 1999 reduced
pre-tax operating income by approximately $1.2 million.
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 pre-tax operating income 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 Company's benefit restructuring, pre-tax operating
income decreased $463,000 or 40 percent. The propane distribution operation was
negatively affected by the warmer temperatures experienced in 1998, resulting in
a decline in sales volumes of 8.2 percent, after taking into account a 2.9
percent increase in customer growth. Somewhat offsetting this volume-related
decline in margin was an increase of 6.5 percent 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. During 1998, marketing revenues
declined by $18.1 million or 18 percent while margins declined by $250,000 or 16
percent. Operating expenses declined primarily due to incentive compensation,
pension expense and administrative fees associated with the pension plan.
The Company estimates that the warm temperatures experienced in 1998 reduced
pre-tax operating income by approximately $1.9 million when compared to normal
temperatures. In addition, margins during 1998 were lower than historical norms,
further reducing pre-tax operating income by approximately $1.6 million.
ADVANCED INFORMATION SERVICES
The results of the advanced information services segment consisted primarily of
those of United Systems, Inc. ("USI"). Pre-tax operating income for 1999
increased $154,000 or 12 percent over 1998. This increase was the result of
revenue growth of $3.2 million or 31, resulting in a gross margin increase of
$1.3 million or 24 percent. The majority of revenue growth is due to increased
web-related products and services. The increase in costs were primarily in the
areas of compensation, marketing and uncollectible accounts.
Exclusive of the Company's benefit restructuring, pre-tax operating income
contributed by USI increased 15 percent or $156,000 from 1997 to 1998. Gross
margin increased $1.5 million, or 38 percent, due to increases in traditional
Progress-based consulting.
INCOME TAXES
The increase in pre-tax operating income and recognition of accumulated deferred
income tax timing differences at the 35 percent federal rate were the primary
reasons for the $992,000 increase in operating income taxes from 1998 to 1999.
Offsetting these increases was a $238,000 reduction in the income tax accrual
due to a reassessment of known tax exposures. Income taxes decreased from 1997
to 1998 due to the reduction in pre-tax operating income. This was
20 Chesapeake Utilities Corporation
<PAGE> 23
partially offset by a one-time expense to establish the deferred income tax
liability in connection with the 1997 acquisition of Tri-County Gas Company,
Inc.
OTHER
Non-operating income was $1,068,000, $241,000 and $545,000 for the years 1999,
1998 and 1997, respectively. In 1999, the Company recognized a pre-tax gain of
$1,415,000, or $863,000 after tax, on the sale of Chesapeake's investment in
Florida Public Utilities Company (see Note E to the Consolidated Financial
Statements). Exclusive of this transaction, non-operating income for 1999 was
$205,000. The resulting decrease from 1998 was primarily due to a reduction in
interest income. The decrease in non-operating income from 1997 to 1998 is
primarily attributable to pre-tax gains of $452,000 on the sale of fixed assets
included in 1997. Also contributing to the 1998 decline is a reduction in
interest income of $100,000 from 1997 to 1998.
REGULATORY ACTIVITIES
The Company's natural gas distribution operations are subject to regulation by
the Delaware, Maryland and Florida Public Service Commissions while the natural
gas transmission operation is subject to regulation by the Federal Energy
Regulatory Commission.
In 1999, the Company requested and received approval from the Delaware Public
Service Commission to adjust its interruptible margin sharing mechanism in order
to address the level of recovery of fixed distribution costs from residential
and small commercial heating customers during the twelve month period of August
1 to July 31. The Company is now allowed to increase or decrease the current
margin sharing thresholds based on the actual level of recovery of fixed
distribution costs from heating customers as compared to the level which the
base tariff rates were designed to recover. Starting in August 1999, the Company
can implement an adjustment to the margin sharing thresholds if the weather is
at least 6.5 percent warmer or colder than normal. The total increase or
decrease in the amount of additional gross margin that the Company will retain
or credit to the firm ratepayers cannot exceed a $500,000 cap during the
twelve-month period ending in July of each year. Any credits to firm ratepayers
will be processed through the interruptible margin sharing mechanism. The
Company expects to file for a similar ratemaking adjustment with the Maryland
Public Service Commission ("MPSC") during 2000.
During the 1999 Maryland General Assembly legislative session, taxation of
electric and gas utilities was changed by the passage of The Electric and Gas
Utility Tax Reform Act ("Tax Act"). Effective January 1, 2000, the Tax Act
altered utility taxation to account for the restructuring of the electric and
gas industries by either repealing and/or amending the existing Public Service
Company Franchise Tax, Corporate Income Tax and Property Tax. Prior to this Tax
Act, the State of Maryland allowed utilities a credit to their income tax
liability for Maryland gross receipts taxes paid during the year. The
modification eliminates the gross receipts tax credit. Chesapeake filed and
received approval from the MPSC to increase its natural gas delivery service
rates by $83,000 on an annual basis to recover the estimated impact of the Tax
Act.
Chesapeake plans to file for a base rate increase with the Florida Public
Service Commission during the second quarter of 2000. Interim rates are expected
to be put into effect, subject to refund, in the second or third quarter of
2000.
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. Long-term debt is subject to potential losses based on the
change in interest rates. The Company's long-term debt consists of first
mortgage
Chesapeake Utilities Corporation 21
<PAGE> 24
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 $36.4 million at December 31, 1999 as compared to a fair
value of $36.3 million, based mainly on current market prices or discounted cash
flows using current rates for similar issues with similar terms and remaining
maturities. The Company is exposed to changes in interest rates as a result of
financing through its issuance of fixed-rate long-term debt. The Company
evaluates whether to refinance existing debt or permanently finance existing
short-term borrowing based in part on the fluctuation in interest rates.
The propane marketing operation is a party to natural gas liquids ("NGL")
forward contracts, primarily propane contracts, with various third parties.
These contracts require that the propane marketing operation purchase or sell
NGL at a fixed price at fixed future dates. At expiration, the contracts are
settled by the delivery of NGL to the 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 propane marketing operation is subject to commodity
price risk on its open positions to the extent that NGL market prices deviate
from fixed contract settlement amounts. Market risk associated with the trading
of futures and forward contracts are monitored daily for compliance with
Chesapeake's Risk Management Policy, which includes volumetric limits for open
positions. To manage exposures to changing market prices, open positions are
marked 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. Quantitative information on the forward and futures
contracts at December 31, 1999 is shown below. All of the contracts mature
during 2000.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
QUANTITY ESTIMATED WEIGHTED AVERAGE
At December 31, 1999 in gallons Market Prices Contract Prices
- -----------------------------------------------------------------------------------------------------------------
Forward Contracts
<S> <C> <C> <C>
Sale 9,954,000 $.3350-- $.5250 $0.4412
Purchase 8,064,000 $.3250-- $.5200 $0.4121
Futures Contracts
Purchase 2,730,000 $.4207-- $.4350 $0.4229
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
Estimated market prices and weighted average contract prices are in dollars per
gallon.
THE YEAR 2000
Chesapeake has not experienced any problems related to the year 2000 date
rollover or the year 2000 leap year issue; however, all date related problems
may not yet have become apparent. While Chesapeake believes its efforts to date
have successfully addressed the potential problems, there can be no assurance
until the passage of time, that no future problems will occur, including date
related problems with respect to Chesapeake's third party business partners. The
costs incurred in addressing the year 2000 issues have been immaterial.
COMPETITION
Historically, the Company's natural gas operations have successfully competed
with other forms of energy such as electricity, oil and propane. The principal
competitive factors have been price, and to a lesser extent, accessibility. The
natural gas distributions operations have several large volume industrial
customers that have the capacity to use fuel oil as an alternative to natural
gas. When oil prices decline, these interruptible customers convert to oil to
satisfy their fuel requirements. Lower levels in interruptible sales occur when
oil prices 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;
22 Chesapeake Utilities Corporation
<PAGE> 25
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. As a result of the Company's transmission
segment's conversion to open access, the Company has shifted from providing
competitive sales service to providing transportation and contract storage
services.
The Company's natural gas distribution operations located in Maryland and
Delaware began offering transportation services to certain industrial customers
during 1998 and 1997, respectively. With transportation services now available
on the Company's distribution systems, the Company is competing with third party
suppliers to sell gas to industrial customers. The distribution operations 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 operations. In
certain situations, the distribution operations may adjust services and rates
for these customers to retain their business. The Company expects to expand the
availability of transportation services to additional distribution 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.
The propane distribution operation competes with several other propane
distributors in its service territories, primarily on the basis of service and
price. Changes are occurring rapidly in the advanced information services
segment, which could adversely affect the markets for the Company's services. In
addition, 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.
INFLATION
Inflation affects the cost of labor, products and services required for
operation, maintenance and capital improvements. While the impact of inflation
has lessened in recent years, natural gas and propane prices are subject to
rapid fluctuations. Fluctuations in natural gas prices are passed on to
customers through the gas cost recovery mechanism in the Company's tariffs. To
help cope with the effects of inflation on its capital investments and returns,
the Company seeks rate relief from regulatory commissions for regulated
operations while monitoring the returns of its unregulated business operations.
To compensate for fluctuations in propane gas prices, Chesapeake adjusts its
propane selling prices to the extent allowed by the market.
CAUTIONARY STATEMENT
Chesapeake has made statements in this report that are considered to be
forward-looking statements. These statements are not matters of historical fact.
Sometimes they contain words such as "believes," "expects," "intends," "plans,"
"will," or "may," and other similar words. These statements relate to such
topics as customer growth, increases in revenues or margins, regulatory
approvals, market risk associated with the Company's 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 temperature sensitivity of the natural gas and propane
businesses;
- the wholesale price of propane and market movements in these
prices;
- the effects of competition on both unregulated and regulated
businesses;
- the effect of changes in federal, state or local legislative
requirements;
- the ability of the Company's new and planned facilities to
generate expected revenues; and
- the Company's ability to obtain the rate relief requested from
utility regulators and the timing of that rate relief.
Chesapeake Utilities Corporation 23
<PAGE> 26
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 accompanying
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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States. 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. The financial statements and the financial statement schedule are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements and financial statement schedule based
on our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States 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.
/s/ PricewaterhouseCoopers LLP
- --------------------------------
PRICEWATERHOUSECOOPERS LLP
Washington, D.C.
February 11, 2000
24 Chesapeake Utilities Corporation
<PAGE> 27
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES $230,863,123 $ 183,568,795 $ 222,489,264
COST OF SALES 176,731,255 136,226,618 175,377,647
- -------------------------------------------------------------------------------------------------------------
GROSS MARGIN 54,131,868 47,342,177 47,111,617
- -------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations 26,460,042 23,462,709 23,500,217
Maintenance 1,858,861 2,123,456 2,068,114
Depreciation and amortization 6,721,661 6,109,202 5,475,417
Other taxes 4,248,900 4,024,129 3,974,097
Income taxes 4,173,670 3,181,599 3,427,308
--------------------------------------------------------------------------------------------------------
Total operating expenses 43,463,134 38,901,095 38,445,153
--------------------------------------------------------------------------------------------------------
OPERATING INCOME 10,668,734 8,441,082 8,666,464
- -------------------------------------------------------------------------------------------------------------
OTHER INCOME
Gain on sale of investment 1,415,343 - -
Interest income 99,753 188,394 288,339
Other income, net 63,930 97,005 533,704
Income taxes (510,577) (44,145) (276,888)
--------------------------------------------------------------------------------------------------------
Total other income 1,068,449 241,254 545,155
--------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES 11,737,183 8,682,336 9,211,619
- -------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 2,793,712 2,966,043 2,387,641
Interest on short-term borrowing 551,937 254,033 764,536
Amortization of debt expense 117,966 123,335 119,401
Other 2,582 36,339 72,429
--------------------------------------------------------------------------------------------------------
Total interest charges 3,466,197 3,379,750 3,344,007
--------------------------------------------------------------------------------------------------------
NET INCOME $ 8,270,986 $ 5,302,586 $ 5,867,612
- -------------------------------------------------------------------------------------------------------------
EARNINGS PER SHARE OF COMMON STOCK:
BASIC $ 1.61 $ 1.05 $ 1.18
DILUTED $ 1.57 $ 1.04 $ 1.16
</TABLE>
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET INCOME $ 8,270,986 $ 5,302,586 $ 5,867,612
UNREALIZED GAIN ON MARKETABLE SECURITIES,
NET OF INCOME TAXES - 566,472 258,274
- -------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 8,270,986 $ 5,869,058 $ 6,125,886
- -------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes
Chesapeake Utilities Corporation 25
<PAGE> 28
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
PROPERTY, PLANT AND EQUIPMENT
<S> <C> <C>
Natural gas distribution and transmission $ 132,929,885 $ 117,232,506
Propane distribution and marketing 28,679,766 27,287,807
Advanced information services 1,460,411 1,087,910
Other plant 9,017,458 7,382,965
- ---------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment 172,087,520 152,991,188
Less: Accumulated depreciation and amortization (54,424,105) (48,725,412)
- ---------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment 117,663,415 104,265,776
- ---------------------------------------------------------------------------------------------------------------------
INVESTMENTS, AT FAIR MARKET VALUE 595,644 4,165,194
- ---------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 2,357,173 2,598,084
Accounts receivable (less allowance for uncollectibles of
$475,592 and $302,513 in 1999 and 1998, respectively) 21,699,128 14,861,255
Materials and supplies, at average cost 2,407,214 1,728,513
Propane inventory, at average cost 2,754,401 1,787,038
Storage gas prepayments 2,211,084 2,152,605
Underrecovered purchased gas costs 1,236,914 1,552,265
Income taxes receivable 76,628 344,311
Deferred income taxes 727,799 -
Prepaid expenses 1,499,910 1,596,595
- ---------------------------------------------------------------------------------------------------------------------
Total current assets 34,970,251 26,620,666
- ---------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Environmental regulatory assets 2,340,000 2,700,000
Environmental expenditures 3,574,888 3,418,166
Other deferred charges and intangible assets 7,823,597 4,063,811
- ---------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 13,738,485 10,181,977
- ---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 166,967,795 $ 145,233,613
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes
26 Chesapeake Utilities Corporation
<PAGE> 29
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Capitalization
Stockholders' equity
Common stock $ 2,524,018 $ 2,479,019
Additional paid-in capital 25,782,824 24,192,188
Retained earnings 31,857,732 28,892,384
Unearned compensation related to restricted stock award - (71,041)
Accumulated other comprehensive income - 863,344
- ---------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 60,164,574 56,355,894
Long-term debt, net of current maturities 33,776,909 37,597,000
- ---------------------------------------------------------------------------------------------------------------------
Total capitalization 93,941,483 93,952,894
- ---------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current maturities of long-term debt 2,665,091 520,000
Short-term borrowing 23,000,000 11,600,000
Accounts payable 16,849,061 11,070,642
Refunds payable to customers 779,508 636,153
Accrued interest 581,649 553,444
Dividends payable 1,347,784 1,273,446
Deferred income taxes - 56,100
Other accrued liabilities 4,626,785 3,754,231
- ---------------------------------------------------------------------------------------------------------------------
Total current liabilities 49,849,878 29,464,016
- ---------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 13,877,284 13,260,282
Deferred investment tax credits 711,987 766,802
Environmental liability 2,340,000 2,700,000
Accrued pension costs 1,544,963 1,536,304
Other liabilities 4,702,200 3,553,315
- ---------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 23,176,434 21,816,703
- ---------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
(NOTES L AND M)
TOTAL CAPITALIZATION AND LIABILITIES $ 166,967,795 $ 145,233,613
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes
Chesapeake Utilities Corporation 27
<PAGE> 30
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
<S> <C> <C> <C>
Net Income $ 8,270,986 $ 5,302,586 $ 5,867,612
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization 7,509,841 6,864,063 6,168,777
Investment tax credit adjustments (54,815) (54,815) (54,815)
Deferred income taxes, net 385,104 1,711,510 1,437,206
Mark-to-market adjustments 65,076 (242,757) 1,144,966
Employee benefits 8,659 (801,898) (238,826)
Employee compensation from lapsing of stock restrictions 71,041 119,845 173,643
Other, net 212,711 (171,619) (286,147)
Changes in assets and liabilities:
Accounts receivable, net (6,902,950) 1,797,425 10,914,969
Other current assets (1,607,857) 630,202 1,368,006
Other deferred charges 1,205,748 215,119 (623,138)
Accounts payable, net 5,778,418 (5,327,048) (12,525,992)
Refunds payable to customers 143,356 279,112 3,307
Overrecovered purchased gas costs 315,351 121,123 518,781
Other current liabilities 1,196,643 584,559 (2,193,548)
- --------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 16,597,312 11,027,407 11,674,801
- --------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant and equipment expenditures, net (25,128,670) (12,021,735) (12,370,932)
Sale (purchase) of investments 2,189,312 (500,000) (36,167)
- --------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (22,939,358) (12,521,735) (12,407,099)
- --------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Common stock dividends, net of amounts reinvested of $456,962,
$421,382 and $385,605 in 1999, 1998 and 1997, respectively (4,774,338) (4,340,687) (3,846,264)
Issuance of stock - Dividend Reinvestment Plan optional cash 187,369 188,564 167,337
Issuance of stock - Retirement Savings Plan 816,306 466,759 404,297
Net borrowing (repayment) under line of credit agreements 11,400,000 3,999,990 (5,134,990)
Proceeds from issuance of long-term debt - - 9,929,711
Repayment of long-term debt (1,528,202) (1,051,390) (3,098,455)
- --------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 6,101,135 (736,764) (1,578,364)
- --------------------------------------------------------------------------------------------------------------------
NET DECREASE)IN CASH AND CASH EQUIVALENTS (240,911) (2,231,092) (2,310,662)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 2,598,084 4,829,176 7,139,838
- --------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 2,357,173 $ 2,598,084 $ 4,829,176
- --------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest $ 3,409,070 $ 3,490,993 $ 3,243,981
Cash paid for income tax $ 4,413,155 $ 2,670,580 $ 3,500,160
</TABLE>
See accompanying notes
28 Chesapeake Utilities Corporation
<PAGE> 31
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------
Common Stock
<S> <C> <C> <C>
Balance - beginning of year $ 2,479,019 $ 2,435,142 $ 2,403,978
Dividend Reinvestment Plan 17,530 16,240 15,398
Retirement Savings Plan 22,489 12,663 11,305
Conversion of debentures 4,201 3,115 4,461
Performance shares 779 11,859 -
-----------------------------------------------------------------------------------------------------
Balance - end of year 2,524,018 2,479,019 2,435,142
-----------------------------------------------------------------------------------------------------
Additional Paid-in Capital
Balance - beginning of year 24,192,188 22,581,463 21,507,577
Dividend Reinvestment Plan 626,801 593,706 529,453
Retirement Savings Plan 793,817 454,096 392,992
Conversion of debentures 142,597 105,736 151,441
Performance shares 27,421 457,187 -
-----------------------------------------------------------------------------------------------------
Balance - end of year 25,782,824 24,192,188 22,581,463
-----------------------------------------------------------------------------------------------------
Retained Earnings
Balance - beginning of year 28,892,384 28,533,145 27,113,764
Net income 8,270,986 5,302,586 5,867,612
Cash dividends - Chesapeake (5,305,638) (4,943,347) (4,341,964)
Cash dividends - Pooled companies - - (106,267)
-----------------------------------------------------------------------------------------------------
Balance - end of year 31,857,732 28,892,384 28,533,145
-----------------------------------------------------------------------------------------------------
Unearned Compensation
Balance - beginning of year (71,041) (190,886) (364,529)
Amortization of prior years' awards 71,041 119,845 173,643
-----------------------------------------------------------------------------------------------------
Balance - end of year - (71,041) (190,886)
-----------------------------------------------------------------------------------------------------
Accumulated Other Comprehensive Income
Net of income tax expense of approximately $552,000 and
$190,000 in 1998 and 1997, respectively - 863,344 296,872
- ----------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $60,164,574 $ 56,355,894 $ 53,655,736
- ----------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes
Chesapeake Utilities Corporation 29
<PAGE> 32
CONSOLIDATED STATEMENTS OF INCOME TAXES
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------
Current Income Tax Expense
<S> <C> <C> <C>
Federal $ 3,948,746 $ 1,553,839 $ 2,076,235
State 807,214 307,654 442,563
Investment tax credit adjustments, net (54,815) (54,815) (54,815)
-------------------------------------------------------------------------------------------------------
Total current income tax expense 4,701,145 1,806,678 2,463,983
-------------------------------------------------------------------------------------------------------
Deferred Income Tax Expense (1)
Property, plant and equipment 734,765 887,175 1,335,802
Deferred gas costs (124,576) (111,416) (204,170)
Pensions and other employee benefits (153,697) 546,237 (19,508)
Unbilled revenue (45,290) (16,198) (104,632)
Contributions in aid of construction (160,971) (104,003) (33,028)
Environmental expenditures 97,480 415,845 249,417
Other (2) (364,609) (198,574) 16,332
-------------------------------------------------------------------------------------------------------
Total deferred income tax expense (16,898) 1,419,066 1,240,213
-------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 4,684,247 $ 3,225,744 $ 3,704,196
-------------------------------------------------------------------------------------------------------
Reconciliation of Effective Income Tax Rates
Federal income tax expense at 34% 4,404,779 $ 2,899,632 $ 3,254,412
State income taxes, net of federal benefit 553,444 363,041 399,213
Acquisition of subchapter S Corporation (3) - - 317,821
Other (2) (273,976) (36,929) (267,250)
-------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 4,684,247 $ 3,225,744 $ 3,704,196
-------------------------------------------------------------------------------------------------------
Effective income tax rate 36.2% 37.8% 38.7%
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------
At December 31, 1999 1998
- -------------------------------------------------------------------------------------------
<S> <C> <C>
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment $14,002,355 $ 13,222,141
Environmental costs 1,477,380 1,358,443
Deferred gas costs 439,146 546,391
Other 476,476 1,077,008
--------------------------------------------------------------------------------------
Total deferred income tax liabilities 16,395,357 16,203,983
--------------------------------------------------------------------------------------
Deferred income tax assets:
Unbilled revenue 1,053,863 984,510
Pension and other employee benefits 980,878 884,286
Self insurance 687,158 625,602
State operating loss carryforwards - 72,041
Other 523,973 321,162
--------------------------------------------------------------------------------------
Total deferred income tax assets 3,245,872 2,887,601
--------------------------------------------------------------------------------------
Deferred Income Taxes Per Consolidated Balance Sheet $13,149,485 $ 13,316,382
--------------------------------------------------------------------------------------
</TABLE>
(1) Includes $39,000, $156,000 and $208,000 of deferred state income taxes
for the years 1999, 1998 and 1997, respectively.
(2) 1999 includes a $238,000 tax benefit associated with the adjustment to
deferred income taxes for known tax exposures, offset by a $78,000
charge to adjust deferred income taxes to the 35% federal income tax
rate.
(3) Accounted for as a pooling of interests (see Note B to the Consolidated
Financial Statements).
See accompanying notes
30 Chesapeake Utilities Corporation
<PAGE> 33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF ACCOUNTING POLICIES
NATURE OF BUSINESS
Chesapeake Utilities Corporation (the "Company") is engaged in natural gas
distribution to approximately 39,000 customers located in central and southern
Delaware, Maryland's Eastern Shore and Florida. The Company's natural gas
transmission subsidiary operates a pipeline from various points in Pennsylvania
and northern Delaware to the Company's Delaware and Maryland distribution
divisions, as well as other utility and industrial customers in Delaware and the
Eastern Shore of Maryland. The Company's propane distribution and marketing
segment provides distribution service to approximately 35,300 customers in
central and 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, development tools and website development 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 all entities in which the Company
owns more than 20 percent but less than 50 percent, 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 their respective 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 in accordance with generally accepted
accounting principles which give appropriate recognition to the ratemaking and
accounting practices and policies of the various commissions. The propane
distribution and marketing and advanced information services segments are not
subject to regulation with respect to rates or maintenance of accounting
records.
PROPERTY, PLANT, EQUIPMENT AND DEPRECIATION
Utility property is stated at original cost while the assets of the propane
segment are recorded at cost. The costs of repairs and minor replacements are
charged to income as incurred and the costs of major renewals and betterments
are capitalized. Upon retirement or disposition of utility property, the
recorded cost of removal, net of salvage value, is charged to accumulated
depreciation. Upon retirement or disposition of non-utility property, the gain
or loss, net of salvage value, is charged to income. The provision for
depreciation is computed using the straight-line method at rates which will
amortize the unrecovered cost of depreciable property over the estimated useful
life. Depreciation and amortization expenses are provided at an annual rate for
each segment. Average rates for the past three years were 4 percent for natural
gas distribution and transmission, 5 percent for propane distribution and
marketing, 18 percent for advanced information services and 7 percent for
general plant.
CASH AND CASH EQUIVALENTS
The Company's policy is to invest cash in excess of operating requirements in
overnight income producing accounts. Such amounts are stated at cost, which
approximates market value. Investments with an original maturity of three months
or less are considered cash equivalents.
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.
Chesapeake Utilities Corporation 31
<PAGE> 34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OTHER DEFERRED CHARGES AND INTANGIBLE ASSETS
Other deferred charges include discount, premium and issuance costs associated
with long-term debt and rate case expenses. These 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 weighted average period of
fourteen years. Gross intangibles and the net unamortized balance at December
31, 1999 were $7.1 million and $5.6 million, respectively. Gross intangibles and
the net unamortized balance at December 31, 1998 were $2.8 and $1.6 million,
respectively.
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 have not been reflected in current service rates represent
income taxes recoverable through future rates. Investment tax credits on utility
property have been deferred and are allocated to income ratably over the lives
of the subject property.
FINANCIAL INSTRUMENTS
Xeron, the Company's propane marketing operation, engages in trading activities
using forward and futures contracts which have been accounted for using the
mark-to-market method of accounting. Under mark-to-market accounting, the
Company's trading contracts are recorded at fair value, net of future servicing
costs, and changes in market price are recognized as gains or losses in the
period of change. The resulting unrealized gains and losses are recorded as
assets or liabilities, respectively. At December 31, 1999 and 1998, the
unrealized gains were $142,000 and $207,000, respectively.
OPERATING REVENUES
Revenues for the natural gas distribution operations of the Company are based on
rates approved by the various public service commissions. 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 yet billed.
Chesapeake's natural gas distribution operations each have a gas cost recovery
mechanism that provides for the adjustment of rates charged to customers as gas
costs fluctuate. These amounts are collected or refunded through adjustments to
rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution's industrial
interruptible customers to make them competitive with alternative types of fuel.
Based on pricing, these customers can choose natural gas or alternative types of
supply. Neither the Company nor the customer is contractually obligated to
deliver or receive natural gas.
The natural gas transmission operation became an open access pipeline on
November 1, 1997 with revenues based on rates approved by FERC. Before open
access, only portions of the operation's revenues were based on FERC-approved
rates.
32 Chesapeake Utilities Corporation
<PAGE> 35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The propane distribution operation records revenues on either an "as delivered"
or a "metered" basis depending on the customer type. The 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.
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CALCULATION OF BASIC EARNINGS PER SHARE:
Net Income $8,270,986 $5,302,586 $5,867,612
Weighted Average Shares Outstanding 5,144,449 5,060,328 4,972,089
- ---------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 1.61 $ 1.05 $ 1.18
- ---------------------------------------------------------------------------------------------
CALCULATION OF DILUTED EARNINGS PER SHARE:
RECONCILIATION OF NUMERATOR:
Net Income-- basic $8,270,986 $5,302,586 $5,867,612
Effect of 8.25% Convertible debentures 188,982 193,666 204,070
- ---------------------------------------------------------------------------------------------
ADJUSTED NUMERATOR-- DILUTED $8,459,968 $5,496,252 $6,071,682
- ---------------------------------------------------------------------------------------------
RECONCILIATION OF DENOMINATOR:
Weighted Shares Outstanding-- basic 5,144,449 5,060,328 4,972,089
Effect of 8.25% Convertible debentures 220,732 226,203 238,357
Effect of stock options 11,875 12,245 38,462
- ---------------------------------------------------------------------------------------------
ADJUSTED DENOMINATOR-- DILUTED 5,377,056 5,298,776 5,248,908
- ---------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE $ 1.57 $ 1.04 $ 1.16
- ---------------------------------------------------------------------------------------------
</TABLE>
CERTAIN RISKS AND UNCERTAINTIES
The financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates in measuring
assets and liabilities and related revenues and expenses (see Notes L and M 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 its regulated operations, all such
deferred amounts would be recognized in the income statement at that time This
would result in a charge to earnings, net of applicable income taxes, which
could be material.
FASB STATEMENTS AND OTHER AUTHORITATIVE PRONOUNCEMENTS
In 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 2001, 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.
RESTATEMENT AND RECLASSIFICATION OF PRIOR YEARS' AMOUNTS
Certain prior years' amounts have been reclassified to conform to current year
presentation.
Chesapeake Utilities Corporation 33
<PAGE> 36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
B. BUSINESS COMBINATIONS
In November 1999, Chesapeake acquired EcoWater Systems of Michigan, Inc.,
operating as Douglas Water Conditioning ("Douglas"). Douglas is an EcoWater
dealership that has served the Detroit, Michigan area for 11 years. The
acquisition was accounted for as a purchase and the Company's financial results
include the results of operations of Douglas from the date of acquisition to
December 31, 1999, which were not material.
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 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, Chesapeake acquired Sam Shannahan Well Co., Inc., operating as
Tolan Water Service, in exchange for 25,000 shares of Chesapeake common stock.
Tolan provides water conditioning and treatment services and equipment to
residential, commercial and industrial customers on the Delmarva Peninsula. This
transaction was accounted for as a pooling of interests.
The 1998 acquisitions of Xeron, Inc. and Tolan Water Service required prior
periods Consolidated Financial Statements to be restated to include the combined
results of operations, financial position and cash flows. 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 each segment are regularly reviewed by the Company's
chief operating decision maker in order to make decisions about resources and to
assess performance. The following table presents information about the Company's
reportable segments.
34 Chesapeake Utilities Corporation
<PAGE> 37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
For the Years Ended December 31, 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues, Unaffiliated Customers
Natural gas distribution and transmission $ 75,395,245 $ 68,583,445 $ 88,105,336
Propane distribution and marketing 139,304,246 102,872,909 125,159,336
Advanced information services 13,531,261 10,330,703 7,636,407
Other 2,632,371 1,781,738 1,588,185
- ---------------------------------------------------------------------------------------------------------
Total operating revenues, unaffiliated customers $230,863,123 $183,568,795 $222,489,264
- ---------------------------------------------------------------------------------------------------------
Intersegment Revenues (1)
Natural gas distribution and transmission $ 45,730 $ 40,253 $ 17,830
Propane distribution and marketing -- -- 52,230
Advanced information services -- -- 149,602
Other 650,985 634,032 523,007
- ---------------------------------------------------------------------------------------------------------
Total intersegment revenues $ 696,715 $ 674,285 $ 742,669
- ---------------------------------------------------------------------------------------------------------
Operating Income Before Income Taxes
Natural gas distribution and transmission $ 10,300,455 $ 8,814,125 $ 9,219,619
Propane distribution and marketing 2,627,123 971,215 1,157,543
Advanced information services 1,469,958 1,316,158 1,045,912
Other 404,491 461,174 637,971
- ---------------------------------------------------------------------------------------------------------
Total 14,802,027 11,562,672 12,061,045
Eliminations 40,377 60,009 32,727
- ---------------------------------------------------------------------------------------------------------
Total operating income before income taxes $ 14,842,404 $ 11,622,681 $ 12,093,772
- ---------------------------------------------------------------------------------------------------------
Depreciation and Amortization
Natural gas distribution and transmission $ 4,762,285 $ 4,381,338 $ 3,968,912
Propane distribution and marketing 1,399,685 1,334,414 1,214,918
Advanced information services 268,082 183,553 122,081
Other 291,609 209,897 169,506
- ---------------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 6,721,661 $ 6,109,202 $ 5,475,417
- ---------------------------------------------------------------------------------------------------------
Capital Expenditures
Natural gas distribution and transmission $ 17,853,885 $ 10,018,491 $ 9,528,884
Propane distribution and marketing 2,168,269 1,544,992 2,820,166
Advanced information services 372,501 246,153 273,351
Other 5,522,615 840,186 848,680
- ---------------------------------------------------------------------------------------------------------
Total capital expenditures $ 25,917,270 $ 12,649,822 $ 13,471,081
- ---------------------------------------------------------------------------------------------------------
Identifiable Assets, at December 31,
Natural gas distribution and transmission $117,024,633 $102,618,587 $103,514,152
Propane distribution and marketing 31,888,633 27,526,019 31,831,616
Advanced information services 2,585,865 2,304,609 1,751,192
Other 15,468,664 12,784,398 8,621,863
- ---------------------------------------------------------------------------------------------------------
Total identifiable assets $166,967,795 $145,233,613 $145,718,823
- ---------------------------------------------------------------------------------------------------------
</TABLE>
(1) All significant intersegment revenues have been eliminated from consolidated
revenues.
Chesapeake Utilities Corporation 35
<PAGE> 38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
D. FAIR VALUE OF FINANCIAL INSTRUMENTS
Various items within the balance sheet are considered to be financial
instruments because they are cash or are to be settled in cash. The carrying
values of these items generally approximate their fair value (see Note E to the
Consolidated Financial Statements for disclosure of fair value of investments).
The Company's open forward and futures contracts at December 31, 1999 and
December 31, 1998 had a fair value of $142,000 and $207,000, respectively based
on market rates. The fair value of the Company's long-term debt is estimated
using a discounted cash flow methodology. The Company's long-term debt at
December 31, 1999, including current maturities, had an estimated fair value of
$36.3 million as compared to a carrying value of $36.4 million. At December 31,
1998, the estimated fair value was approximately $41.6 million as compared to a
carrying value of $38.1 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, 1999 consists primarily of a Rabbi Trust
associated with the acquisition of Xeron, Inc. The Company has classified this
investment as a trading security, which requires all gains and losses to be
recorded into earnings.
In November 1999, Chesapeake finalized the sale of its investment in Florida
Public Utilities Company ("FPU") for $16.50 per share. Chesapeake recognized a
gain on the sale of $1,415,000 pre-tax or $863,000 after-tax. The Company had a
7.3 percent ownership interest in the common stock of FPU which had been
classified as an available for sale security. This classification required 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, the market value had exceeded the aggregate cost basis of the Company's
portfolio by $1,552,000 pre-tax and $487,000 after-tax, respectively.
F. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL
The following is a schedule of changes in the Company's shares of common stock.
<TABLE>
<CAPTION>
For the Years Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common Stock: Shares issued and outstanding (1)
Balance-- beginning of year 5,093,788 5,004,078 4,939,515
Dividend Reinvestment Plan (2) 36,319 32,925 32,169
Sale of stock to the Company's Retirement Savings Plan 46,208 26,018 23,228
Conversion of debentures 8,631 6,401 9,166
Performance shares 1,600 24,366 --
- ------------------------------------------------------------------------------------------------------
Balance-- end of year 5,186,546 5,093,788 5,004,078
- ------------------------------------------------------------------------------------------------------
</TABLE>
(1) 12,000,000 shares are authorized at a par value of $.4867 per share.
(2) Includes dividends and reinvested optional cash payments.
36 Chesapeake Utilities Corporation
<PAGE> 39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
G. LONG-TERM DEBT
The outstanding long-term debt, net of current maturities, is as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31, 1999 1998
- --------------------------------------------------------------------------------
<S> <C> <C>
First mortgage sinking fund bonds:
9.37% Series I, due December 15, 2004 $ 3,024,000 $ 3,780,000
Uncollateralized senior notes:
7.97% note, due February 1, 2008 8,000,000 10,000,000
6.91% note, due October 1, 2010 9,090,909 10,000,000
6.85% note, due January 1, 2012 10,000,000 10,000,000
Convertible debentures:
8.25% due March 1, 2014 3,662,000 3,817,000
- --------------------------------------------------------------------------------
Total long-term debt $33,776,909 $37,597,000
- --------------------------------------------------------------------------------
</TABLE>
Annual maturities of consolidated long-term debt for the next five years are as
follows: $2,665,091 for the years 2000 through 2002, and $3,665,091 thereafter.
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 1999, debentures totaling $147,000 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 percent 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, 1999, the amounts available for future
dividends permitted by the Series I covenant approximated $17.6 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 BORROWINGS
The Board of Directors has authorized the Company to borrow up to $35.0 million
from various banks and trust companies. As of December 31, 1999, the Company had
four unsecured bank lines of credit totaling $36.0 million, none of which
required compensating balances. Under these lines of credit, the Company had
short-term debt outstanding of $23.0 million and $11.6 million at December 31,
1999 and 1998, respectively, with weighted average interest rates of 5.51
percent and 5.56 percent, respectively.
I. LEASE OBLIGATIONS
The Company has entered several operating lease arrangements for office space at
various locations and pipeline facilities. Rent expense related to these leases
was $357,000, $309,000 and $343,000 for 1999, 1998 and 1997, respectively.
Future minimum payments under the Company's current lease agreements are
$511,000, $468,000, $390,000, $340,000 and $314,000 for the years of 2000
through 2004, respectively; and $692,000 thereafter, totaling $2.7 million.
J. EMPLOYEE BENEFIT PLANS
PENSION PLAN
In December 1998, the Company restructured the employee benefit plans to be
competitive with those in similar industries. Chesapeake offered existing
participants of the defined benefit plan the option to remain in the existing
plan
Chesapeake Utilities Corporation 37
<PAGE> 40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 its accrued pension liability to $1,283,088. As a result of the
change in the accrued liability, the Company recorded a curtailment gain of
$1,224,298 in 1998. Benefits under the plan are based on each participant's
years of service and highest average compensation. The Company's funding policy
provides that payments to the trustee shall be equal to the minimum funding
requirements of the Employee Retirement Income Security Act of 1974.
The following schedule sets forth the funded status of the pension plan at
December 31, 1999 and 1998:
<TABLE>
<CAPTION>
At December 31, 1999 1998
- --------------------------------------------------------------------------------------
<S> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 12,187,885 $ 11,534,355
Service cost 400,921 838,177
Interest cost 688,198 803,727
Effect of curtailment (16,369) (1,224,298)
Change in discount rate (896,201) 952,552
Actuarial loss (gain) 263,562 (384,492)
Benefits paid (1) (4,386,001) (332,136)
- --------------------------------------------------------------------------------------
Benefit obligation at end of year 8,241,995 12,187,885
- --------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year 14,585,169 13,592,699
Actual return on plan assets (13,774) 1,324,606
Benefits paid (1) (4,386,001) (332,136)
- --------------------------------------------------------------------------------------
Fair value of plan assets at end of year 10,185,394 14,585,169
- --------------------------------------------------------------------------------------
Funded Status 1,943,399 2,397,284
Unrecognized transition obligation (96,267) (111,371)
Unrecognized prior service cost (62,453) (67,152)
Unrecognized net gain (2,956,318) (3,501,849)
- --------------------------------------------------------------------------------------
Accrued pension cost $ (1,171,639) $ (1,283,088)
- --------------------------------------------------------------------------------------
Assumptions:
Discount rate 7.50% 6.75%
Rate of compensation increase 4.75% 4.75%
Expected return on plan assets 8.50% 8.50%
- --------------------------------------------------------------------------------------
</TABLE>
(1) Benefits paid in 1999 include $4 million in one-time payments related to the
restructuring of the pension plan.
Net periodic pension costs for the defined pension benefit plan for 1999, 1998
and 1997 include the following components:
<TABLE>
<CAPTION>
For the Years Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Components of net periodic pension cost:
Service cost $ 400,921 $ 838,177 $ 680,192
Interest cost 688,198 803,727 732,188
Expected return on assets (1,046,254) (1,149,754) (898,037)
Amortization of:
Transition assets (15,104) (15,104) (15,104)
Prior service cost (4,699) (4,699) (4,699)
Actuarial gain (118,142) (143,622) (88,900)
- ------------------------------------------------------------------------------------------------
Net periodic pension (benefit) cost (95,080) 328,725 405,640
Curtailment gain -- (1,224,298) --
- ------------------------------------------------------------------------------------------------
Total pension (benefit) cost accruals $ (95,080) $ (895,573) $ 405,640
- ------------------------------------------------------------------------------------------------
</TABLE>
38 Chesapeake Utilities Corporation
<PAGE> 41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RETIREMENT SAVINGS PLAN
The Company sponsors a 401(k) Retirement Savings Plan, which provides
participants a mechanism for making contributions for retirement savings. Each
participant may make pre-tax contributions of up to 15 percent of eligible base
compensation, subject to IRS limitations. For participants still covered by the
defined benefit pension plan, the Company makes a contribution matching 60
percent or 100 percent of each participant's pre-tax contributions based on the
participant's years of service, not to exceed 6 percent of the participant's
eligible compensation for the plan year.
Effective January 1, 1999, the Company began offering an enhanced 401(k) plan to
all new employees, as well as existing employees that elected to no longer
participate in the defined benefit plan. The Company makes matching
contributions on a basis of up to 6 percent of each employee's pre-tax
compensation for the year. The match is between 100 percent and 200 percent,
based on a combination of the employee's age and years of service. The first 100
percent of the funds is matched with Chesapeake common stock. The remaining
match is invested in the Company's 401(k) plan according to each employee's
election options.
Effective, January 1, 1999 the Company offers a non-qualified supplemental
employee retirement savings plan open to Company executives over a specific
income threshold. Each participant receives a cash only matching contribution
percentage equivalent to their 401(k) match level. All contributions and matched
funds earn interest income monthly. This Plan is not funded externally.
The Company's contributions to the 401(k) plans totaled $1,066,000, $495,000 and
$404,000 for the years ended December 31, 1999, 1998 and 1997, respectively. As
of December 31, 1999, there are 84,148 shares reserved to fund future
contributions to the Retirement Savings Plan.
OTHER POST-RETIREMENT BENEFITS
The Company sponsors a defined benefit post-retirement health care and life
insurance plan that covers substantially all natural gas and corporate
employees. 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 $25,028 at December 31, 1999.
Net periodic post-retirement costs for 1999, 1998 and 1997 include the following
components:
<TABLE>
<CAPTION>
For the Years Ended December 31, 1999 1998 1997
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Components of net periodic post-retirement cost:
Service cost $ 3,322 $ 3,361 $ 3,287
Interest cost 55,023 59,321 60,221
Amortization of:
Transition obligation 27,859 27,859 27,859
Actuarial loss 3,130 6,071 1,554
- ---------------------------------------------------------------------------------------------
Net periodic post-retirement cost 89,334 96,612 92,921
Amounts amortized 25,254 25,254 25,254
- ---------------------------------------------------------------------------------------------
Total post-retirement cost accruals $114,588 $121,866 $118,175
- ---------------------------------------------------------------------------------------------
</TABLE>
Chesapeake Utilities Corporation 39
<PAGE> 42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following schedule sets forth the funded status of the post-retirement
health care and life insurance plan:
<TABLE>
<CAPTION>
At December 31, 1999 1998
- ------------------------------------------------------------------------------
<S> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 887,060 $ 868,899
Retirees (19,169) 14,236
Fully-eligible active employees (59,211) 674
Other active (20,148) 3,251
- ------------------------------------------------------------------------------
Benefit obligation at end of year $ 788,532 $ 887,060
- ------------------------------------------------------------------------------
Funded Status $(788,532) $(887,060)
Unrecognized transition obligation 189,436 217,295
Unrecognized net loss 23,329 165,160
- ------------------------------------------------------------------------------
Accrued post-retirement cost $(575,767) $(504,605)
- ------------------------------------------------------------------------------
Assumptions:
Discount rate 7.50% 6.75%
- ------------------------------------------------------------------------------
</TABLE>
The health care inflation rate for 1999 is assumed to be 8.5 percent. This rate
is projected to gradually decrease to an ultimate rate of 5 percent by the year
2008. 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 $97,327 as of January 1, 2000, and would increase the aggregate
of the service cost and interest cost components of the net periodic
post-retirement benefit cost for 2000 by approximately $7,474.
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 compensation expense of $131,000 and $49,000 associated with
these performance shares in 1999 and 1998, respectively.
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 to recognize the
compensation expense associated with these performance shares in 1997.
Chesapeake Utilities Corporation 40
<PAGE> 43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in outstanding options were as follows:
<TABLE>
<CAPTION>
1999 1998 1997
Number Option Number Option Number Option
of shares Price of shares Price of shares Price
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance-- beginning of year 163,637 $12.75-- $20.50 208,543 $12.625-- $20.50 113,051 $12.625-- $12.75
Options granted 95,492 $20.50
Options expired (44,906) $12.625
- -------------------------------------------------------------------------------------------------------------------------------
Balance-- end of year 163,637 $12.75-- $20.50 163,637 $12.75-- $20.50 208,543 $12.625-- $20.50
- -------------------------------------------------------------------------------------------------------------------------------
Exercisable 85,735 $12.75-- $20.50 68,145 $12.75 98,083 $12.625-- $12.75
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
In December 1997, the Company granted stock options to certain executive
officers of the Company. As required by Statement of Financial Accounting
Standards 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.
<TABLE>
<CAPTION>
For the Years Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Pro forma Net Income $ 8,230,868 $ 5,262,468 $ 5,864,269
Pro forma Earnings Per Share:
Basic $ 1.60 $ 1.04 $ 1.18
Diluted $ 1.57 $ 1.03 $ 1.16
Assumptions:
Dividend yield 4.73% 4.73% 4.73%
Expected volatility 15.53% 15.53% 15.53%
Risk-free interest rate 5.89% 5.89% 5.89%
Expected lives 4 years 4 years 4 years
- ----------------------------------------------------------------------------------------------
</TABLE>
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 1999, the Company completed the first phase of the soil remediation
process at that site at a cost of $550,000. Over the next twelve to eighteen
months, the Company expects to complete the remaining phases of 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
for 30 years for natural attenuation; to a high of $3.3 million in capital and
$1.0 million per year in operating costs to operate a pump-and-treat /
ground-water containment system. The pump-and-treat / ground-water containment
system is intended to contain the manufactured gas plant ("MGP") contaminants to
allow the ground-water outside of the containment area to naturally attenuate.
The operating cost estimate for the pump-and-treat containment system is
dependent upon the actual ground-water quality and flow conditions at the site.
The EPA has also requested that the Company submit a design for a pump-and-treat
/ ground-water containment system that is estimated to cost $2.8 million in
capital and $600,000 per year in operating costs. The EPA has requested that the
design be submitted in enough time to allow the EPA to approve it by July 14,
Chesapeake Utilities Corporation 41
<PAGE> 44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2000. The Company continues to believe that a ground-water pump-and-treat system
is not necessary for the MGP contaminants, that there is insufficient
information to design an overall ground-water containment program and that
natural attenuation is the appropriate remedial action for the MGP wastes.
Chesapeake cannot predict the ground-water remediation that the EPA will
require; therefore, the Company has accrued $2.1 million at December 31, 1999
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 remediation. 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"), the
Company is engaged in remediation procedures at the Salisbury site. In addition,
the Company reports the remediation and monitoring results to the MDE. The
Company has established a liability with respect to the Salisbury site of
$240,000 as of December 31, 1999. This amount is based on the estimated
operating costs of the remediation facilities for over the next two years and
capital costs to shut down the remediation procedures in 2001. A corresponding
regulatory asset has been recorded, reflecting the Company's belief that costs
incurred will be recoverable in base rates.
The third site is located in the state of Florida and is currently being
evaluated. At this time, no estimate of liability can be made. The Company
continues to collect proceeds from our Florida ratepayers to fund future
expenditures. At December 31, 1999, the Company has collected $505,000 in excess
of costs incurred.
It is management's opinion that any unrecovered current costs and any other
future costs associated with any of the three sites incurred will be recoverable
through future rates or sharing arrangements with other responsible parties.
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.
42 Chesapeake Utilities Corporation
<PAGE> 45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
For the Quarters Ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1999
Operating Revenue $ 55,644,264 $ 46,842,724 $ 56,525,775 $ 71,850,360
Operating Income 5,756,996 1,542,298 22,293 3,347,147
Net Income (1) 4,942,983 796,103 (784,981) 3,316,881
Earnings per share:
Basic $ 0.97 $ 0.16 $ (0.15) $ 0.64
Diluted $ 0.93 $ 0.16 $ (0.15) $ 0.62
- ---------------------------------------------------------------------------------------------------------------------
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 (2) 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
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Results for the fourth quarter of 1999 reflect a gain on the sale of
investments of $863,000, net of income tax expense. See Note E to the
Consolidated Financial Statements.
(2) Results for the fourth quarter of 1998 reflect a pension plan
curtailment gain of approximately $750,000, net of income tax expense.
See Note J to the Consolidated Financial Statements.
Chesapeake Utilities Corporation 43
<PAGE> 46
OPERATING STATISTICS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenues (in thousands)
Natural gas
Residential $ 19,969 $ 19,274 $ 21,540 $ 18,256 $ 14,857
Commercial 15,241 15,243 16,557 14,339 11,383
Industrial 19,109 15,953 22,625 28,546 36,898
Sale for resale 11,736 11,683 23,010 24,481 12,459
Transportation 8,454 6,120 4,212 3,369 2,993
Other 886 310 161 1,102 515
--------------------------------------------------------------------------------------------------------------
Total natural gas revenues 75,395 68,583 88,105 90,093 79,105
Propane distribution and marketing 139,304 102,873 125,159 161,812 147,596
Other 16,164 12,113 9,225 8,197 8,584
--------------------------------------------------------------------------------------------------------------
Total revenues $ 230,863 $ 183,569 $ 222,489 $ 260,102 $ 235,285
--------------------------------------------------------------------------------------------------------------
Volumes
Natural gas deliveries (in MMCF)
Residential 1,805 1,636 1,753 1,987 1,686
Commercial 2,023 1,907 2,113 2,059 1,792
Industrial 2,793 3,115 5,975 7,553 13,622
Sale for resale 1,461 1,194 1,200 1,065 990
Transportation 19,301 13,548 12,231 12,138 11,131
--------------------------------------------------------------------------------------------------------------
Total natural gas deliveries 27,383 21,400 23,272 24,802 29,221
--------------------------------------------------------------------------------------------------------------
Propane distribution (in thousands of gallons) 27,788 25,979 26,682 29,975 26,184
--------------------------------------------------------------------------------------------------------------
Customers
Natural gas
Residential 34,245 32,473 31,277 30,349 29,285
Commercial 4,527 4,416 4,288 4,151 4,030
Industrial (1) 254 236 229 210 212
Sale for resale (1) 3 3 3 3 3
--------------------------------------------------------------------------------------------------------------
Total natural gas customers 39,029 37,128 35,797 34,713 33,530
Propane distribution 35,267 34,113 33,123 31,961 31,115
--------------------------------------------------------------------------------------------------------------
Total customers 74,296 71,241 68,920 66,674 64,645
--------------------------------------------------------------------------------------------------------------
Other
Heating degree-days 4,082 3,704 4,430 4,717 4,594
Heating degree-days (10-year average) 4,444 4,579 4,596 4,586 4,564
--------------------------------------------------------------------------------------------------------------
</TABLE>
(1)Includes transportation customers.
[GRAPHS APPEARS HERE]
<TABLE>
<CAPTION>
Natural Gas and Propane Volumes Compared to Heating
Customer Growth Degree-Days
Natural Propane
Natural Gas Propane Gas (in thousands Heating
Year Customers Customers (in MMCF) of gallons) Degree-Days
- --------------------------------------- ------------------------------------------
<S> <C> <C> <C> <C> <C>
1995 33,530 31,115 29,221 26,184 4,594
1996 34,713 31,961 24,802 29,975 4,717
1997 35,797 33,123 23,272 26,682 4,430
1998 37,128 34,113 21,400 25,979 3,704
1999 39,029 35,267 27,383 27,788 4,082
</TABLE>
44 Chesapeake Utilities Corporation
<PAGE> 47
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", Section 16(a) Beneficial Ownership Reporting
Compliance" to be filed on or before May 1, 2000 in connection with the
Company's Annual Meeting to be held on May 16, 2000.
The information required by this item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Part I of this Form 10-K under "Executive Officers of the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
This information is incorporated herein by reference to the Proxy Statement,
under "Management Compensation Committee Interlocks and Insider Participation",
to be filed on or before May 1, 2000 in connection with the Company's Annual
Meeting to be held on May 16, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is incorporated herein by reference to the Proxy Statement,
under "Certain Transactions", dated and to be filed on or before May 1, 2000 in
connection with the Company's Annual Meeting to be held on May 16, 2000.
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, 2000 in connection with the Company's Annual Meeting to
be held on May 16, 2000.
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 11, 2000 of PricewaterhouseCoopers
LLP, Independent Accountants
- - Consolidated Statements of Income for each of the three years ended
December 31, 1999, 1998 and 1997
- - Consolidated Balance Sheets at December 31, 1999 and December 31, 1998
- - Consolidated Statements of Cash Flows for each of the three years ended
December 31, 1999, 1998 and 1997
- - Consolidated Statements of Common Stockholders' Equity for each of the
three years ended December 31, 1999, 1998 and 1997
- - Consolidated Statements of Income Taxes for each of the three years
ended December 31, 1999, 1998 and 1997
- - Notes to Consolidated Financial Statements
2. Financial Statement Schedules -- Schedule II - Valuation and Qualifying
Accounts
Chesapeake Utilities Corporation 45
<PAGE> 48
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.
<TABLE>
<CAPTION>
(c) EXHIBITS:
<S> <C>
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 August 20, 1999, are incorporated herein by
reference to Exhibit 3 of the Company's Registration Statement
on Form 8-A, File No. 001-11590, filed August 24, 1999.
Exhibit 4(a) Form of Indenture between the Company and Boatmen's Trust
Company, Trustee, with respect to the 8 1/4% Convertible
Debentures is incorporated herein by reference to Exhibit 4.2
of the Company's Registration Statement on Form S-2, Reg. No.
33-26582, filed on January 13, 1989.
Exhibit 4(b) 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) 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(d) 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
</TABLE>
46 Chesapeake Utilities Corporation
<PAGE> 49
<TABLE>
<S> <C>
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) Form of Performance Share Agreement dated January 1,
2000, pursuant to Chesapeake Utilities Corporation Performance
Incentive Plan by and between Chesapeake Utilities Corporation
and each of Ralph J. Adkins and John R. Schimkaitis, filed
herewith.
*Exhibit 10(l) 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(m) 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(n) 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 10(o) Form of Stock Option Agreement dated January 1, 2000, pursuant
to Chesapeake Utilities Corporation Performance Incentive Plan
by and between Chesapeake Utilities Corporation and each of
William C. Boyles, Philip S. Barefoot, Thomas A. Geoffroy,
James R. Schneider and William P. Schneider, filed herewith.
*Exhibit 10(p) 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 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.
</TABLE>
* Management contract or compensatory plan or agreement.
Chesapeake Utilities Corporation 47
<PAGE> 50
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, 2000
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.
<TABLE>
<S> <C>
/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, 2000 Date: March 16, 2000
/S/ MICHAEL P. MCMASTERS /S/ RICHARD BERNSTEIN
- ---------------------------- -------------------------------
Michael P. McMasters, Vice President, Richard Bernstein, Director
Chief Financial Officer and Treasurer Date: March 16, 2000
(Principal Financial and Accounting Officer)
Date: March 16, 2000
/S/ WALTER J. COLEMAN /S/ JOHN W. JARDINE, JR.
- ---------------------------- -------------------------------
Walter J. Coleman, Director John W. Jardine, Jr., Director
Date: March 16, 2000 Date: March 16, 2000
/S/ RUDOLPH M. PEINS, JR. /S/ ROBERT F. RIDER
- ---------------------------- -------------------------------
Rudolph M. Peins, Jr., Director Robert F. Rider, Director
Date: March 16, 2000 Date: March 16, 2000
/S/ JEREMIAH P. SHEA /S/ WILLIAM G. WARDEN, III
- ---------------------------- -------------------------------
Jeremiah P. Shea, Director William G. Warden, III, Director
Date: March 16, 2000 Date: March 16, 2000
</TABLE>
48 Chesapeake Utilities Corporation
<PAGE> 51
Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
Balance at Additions Balance at
---------------------------
Beginning Charged to Other End of
For the Year Ended December 31, of Year Income Accounts (1) Deductions (2) Year
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
1999 $ 302,513 $ 306,651 $ 74,877 $ (359,165) $ 324,876
..........................................................................................................................
1998 $ 331,775 $ 280,391 $ 57,759 $ (367,412) $ 302,513
..........................................................................................................................
1997 $ 392,412 $ 203,624 $ 68,038 $ (332,299) $ 331,775
..........................................................................................................................
</TABLE>
(1) Recoveries.
(2) Uncollectible accounts charged off.
Chesapeake Utilities Corporation 49
<PAGE> 1
EXHIBIT 10.1
PERFORMANCE SHARE AGREEMENT
PURSUANT TO THE
CHESAPEAKE UTILITIES CORPORATION
PERFORMANCE INCENTIVE PLAN
AGREEMENT dated as of January 1, 2000, and entered into, in duplicate, by
and between Chesapeake Utilities Corporation, a Delaware corporation (the
"Company"), and [Ralph J. Adkins / John R. Schimkaitis] (the "Grantee") who
resides at [address].
WITNESSETH that:
WHEREAS, the Chesapeake Utilities Corporation Performance Incentive Plan
(the "Plan") has been duly adopted by action of the Company's Board of Directors
(the "Board") as of January 1, 1992; and
WHEREAS, the Committee of the Board of Directors of the Company referred
to in the Plan (the "Committee") has determined that it is in the best interests
of the Company to grant the Performance Share Award described herein pursuant to
the Plan; and
WHEREAS, the shares of the Common Stock of the Company that are subject to
this Agreement, when added to the other shares of Common Stock that are subject
to awards granted under the Plan, do not exceed the total number of shares of
Common Stock with respect to which awards are authorized to be granted under the
Plan;
NOW, THEREFORE, it is hereby covenanted and agreed by and between the
Company and the Grantee as follows:
Section 1. Performance Share Award
The Company hereby grants to the Grantee a Performance Share Award for the
year ending December 31, 2000 (the "Award Year"). As more fully described
herein, the Grantee may earn a maximum total of [X,XXX] shares (the "Contingent
Performance Shares") upon the Company's achievement of the Performance Goals set
forth in Section 2. Alternatively, the Grantee may elect to receive [X,XXX]
shares (the "Forfeitable Performance Shares"), as detailed in Section 3, in lieu
of receiving any Contingent Performance Shares. The Forfeitable Performance
Shares shall be subject to forfeiture conditions, as set forth in Section 3(c).
Section 2. Contingent Performance Shares
(a) As soon as practicable after the Company's independent auditors have
certified the Company's financial statements for the Award Year, the Committee
shall determine for purposes of this Agreement the Company's (1) earnings growth
("EG"), (2) growth in non-regulated net income ("NRNI"), and (3) share price
relative to book value ("Price/Book Value") as of the end of the Award Year. The
EG, NRNI and Price/Book Value shall be determined by the Committee based on
financial results reported to shareholders in the Company's annual reports and
shall be subject to adjustment by the Committee for
<PAGE> 2
extraordinary events, including, but not limited to, temperature fluctuation
during the Award Year. The Committee shall promptly notify the Grantee of its
determination.
(b) The Grantee may earn up to [X,XXX] Contingent Performance Shares (the
"Maximum Award"), as follows:
(1) If the EG for the Award Year exceeds the median five-year
weighted average growth for companies included in the C.A. Turner database
(natural gas distribution companies and integrated natural gas distribution
companies), the Grantee may earn up to fifty percent (50%) of the Maximum Award,
as follows:
(i) If the EG is in the fourth quartile of companies in the
C.A. Turner database, the Grantee shall earn fifty
percent (50%) of the Maximum Award, or
(ii) If the EG falls between the median and the fourth
quartile, the Grantee shall earn a portion of the fifty
percent (50%) available under this paragraph that is
pro-rated to reflect the position of the Company's
earnings growth within the third quartile, or
(iii) If the EG is at or below the median, the Grantee shall
not earn any Contingent Performance Shares under this
paragraph (1);
(2) If the temperature-adjusted NRNI for the Award Year exceeds the
temperature-adjusted NRNI for the prior calendar year by fifteen percent (15%)
or more, the Grantee shall earn thirty percent (30%) of the Maximum Award. If
the temperature-adjusted NRNI for the Award Year does not exceed the
temperature-adjusted NRNI for the prior calendar year by at least fifteen
percent (15%), the Grantee shall not earn any Contingent Performance Shares
under this paragraph (2); and
(3) If the Price/Book Value for the Award Year is equal to or
greater than the average Price/Book Value for the Award Year of companies in the
third quartile of the C.A. Turner database (natural gas distribution companies
and integrated natural gas distribution companies), the Grantee shall earn
twenty percent (20%) of the Maximum Award. If the Price/Book Value for the Award
Year does not equal or exceed the average Price/Book Value for the Award Year of
companies in the third quartile of the C.A. Turner database, the Grantee shall
not earn any Contingent Performance Shares under this paragraph (3). If one or
more of the companies in the C.A. Turner database is at any time during the
Award Year the subject of an announced acquisition, its stock shall not be
considered for purposes of this paragraph (3).
(c) Contingent Performance Shares that are earned by the Grantee pursuant
to this Section 2 shall be issued promptly, without payment of consideration by
the Grantee. The Grantee shall have the right to vote the Contingent Performance
Shares and to receive the dividends distributable with respect to such shares on
and after, but not before, the date on which the Grantee is recorded on the
Company's ledger as holder of record of the Contingent Performance Shares (the
"Issue Date"). If, however, the Grantee receives shares of Common Stock as part
of any dividend or other distribution with respect to the Contingent Performance
Shares, such shares shall be treated as if they are Contingent Performance
Shares, and such shares shall be subject to all of the terms and conditions
imposed by this Section 2.
2
<PAGE> 3
(d) Sale, transfer, pledge, or hypothecation of the Contingent Performance
Shares shall be prohibited for a period of three (3) years after the Issue Date
(the "Limitation Period"), and the Performance Shares shall bear a restrictive
legend to that effect. Any attempt to dispose of Contingent Performance Shares
in contravention of this Agreement shall be ineffective. Upon expiration of the
Limitation Period, the transfer restrictions imposed by this Section shall
expire, and new certificates representing the Contingent Performance Shares,
without the restrictive legend described in this paragraph (d), shall be issued,
subject to the provisions of paragraph (e) of this Section 2.
(e) The Performance Shares will be not registered for resale under the
Securities Act of 1933 or the laws of any state except when and to the extent
determined by the Board pursuant to a resolution. Until a registration statement
is filed and becomes effective, however, transfer of the Contingent Performance
Shares after expiration of the Limitation Period shall require the availability
of an exemption from such registration, and prior to the issuance of new
certificates, the Company shall be entitled to take such measures as it deems
appropriate (including but not limited to obtaining from the Grantee an
investment representation letter and/or further legending the new certificates)
to ensure that the Contingent Performance Shares are not transferred in the
absence of such exemption.
(f) In the event of a Change in Control, as defined in the Plan, during
the Award Year, the Grantee shall earn at least the Maximum Award of Contingent
Performance Shares set forth in this Section 2, as if all employment and
performance criteria were satisfied, pro rated based on the proportion of the
Award Year that has expired as of the date of such Change in Control.
(g) If, during the Award Year, the Grantee is separated from employment,
Contingent Performance Shares shall be deemed earned or forfeited as follows:
(1) Upon voluntary termination by the Grantee (other than for
retirement at age 65 or as accepted by the Committee) or termination by the
Company for failure of job performance or other just cause as determined by the
Committee, all unearned Contingent Performance Shares shall be forfeited
immediately;
(2) If the Grantee separates from employment by reason of death or
total and permanent disability (as determined by the Committee), the number of
Contingent Performance Shares that would otherwise have been earned at the end
of the Award Year shall be reduced by pro rating such Contingent Performance
Shares based on the proportion of the Award Year during which the Grantee was
employed by the Company, unless the Committee determines that the Contingent
Performance Shares shall not be so reduced;
(3) Retirement of the Grantee at age 65 or as accepted by the
Committee shall not affect the Contingent Performance Shares, which shall
continue to be earned through the remainder of the Award Year, as set forth
above.
(h) The Grantee shall be solely responsible for any federal, state and
local income taxes imposed in connection with the delivery of Contingent
Performance Shares. Prior to the transfer of any Contingent Performance Shares
to the Grantee, the Grantee shall remit to the Company an amount sufficient to
satisfy any federal, state, local and other withholding tax requirements. The
Grantee may elect to have all or part of any withholding tax obligation
satisfied by having the Company withhold shares otherwise deliverable to the
Grantee as Contingent Performance Shares, unless the Committee determines
otherwise by resolution. If
3
<PAGE> 4
the Grantee fails to make such payments or election, the Company and its
subsidiaries shall, to the extent permitted by law, have the right to deduct
from any payments of any kind otherwise due to the Grantee any taxes required by
law to be withheld with respect to the Contingent Performance Shares.
Section 3. Forfeitable Performance Shares
(a) In lieu of earning Contingent Performance Shares, the Grantee may
elect to receive [X,XXX] Forfeitable Performance Shares, irrespective of whether
the Company meets any Performance Goals. The Grantee must make any such election
on or before September 30, 2000, and the election must be made in writing, in a
manner prescribed by the Committee. Once made, the election is irrevocable. If a
Grantee makes such an election, he shall not receive any Contingent Performance
Shares under this Agreement.
(b) Any Forfeitable Performance Shares received by the Grantee pursuant
to this Section 3 shall be issued as promptly as possible after December 31,
2000, without payment of consideration by the Grantee. The Grantee shall have
the right to vote the Forfeitable Performance Shares and to receive the
dividends distributable with respect to such shares on and after, but not
before, the date on which the Grantee is recorded on the Company's ledger as
holder of record of the Forfeitable Performance Shares (the "Issue Date"). If,
however, the Grantee receives shares of Common Stock as part of any dividend or
distribution with respect to the Forfeitable Performance Shares, such shares
shall be treated as if they are Forfeitable Performance Shares, and such shares
shall be subject to all of the terms and conditions imposed by this Section 3.
(c) The Forfeitable Performance Shares shall be subject to the following
restrictions:
(1) Sale, transfer, pledge or hypothecation of the Forfeitable
Performance Shares shall be prohibited for a period of three (3) years after the
Issue Date (the "Restriction Period"), and the certificates evidencing the
Forfeitable Performance Shares shall bear an appropriate restrictive legend that
refers to the terms, conditions, and restrictions set forth in this Agreement.
Any attempt to dispose of Forfeitable Performance Shares in contravention of
this Agreement shall be ineffective. Upon expiration of the Restriction Period,
the transfer restrictions imposed by this Section shall expire, and new
certificates representing the Forfeitable Performance Shares, without the
restrictive legend described in this paragraph (c)(1), shall be issued, subject
to the provisions of paragraph (f) of this Section 3.
(2) If, during the Restriction Period, the Grantee separates from
employment for any reason other than death, total and permanent disability (as
determined by the Committee), or involuntary termination without cause (as
determined by the Committee), all Forfeitable Performance Shares shall be
forfeited immediately.
(d) All restrictions under paragraph (c) of this Section 3 shall
immediately expire on the earliest of: (A) the Grantee's separation from
employment because of death, total and permanent disability (as determined by
the Committee), or involuntary termination without cause (as determined by the
Committee), (B) a Change in Control, as defined in the Plan, or (C) the end of
the Restriction Period.
(e) If, after the Grantee has made an election to receive Forfeitable
Performance Shares pursuant to Section 3(a), a Change in Control, as defined in
the Plan, occurs during the Award Year, the Grantee shall receive at least the
total number of Forfeitable Performance
4
<PAGE> 5
Shares due under this Agreement, pro rated based on the proportion of the Award
Year that has expired as of the date of such Change in Control. Pursuant to
Section 3(d), such Shares shall not be subject to any of the restrictions
imposed by this Section.
(f) The Forfeitable Performance Shares shall be not registered for resale
under the Securities Act of 1933 or the laws of any state except when and to the
extent determined by the Board pursuant to a resolution. Until a registration
statement is filed and becomes effective, however, transfer of the Forfeitable
Performance Shares after expiration of the Restriction Period shall require the
availability of an exemption from such registration, and prior to the issuance
of new certificates, the Company shall be entitled to take such measures as it
deems appropriate (including but not limited to obtaining from the Grantee an
investment representation letter and/or further legending the new certificates)
to ensure that the Forfeitable Performance Shares are not transferred in the
absence of such exemption.
(g) The Grantee shall be solely responsible for any federal, state and
local income taxes imposed in connection with receipt of the Forfeitable
Performance Shares:
(1) The Grantee agrees that, no later than the date that the
restrictions set forth in Section 3(c) lapse, he shall remit to the Company an
amount sufficient to satisfy any federal, state, local and other withholding tax
requirements.
(2) The Grantee may elect to have all or part of any withholding
tax obligation satisfied by having the Company withhold shares otherwise
deliverable to the Grantee in connection with the Award of Restricted Stock,
unless the Committee determines otherwise by resolution.
(3) If the Grantee properly elects, within 30 days of the Issue
Date, to include in gross income for federal income tax purposes an amount equal
to the fair market value of the Forfeitable Performance Shares, he shall make
arrangements satisfactory to the Committee to remit in the year of issue an
amount sufficient to satisfy any federal, state, local and other withholding tax
requirements with respect to such Forfeitable Performance Shares.
(4) If the Grantee fails to make satisfactory arrangements to meet
all withholding tax obligations, the Company and its subsidiaries shall, to the
extent permitted by law, have the right to deduct from any payments of any kind
otherwise due to the Grantee any taxes required by law to be withheld with
respect to the Forfeitable Performance Shares.
Section 4. Effect on Prior Agreements
Pursuant to an Agreement dated January 1, 1998, between the Company and
the Grantee (the "1998 Agreement"), awards may vest as of the end of each of
1998, 1999, and 2000. This Agreement hereby modifies the 1998 Agreement to
provide that no awards shall vest for years after December 31, 1999. This
Agreement does not affect the awards that vest as of the end of 1998 or 1999,
and the terms of the 1998 Agreement shall continue in effect with respect to
those awards.
Section 5. Additional Conditions to Issuance of Shares
Each transfer of Contingent Performance Shares or Forfeitable Performance
Shares (together, the "Award Shares") shall be subject to the condition that if
at any time the Committee shall determine, in its sole discretion, that it is
necessary or desirable as a condition
5
<PAGE> 6
of, or in connection with, transfer of Award Shares (i) to satisfy withholding
tax or other withholding liabilities, (ii) to effect the listing, registration
or qualification on any securities exchange or under any state or federal law of
any Shares deliverable in connection with such exercise, or (iii) to obtain the
consent or approval of any regulatory body, then in any such event such transfer
shall not be effective unless such withholding, listing, registration,
qualification, consent or approval shall have been effected or obtained free of
any conditions not acceptable to the Company.
Section 6. Adjustment of Shares
(a) If the Company shall become involved in a merger, consolidation or
other reorganization, whether or not the Company is the surviving corporation,
any right to earn Contingent Performance Shares or to elect to receive
Forfeitable Performance Shares shall be deemed a right to earn or to elect to
receive the consideration into which the shares of Common Stock represented by
the Contingent Performance Shares or by the Forfeitable Performance Shares would
have been converted under the terms of the merger, consolidation or other
reorganization. If the Company is not the surviving corporation, the surviving
corporation (the "Successor") shall succeed to the rights and obligations of the
Company under this Agreement.
(b) If any subdivision or combination of shares of Common Stock or any
stock dividend, capital reorganization or recapitalization occurs after the
adoption of the Plan, the Committee shall make such proportionate adjustments as
are appropriate to the number of Contingent Performance Shares to be earned
and/or to the number of Forfeitable Performance Shares to be received in order
to prevent the dilution or enlargement of the rights of the Grantee.
Section 7. No Right to Employment
Nothing contained in this Agreement shall be deemed by implication or
otherwise to confer upon the Grantee any right to continued employment by the
Company or any affiliate of the Company.
Section 8. Notice
Any notice to be given hereunder by the Grantee shall be sent by mail
addressed to Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover,
Delaware 19904, for the attention of the Committee, c/o the Secretary, and any
notice by the Company to the Grantee shall be sent by mail addressed to the
Grantee at the address of the Grantee shown on the first page hereof. Either
party may, by notice given to the other in accordance with the provisions of
this Section, change the address to which subsequent notices shall be sent.
Section 9. Assumption of Risk
It is expressly understood and agreed that the Grantee assumes all risks
incident to any change hereafter in the applicable laws or regulations or
incident to any change in the market value of the Award Shares.
6
<PAGE> 7
Section 10. Terms of Plan
This Agreement is entered into pursuant to the Plan (a copy of which has
been delivered to the Grantee). This Agreement is subject to all of the terms
and provisions of the Plan, which are incorporated into this Agreement by
reference, and the actions taken by the Committee pursuant to the Plan. In the
event of a conflict between this Agreement and the Plan, the provisions of the
Plan shall govern. All determinations by the Committee shall be in its sole
discretion and shall be binding on the Company and the Grantee.
Section 11. Governing Law; Amendment
This Agreement shall be governed by, and shall be construed and
administered in accordance with, the laws of the State of Delaware (without
regard to its choice of law rules) and the requirements of any applicable
federal law. This Agreement may be modified or amended only by a writing signed
by the parties hereto.
Section 12 Terms of Agreement
This Agreement shall remain in full force and effect and shall be binding
on the parties hereto for so long as any Award Shares issued to the Grantee
under this Agreement continue to be held by the Grantee.
IN WITNESS WHEREOF, the Company has caused this Agreement to be executed
in its corporate name, and the Grantee has executed the same in evidence of the
Grantee's acceptance hereof, upon the terms and conditions herein set forth, as
of the day and year first above written.
CHESAPEAKE UTILITIES CORPORATION
By: ___________________________________
___________________________________
Grantee
7
<PAGE> 1
EXHIBIT 10.2
STOCK APPRECIATION RIGHTS AGREEMENT
PURSUANT TO THE
CHESAPEAKE UTILITIES CORPORATION
PERFORMANCE INCENTIVE PLAN
AGREEMENT dated as of January 1, 2000, and entered into, in duplicate, by
and between Chesapeake Utilities Corporation, a Delaware corporation (the
"Company"), and [William C. Boyles / Philip S. Barefoot / Thomas A. Geoffroy /
James R. Schneider / William P. Schneider] (the "Grantee") who resides at
[address].
WITNESSETH that:
WHEREAS, the Chesapeake Utilities Corporation Performance Incentive Plan
(the "Plan") has been duly adopted by action of the Company's Board of Directors
(the "Board") as of January 1, 1992; and
WHEREAS, the Committee of the Board of Directors of the Company referred
to in the Plan (the "Committee") has determined that it is in the best interests
of the Company to grant the Stock Appreciation Rights Award described herein
pursuant to the Plan; and
WHEREAS, the shares of the Common Stock of the Company that are subject to
Stock Appreciation Rights under this Agreement, when added to the other shares
of Common Stock that are subject to awards granted under the Plan, do not exceed
the total number of shares of Common Stock with respect to which awards are
authorized to be granted under the Plan;
NOW, THEREFORE, it is hereby covenanted and agreed by and between the
Company and the Grantee as follows:
Section 1. Stock Appreciation Rights Award
The Company hereby grants to the Grantee a Stock Appreciation Rights Award
(the "Award") for the year ending December 31, 2000 (the "Award Year"). As more
fully described herein, the Award consists of Stock Appreciation Rights (the
"Rights") on a maximum total of [X,XXX] shares of the Company's Common Stock
(par value $.4867 per share). Subject to the employment restrictions in Section
4(d), the Grantee may exercise Rights on [X,XXX] shares (the "Service-Based
Stock Appreciation Rights") on or after December 31, 2000, and he may exercise
Rights on up to [X,XXX] shares (the "Performance-Based Stock Appreciation
Rights") upon the Company's achievement of the Performance Goals set forth in
Section 3.
When the Grantee exercises Rights, he will receive a cash payment equal to
the amount by which the Fair Market Value of one share of Common Stock on the
date of exercise exceeds the Fair Market Value of one share of Common Stock on
the date of grant, multiplied by the number of shares with respect to which
Rights are exercised. For purposes of the exercise of the Rights under this
Agreement, the Fair Market Value of one (1) share of Common Stock on the date of
grant is as of the close of business on December 31, 1999.
The Grantee's exercise of Rights is subject to the other restrictions set
forth in this Agreement. In no event may the Grantee exercise Rights after
December 31, 2005 (the "Expiration Date").
<PAGE> 2
Section 2. Service-Based Stock Appreciation Rights
Subject to the employment restrictions in Section 4(d), the Rights on
[X,XXX] shares become exercisable at the end of the Award Year. The Grantee may
exercise these Rights in addition to any Rights that may be exercisable pursuant
to Section 3.
Section 3. Performance-Based Stock Appreciation Rights
As soon as practicable after the Company's independent auditors have
certified the Company's financial statements for the Award Year, the Committee
shall determine for purposes of this Agreement the Company's (1) earnings growth
("EG"), (2) growth in non-regulated net income ("NRNI"), and (3) share price
relative to book value ("Price/Book Value") as of the end of the Award Year. The
EG, NRNI and Price/Book Value shall be determined by the Committee based on
financial results reported to shareholders in the Company's annual reports and
shall be subject to adjustment by the Committee for extraordinary events,
including, but not limited to, temperature fluctuation. The Committee shall
promptly notify the Grantee of its determination.
In addition to the Rights that may be exercised pursuant to Section
2, and subject to the continued employment requirements in Section 4(d), the
Grantee may exercise Rights on up to [X,XXX] shares (the "Maximum Performance
Award") as follows:
(1) If the EG for the Award Year exceeds the median five-year weighted
average growth for companies included in the C.A. Turner database (natural gas
distribution companies and integrated natural gas distribution companies), the
Grantee may exercise Rights on up to fifty percent (50%) of the Maximum
Performance Award, as follows:
(i) If the EG is in the fourth quartile of companies in the C.A.
Turner database, the Grantee may exercise Rights on fifty
percent (50%) of the Maximum Performance Award, or
(ii) If the EG falls between the median and the fourth quartile,
the Grantee may exercise Rights on a portion of the fifty
percent (50%) available under this paragraph that is pro-rated
to reflect the position of the Company's earnings growth
within the third quartile, or
(iii) If the EG is at or below the median, the Grantee may not
exercise any Rights available under this paragraph (1);
(2) If the temperature-adjusted NRNI for the Award Year exceeds the
temperature-adjusted NRNI for the prior calendar year by fifteen percent (15%)
or more, the Grantee may exercise Rights on thirty percent (30%) of the Maximum
Performance Award. If the temperature-adjusted NRNI for the Award Year does not
exceed the temperature-adjusted NRNI for the prior calendar year by at least
fifteen percent (15%), the Grantee may not exercise any Rights available under
this paragraph (2); and
(3) If the Price/Book Value for the Award Year is equal to or greater than
the average Price/Book Value for the Award Year of companies in the third
quartile of the C.A. Turner database (natural gas distribution companies and
integrated natural gas distribution companies), the Grantee may exercise Rights
on twenty percent (20%) of the Maximum Performance Award. If the Price/Book
Value for the Award Year is not equal to or greater than
2
<PAGE> 3
the average Price/Book Value for the Award Year of companies in the third
quartile of the C.A. Turner database the Grantee may not exercise any Rights
available under this paragraph 93). If one or more of the companies in the C.A.
Turner database is at any time during the Award Year the subject of an announced
acquisition, its stock shall not be considered for purposes of this paragraph
(3).
Section 4. Additional Terms and Conditions
(a) In the event of a Change in Control, as defined in the Plan, during
the Award Year, the Grantee may exercise Rights on the maximum number of shares
set forth in Sections 2 and 3, as if all service and performance criteria were
satisfied, pro rated based on the proportion of the Award Year that has expired
as of the date of such Change in Control.
(b) The Grantee may exercise Rights by delivering or mailing to the
Committee at the Company's address at the time of exercise a notice in writing
specifying the number of Rights to be exercised.
(c) The Rights are exercisable only by the Grantee or, in the case of the
Grantee's death or incapacity, by the Grantee's executors, administrators,
guardians or other legal representatives, and shall not be assignable or
transferable by the Grantee, other than by will or the laws of descent and
distribution.
(d) If the Grantee is separated from employment before Rights have been
exercised, such unexercised Rights shall be exercisable or forfeited as follows,
except that under no circumstances may any Rights be exercised after the
Expiration Date:
(i) Upon voluntary termination by the Grantee (other than for
retirement at age 65 or as accepted by the Committee), any unexercised Rights
shall be forfeited, unless otherwise determined by the Committee.
(ii) Upon termination by the Company for failure of job performance
or other just cause as determined by the Committee, any unexercised Rights that
are exercisable on the date of termination may be exercised during a period of
30 days following termination, after which time the Rights will expire, unless
such period is extended by the Committee.
(iii)If the Grantee terminates employment during the Award Year by
reason of death or total and permanent disability (as determined by the
Committee), the Grantee may exercise Rights that would otherwise have been
exercisable at the end of the Award Year, pro rated based on the proportion of
the Award Year during which the Grantee was employed by the Company. The
remaining Rights shall be forfeited unless the Committee determines otherwise.
If the Grantee terminates employment at any time by reason of death, all
unexercised Rights shall expire (if they have not otherwise expired) on the
later of (A) six months from the date of death, or (B) March 15, 2001, unless
extended by the Committee.
(iv) Upon retirement of the Grantee at age 65 or as accepted by the
Committee, any unexercised Rights may be exercised no later than the fifth
anniversary of such retirement, at which time unexercised Rights shall expire,
unless such period is extended by the Committee.
Section 5. Effect on Prior Agreement
Pursuant to an Agreement dated January 1, 1998, between the Company and
the Grantee (the "1998 Agreement"), awards may vest as of the end of each of
1998, 1999, and
3
<PAGE> 4
2000. This Agreement hereby modifies the 1998 Agreement to provide that no
awards shall vest for years after December 31, 1999. This Agreement does not
affect the status of awards that vested as of the end of 1998 or 1999, and the
terms of the 1998 Agreement shall continue in effect with respect to those
awards.
Section 6. Withholding
The Grantee shall be solely responsible for any federal, state and local
income taxes imposed in connection with the exercise of the Rights. The Company
may satisfy any withholding tax obligation by withholding an appropriate amount
of any cash due the Grantee upon exercise of the Rights.
Section 7. Additional Conditions to Exercise of Rights
Each exercise of Rights shall be subject to the condition that if at any
time the Committee shall determine, in its sole discretion, that it is necessary
or desirable as a condition of, or in connection with, such exercise (i) to
satisfy withholding tax or other withholding liabilities, or (ii) to obtain the
consent or approval of any regulatory body, then in any such event such exercise
shall not be effective unless such withholding, consent or approval shall have
been effected or obtained free of any conditions not acceptable to the Company.
Any such limitation affecting the right to exercise Rights shall not extend the
time within which Rights may be exercised, unless the Committee in its sole
discretion determines otherwise; and neither the Company or any affiliate of the
Company, the directors or officers of the Company or any affiliate of the
Company, nor the Committee shall have any obligation or liability to the Grantee
or to any executor, administrator, guardian or other legal representative of the
Grantee regarding Rights which may expire because of such limitation.
Section 8. Adjustment of Shares
(a) If the Company shall be involved in a merger, consolidation or other
reorganization, whether or not the Company is the surviving corporation, any
unexercised Rights received hereunder shall be deemed Stock Appreciation Rights
as to the same number of shares in the surviving corporation that a holder of
the number of shares of Common Stock subject to the unexercised Rights would be
entitled to receive under the terms of the merger, consolidation or other
reorganization. Any Rights deemed granted under this Section 8(a) shall be
deemed granted on the date the original Rights were granted. If the Company is
not the surviving corporation, the surviving corporation (the "Successor") shall
succeed to the rights and obligations of the Company under this Agreement.
(b) If any subdivision or combination of shares of Common Stock or any
stock dividend, capital reorganization or recapitalization occurs after the
adoption of the Plan, the Committee shall make such proportionate adjustments as
are appropriate in order to prevent the dilution or enlargement of the Grantee's
Rights.
Section 9. No Right to Employment
Nothing contained in this Agreement shall be deemed by implication or
otherwise to confer upon the Grantee any right to continued employment by the
Company or any affiliate of the Company.
Section 10. Notice
4
<PAGE> 5
Any notice to be given hereunder by the Grantee shall be sent by mail
addressed to Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover,
Delaware 19904, for the attention of the Committee, c/o the Secretary, and any
notice by the Company to the Grantee shall be sent by mail addressed to the
Grantee at the address of the Grantee shown on the first page hereof. Either
party may, by notice given to the other in accordance with the provisions of
this Section 10, change the address to which subsequent notices shall be sent.
Section 11. Assumption of Risk
It is expressly understood and agreed that the Grantee assumes all risks
incident to any change hereafter in the applicable laws or regulations or
incident to any change in the market value of shares of Common Stock.
Section 12. Terms of Plan
This Agreement is entered into pursuant to the Plan (a copy of which has
been delivered to the Grantee). This Agreement is subject to all of the terms
and provisions of the Plan, which are incorporated into this Agreement by
reference, and the actions taken by the Committee pursuant to the Plan. In the
event of a conflict between this Agreement and the Plan, the provisions of the
Plan shall govern. All determinations by the Committee shall be in its sole
discretion and will be binding on the Company and the Grantee.
Section 13. Governing Law; Amendment
This Agreement shall be governed by, and shall be construed, enforced and
administered in accordance with, the laws of the State of Delaware (without
regard to its choice of law rules) and the requirements of any applicable
federal law. This Agreement may be modified or amended only by a writing signed
by the parties hereto.
Section 14. Terms of Agreement
This Agreement shall remain in full force and effect and shall be binding
on the parties hereto for so long as Rights remain outstanding.
IN WITNESS WHEREOF, the Company has caused this Agreement to be executed
in its corporate name, and the Grantee has executed the same in evidence of the
Grantee's acceptance hereof, upon the terms and conditions herein set forth, as
of the day and year first above written.
CHESAPEAKE UTILITIES CORPORATION
By: ________________________________
________________________________
Grantee
5
<PAGE> 1
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
EXHIBIT 12
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Income from continuing operations $ 8,270,986 $ 5,302,586 $ 5,867,612
Add:
Income taxes 4,684,247 3,225,744 3,704,196
Portion of rents representative of interest factor 162,278 130,717 167,029
Interest on indebtedness 3,348,231 3,256,415 3,224,606
Amortization of debt discount and expense 117,966 123,335 119,401
- ----------------------------------------------------------------------------------------------------------------
EARNINGS AS ADJUSTED $16,583,708 $12,038,797 $13,082,844
================================================================================================================
FIXED CHARGES
Portion of rents representative of interest factor $ 162,278 $ 130,717 $ 167,029
Interest on indebtedness 3,348,231 3,256,415 3,224,606
Amortization of debt discount and expense 117,966 123,335 119,401
- ----------------------------------------------------------------------------------------------------------------
FIXED CHARGES $ 3,628,475 $ 3,510,467 $ 3,511,036
================================================================================================================
RATIO OF EARNINGS TO FIXED CHARGES 4.57 3.43 3.73
================================================================================================================
</TABLE>
50 Chesapeake Utilities Corporation
<PAGE> 1
CHESAPEAKE UTILITIES CORPORATION
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
SUBSIDIARIES STATE INCORPORATED
------------ ------------------
Eastern Shore Natural Gas Company Delaware
Sharp Energy, Inc. Delaware
Chesapeake Service Company Delaware
United Systems, Inc. Georgia
Tri-County Gas Co., Incorporated Maryland
Eastern Shore Real Estate Maryland
Xeron, Inc. Mississippi
Sam Shannahan Well Company, Inc. Maryland
Sharp Water, Inc. Delaware
SUBSIDIARY OF EASTERN SHORE NATURAL GAS COMPANY STATE INCORPORATED
- ----------------------------------------------- ------------------
Dover Exploration Company Delaware
SUBSIDIARIES OF SHARP ENERGY, INC. STATE INCORPORATED
---------------------------------- ------------------
Sharpgas, Inc. Delaware
Sharpoil, Inc. Delaware
SUBSIDIARIES OF CHESAPEAKE SERVICE COMPANY STATE INCORPORATED
------------------------------------------ ------------------
Skipjack, Inc. Delaware
Capital Data Systems, Inc. North Carolina
Currin and Associates, Inc. North Carolina
Chesapeake Investment Company Delaware
SUBSIDIARIES OF SHARP WATER, INC. STATE INCORPORATED
--------------------------------- ------------------
EcoWater Systems of Michigan, Inc. Michigan
Chesapeake Utilities Corporation 51
<PAGE> 1
CONSENT OF INDEPENDENT ACCOUNTANTS
--------
We consent to the incorporation by reference in the Prospectuses of Chesapeake
Utilities Corporation on Form S-2 (File No. 33-26582), Form S-3 (File Nos.
33-28391, 33-64671, 333-37165, 333-64757, 333-63381 and 333-94159) and Form S-8
(File No. 33-301175) of our report dated February 11, 2000 on our audits of the
consolidated financial statements and the consolidated financial statement
schedules of Chesapeake Utilities Corporation as of December 31, 1999 and 1998
and for each of the three years in the period ended December 31, 1999 included
in this Annual Report on Form 10-K.
/s/ PricewaterhouseCoopers LLP
PRICEWATERHOUSECOOPERS LLP
Washington, D.C.
March 28, 2000
52 Chesapeake Utilities Corporation
<TABLE> <S> <C>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 92,778,093
<OTHER-PROPERTY-AND-INVEST> 25,480,966
<TOTAL-CURRENT-ASSETS> 34,970,251
<TOTAL-DEFERRED-CHARGES> 13,738,485
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 166,967,795
<COMMON> 2,524,018
<CAPITAL-SURPLUS-PAID-IN> 25,782,824
<RETAINED-EARNINGS> 31,857,732
<TOTAL-COMMON-STOCKHOLDERS-EQ> 60,164,574
0
0
<LONG-TERM-DEBT-NET> 33,776,909
<SHORT-TERM-NOTES> 23,000,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 2,665,091
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 24,184,787
<TOT-CAPITALIZATION-AND-LIAB> 143,791,361
<GROSS-OPERATING-REVENUE> 230,863,123
<INCOME-TAX-EXPENSE> 4,173,670
<OTHER-OPERATING-EXPENSES> 39,289,464
<TOTAL-OPERATING-EXPENSES> 43,463,134
<OPERATING-INCOME-LOSS> 10,668,734
<OTHER-INCOME-NET> 1,068,449
<INCOME-BEFORE-INTEREST-EXPEN> 11,737,183
<TOTAL-INTEREST-EXPENSE> 3,466,197
<NET-INCOME> 8,270,986
0
<EARNINGS-AVAILABLE-FOR-COMM> 8,270,986
<COMMON-STOCK-DIVIDENDS> 5,305,638
<TOTAL-INTEREST-ON-BONDS> 2,793,712
<CASH-FLOW-OPERATIONS> 16,597,312
<EPS-BASIC> 1.61
<EPS-DILUTED> 1.57
</TABLE>
