As filed with the Securities and Exchange Commission on March 19, 1997
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 19961997
Commission File Number 0-593
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Chesapeake Utilities Corporation001-11590
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) (Zip Code)
Registrant'sRegistrants telephone number, including area code: 302-734-6713302-734-6799
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
-------------------
-----------------------------------------
Common Stock - par value per share $.4867
Name of each exchange on which registered
-----------------------------------------
New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
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'sregistrants 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 14, 1997, 4,452,70420, 1998, 4,543,695 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 14,20,
1997, as reported by the New York Stock Exchange, was approximately $78,478,908.$67
million.
DOCUMENTS INCORPORATED BY REFERENCE
Documents Part of FormDOCUMENTS PART OF FORM 10-K
Definitive Proxy Statement dated April 4, 1997 Part III
================================================================================dated March 30, 1998
CHESAPEAKE UTILITIES CORPORATION
FORM 10-K
Year Ended December 31, 19961997
TABLE OF CONTENTS
PART I
Page
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Item 1. Business.............................................. 1
Item 2. Properties............................................ 13
Item 3. Legal Proceedings..................................... 13
Item 4. Submission of Matters to a Vote of Security Holders... 17
Item 10. Executive Officers of the Registrant.................. 17
PART II
Item 5. Market for Registrant's Common Stock and Related
Security Holder Matters............................... 18
Item 6. Selected Financial Data............................... 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 21
Item 8. Financial Statements and Supplementary Data........... 27
Item 9. Changes In and Disagreements with Accountants
on Accounting and Financial Disclosure................ 47
PART III
Item 10. Directors and Executive Officers of the Registrant.... 47
Item 11. Executive Compensation................................ 47
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................. 47
Item 13. Certain Relationships and Related Transactions........ 47
PART IV
Item 14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K...................... 47
Signatures ...................................................... 51
Page
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Item 1. Business ...................................................... 1
Item 2. Properties ................................................... 11
Item 3. Legal Proceedings ............................................ 12
Item 4. Submission of Matters to a Vote of Security Holders .......... 15
Item 10.Executive Officers of the Registrant ......................... 15
PART II
Item 5. Market for Registrants Common Stock and Related
Security Holder Matters ...................................... 16
Item 6. Selected Financial Data ...................................... 17
Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations .......................... 18
Item 8. Financial Statements and Supplementary Data .................. 25
Item 9. Changes In and Disagreements with Accountants
on Accounting and Financial Disclosure ....................... 45
PART III
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
Item 14.Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K ............................. 45
Signatures ........................................................... 49
PART I
Item 1. Business
(a) General Development of Business
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a
diversified utility company engaged in natural gas distribution and
transmission, propane distribution and advanced information services.
Chesapeake'sChesapeakes three natural gas distribution divisions serve approximately
34,70035,800 residential, commercial and industrial customers in southern Delaware,
Maryland'sMarylands Eastern Shore and Central Florida. The Company'sCompanys natural gas
transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"),
operates a 271-mile interstate pipeline system that transports gas from
various points in Pennsylvania to the Company'sCompanys 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'sCompanys
propane segment serves approximately 23,10034,000 customers in southern Delaware
and on the Eastern Shore of Maryland and Virginia. The advanced information
services segment provides software services and products to a wide variety of
customers and clients.
(b) Financial Information Aboutabout Industry Segments
Portions of Segment data from Annual Report. (Note E)
For the Years Ended December 31,
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1996 1995 1994
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Operating Revenues, Unaffiliated Customers
Natural gas distribution $74,904,076 $54,120,280 $49,523,743
Natural gas transmission 15,188,777 24,984,767 22,191,896
Propane distribution 22,333,969 17,607,956 20,684,150
Advanced information services and other 6,903,246 7,307,413 6,172,508
-----------------------------------------------------
Total operating revenues, unaffiliated customers $119,330,068 $104,020,416 $98,572,297
-----------------------------------------------------
Intersegment Revenues *
Natural gas distribution $8,711 $42,037 $55,888
Natural gas transmission 21,543,327 16,663,043 17,303,529
Propane distribution 2,059 139,052 85,552
Advanced information services and other 710,949 1,722,135 2,277,361
-----------------------------------------------------
Total intersegment revenues $22,265,046 $18,566,267 $19,722,330
-----------------------------------------------------
Operating Income Before Income Taxes
Natural gas distribution $7,167,236 $4,728,348 $4,696,659
Natural gas transmission 2,458,442 6,083,440 3,018,212
Propane distribution 2,053,299 1,852,630 2,287,688
Advanced information services and other 1,305,203 1,170,970 174,033
-----------------------------------------------------
Total 12,984,180 13,835,388 10,176,592
Add (Less): Eliminations 206,580 (248,595) (419,883)
-----------------------------------------------------
Total operating income before income taxes $13,190,760 $13,586,793 $9,756,709
-----------------------------------------------------
Identifiable Assets, at December 31,
Natural gas distribution $81,250,030 $75,630,741 $68,528,774
Natural gas transmission 23,981,989 19,292,524 17,792,415
Propane distribution 20,791,588 18,855,507 16,949,431
Advanced information services 1,496,418 1,635,100 3,196,064
Other 3,617,885 3,380,108 1,803,933
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Total identifiable assets $131,137,910 $118,793,980 $108,270,617
-----------------------------------------------------
* All significant intersegment revenues have been eliminated from
consolidated revenues.
Financial information by business segment is included in Item 7 under the
heading Notes to Consolidated Financial Statements.
(c) Narrative Description of Business
The Company is engaged in four primary business activities: natural gas
transmission;transmission, natural gas distribution;distribution, propane distribution;distribution and advanced
information services. In addition to the four primary groups, Chesapeake has
three subsidiaries engaged in other service related businesses.
During 1996 and
1994, no individual customer accounted for 10% or more of operating revenues.
In 1995, the Company had sales to one customer, Texaco Refining and Marketing,
an industrial interruptible customer of Eastern Shore, which exceeded 10% of
total revenue. Total sales to this customer were approximately $10.6 million or
10.2% of total revenue during 1995.
(i) (a) Natural Gas Transmission
Eastern Shore, the Company'sCompanys wholly owned transmission subsidiary,
operates an interstate natural gas transportation and provides contract
storage services for affiliated and non-affiliated companies through an
integrated gas pipeline that delivers gasextending from southeastern Pennsylvania to five utility and thirteen industrial
customers in
Delaware and the Eastern Shore of Maryland. During 1997, Eastern Shore
is the
sole sourceimplemented open access transportation services. Eastern Shore now
provides transportation services, contract storage services as well as
purchasing and selling small amounts of gas supply for Chesapeake's Maryland and Delaware divisions and
for two unaffiliated distribution entities. During 1996 and previously,system balancing purposes
("swing gas"). Eastern Shore was not an open access pipeline (see competition within natural
gas industry) which would provide transportation serviceShores rates are subject to all customers.
However, Eastern Shore has authority fromregulation by the
Federal Energy Regulatory Commission ("FERC") to provide.
Adequacy of Resources
With the implementation of open access effective November 1, 1997, Eastern
Shore released, through the permanent release mechanism of its upstream
service providers tariffs, various levels of firm transportation capacity
and contract storage service to two of its customers for
gas they own and deliver tocustomers. Eastern Shore for redelivery.
Natural Gas Supply
General. Eastern Shore has firmretained
contracts with three major interstate
pipelines, Transcontinental Gas Pipe Line Corporation ("Transco"), for
4,916 thousand cubic feet ("Mcf") firm transportation capacity, expiring
in 2005, and three firm storage services providing peak day entitlements
of 7,046 Mcf.
Eastern Shore also retained contracts with Columbia Gas Transmission CorporationTransportation
("Columbia") for services, including: firm transportation capacity of 869
Mcf per day, which expires in 2018; storage service providing a peak day
entitlement of 1,111 Mcf and total capacity of 53,738 Mcf, expiring in
2004; and firm storage service providing peak day entitlements of 563 Mcf
and a total capacity of 50,686 Mcf, which expires in 2018. Eastern Shore
retained the firm transportation capacity to provide swing transportation
service to a limited number of customers that requested this service.
Prior to open access, Eastern Shore had firm contracts with three
interstate pipelines for transportation and storage services coupled with
firm contracts for natural gas supply with five suppliers providing a
maximum firm daily capacity of 20,469 Mcf.
Competition
Under this open access environment, interstate pipeline companies have
unbundled the traditional components of their service -- gas gathering,
transportation and storage -- from the sale of the commodity. Pipelines
that choose to be merchants of gas must form separate marketing operations
independent of their pipeline operations. Hence, gas marketers have
developed as a viable option for many companies because they are providing
expertise in gas purchasing along with collective purchasing capabilities
which, when combined, may reduce end-user cost. Additional discussion on
competition is included in Item 7 under the heading "Managements
Discussion and Analysis of Financial Condition and Results of Operations".
Rates and Regulation
General. Eastern Shore is subject to regulation by the FERC as an
interstate pipeline. The FERC regulates the provision of service, terms
and conditions of service, and the rates and fees Eastern Shore can charge
to its transportation customers. In addition, the FERC regulates the rates
Eastern Shore is charged for transportation and transmission line capacity
and services provided by Transco and Columbia.
Regulatory Proceedings
Delaware City Compressor Station Filing. In December 1995, Eastern Shore
filed an application before the FERC pursuant to Sections 7(b) and (c) of
the Natural Gas Act for a certificate of public convenience and necessity
authorizing Eastern Shore to: (1) construct and operate a 2,170 horsepower
compressor station in Delaware City, New Castle County, Delaware on a
portion of its existing pipeline system known as the "Hockessin Line",
such new station to be known as the "Delaware City Compressor Station";
(2) construct and operate slightly less than one mile of 16-inch pipeline
in Delaware City, New Castle County, Delaware to tie the suction side of
the proposed Delaware City Compressor Station into the Hockessin Line; and
(3) increase the maximum allowable operating pressure from 500 psig to 590
psig on 28.7 miles of Eastern Shores pipeline from Eastern Shores
existing Bridgeville Compressor Station in Bridgeville, Sussex County,
Delaware to its terminus in Salisbury, Wicomico County, Maryland.
In September 1996 the FERC issued its Final Order, which: (1) authorized
Eastern Shore to construct and operate the facilities requested in its
application; (2) authorized Eastern Shore to roll-in the cost of the
facilities into its existing rates if the revenues from the increase in
services exceed the cost associated with the expansion portion of the
project; (3) denied Eastern Shore the authority to increase the level of
sales and storage service it provides its customers until it completes its
restructuring in its open access proceeding; and (4) authorized Eastern
Shore to abandon the 100 Mcf per day of firm sale service, to one of its
direct sale customers. The compressor facility and associated piping were
needed to stabilize capacity on Eastern Shores system as a result of
steadily declining inlet pressures at the Hockessin interconnect with
Transcontinental Gas Pipe Line Corporation. Construction of the facilities
started during the second half of 1996 and was completed during the first
quarter of 1997.
Rate Case Filing. In October 1996 Eastern Shore filed for a general rate
increase with the FERC. The filing proposed an increase in Eastern Shores
jurisdictional rates that would generate additional annual operating
revenue of approximately $1.4 million. Eastern Shore also stated in the
filing that it intended to use the cost-of-service submitted in the
general rate increase filing to develop rates in the pending Open Access
Docket. In September 1997, the FERC approved a rate increase of $1.2
million.
Open Access Filing. In December 1995, Eastern Shore filed its abbreviated
application for a blanket certificate of public convenience and necessity
authorizing the transportation of natural gas on behalf of others. Eastern
Shore proposed to unbundle the sales and storage services it had provided.
Customers who had previously received firm sales and storage services on
Eastern Shore (the "Converting Customers") would receive entitlements to
firm transportation service on Eastern Shores pipeline in a quantity
equivalent to their existing service rights. Eastern Shore proposed to
retain some of its pipeline entitlements and storage capacity for
operational issues and to facilitate "no-notice" (no prior notification
required to receive service) transportation service on its pipeline
system. Eastern Shore would release or assign to the remaining Converting
Customers the firm transportation capacity, including contract storage, it
held on its upstream pipelines so that the Converting Customers would be
able to become direct customers of such upstream pipelines. Converting
Customers who previously received bundled sales service having no-notice
characteristics would have the right to elect no-notice firm
transportation service.
In connection with the rate increase settlement, the issues pertaining to
Eastern Shore operating as an open access pipeline were also settled in
September 1997, with open access implementation occurring on November 1, 1997.
(i) (b) Natural Gas Distribution
Chesapeake distributes natural gas to approximately 35,800 residential,
commercial and industrial customers in southern Delaware, the Salisbury
and Cambridge, Maryland areas on Marylands Eastern Shore, and Central
Florida. These activities are conducted through three utility divisions,
one division in Delaware, another in Maryland and a third division in
Florida. In 1993, the Company started natural gas supply management
services in the state of Florida under the name of Peninsula Energy
Services Company ("PESCO").
Delaware and Maryland. The Delaware and Maryland divisions serve
approximately 29,950 customers, of which approximately 26,860 are
residential and commercial customers purchasing gas primarily for heating
purposes. Annually, residential and commercial customers account for
approximately 69% of the volume delivered by the divisions, and 79% 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 Chesapeakes customer growth in these
divisions comes from new residential construction using gas heating
equipment.
Florida. The Florida division distributes natural gas to approximately
8,748 residential and commercial and 84 industrial customers in Polk,
Osceola and Hillsborough Counties. Currently 42 of the divisions
industrial customers, which purchase and transport gas on a firm and
interruptible basis, account for approximately 90% of the volume delivered
by the Florida division and 60% of the divisions annual natural gas and
transportation revenues. These customers are primarily engaged in the
citrus and phosphate industries and electric cogeneration. The Companys
Florida division also provides natural gas supply management services to
compete in the open access environment. Currently, twenty-one customers
receive such services, which generated gross margin of $70,000 in 1997.
Adequacy of Resources
General. Chesapeakes Delaware and Maryland utility divisions ("Delaware",
"Maryland" or "the Divisions") have firm and interruptible contracts with
four (4) interstate "open access" pipelines. The Divisions are directly
interconnected with Eastern Shore and services upstream of Eastern Shore
are contracted with Transco, Columbia, and Columbia Gulf Transmission
CorporationCompany ("Gulf"), all of which are open access pipelines.
Eastern Shore's.
Delaware. Delawares contracts with Transco include: (a) firm
transportation capacity of 22,900 Mcf8,663 dekatherms ("Dt") per day, which expires
in 2005; (b) firm transportation capacity of 500 Mcf311 Dt per day for December
through February, which expiresexpiring in 2006; and (c) three firm bundled storage servicesservice,
providing a peak day entitlement
of 7,046 Mcf and a total capacity of 278,264 Mcf; and (d) two unbundled
storage services with a total capacity of 432,663 Mcf.
Eastern Shore's142,830 Dt, which expires in 1998.
Delawares contracts with Columbia include: (a) firm transportation
capacity of 1,481 Mcf852 Dt per day, which expires in 2004; (b) firm transportation
capacity of 1,971 Mcf1,132 Dt per day, which commences in 1997 and expires in 2017;
(c) firm transportation capacity of 869 Mcf per day, which commences in 1998
and expires in 2018; (d) firm transportation capacity of 869 Mcf per day,
which commences in 1999 and expires 2019; and (e) firm transportation capacity
of 192 Mcf per day for April through August, which expires in 2003. Eastern
Shore's contracts with Columbia also include: (a) firm storage service
providing a peak day entitlement of 10,525 Mcf and a total capacity of 509,954
Mcf, which expires in 2004; (b) firm storage service providing a peak day
entitlement of 1,150 Mcf and a total capacity of 103,459 Mcf, which commences
in 1997 and expires in 2017; (c) firm storage
service, providing a peak day entitlement of 563 Mcf6,193 Dt and a total capacity
of 50,686 Mcf,298,195 Dt, which commences in
1998 and expires in 2018;2004; and (d) firm storage service
providing a peak day entitlement of 563 Mcf635 Dt and a total capacity of 50,686 Mcf, which commences57,139
Dt, expring in 19992017. Delawares 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 expires in 2019.
Eastern Shore'sare 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.
Delawares contract with Gulf, is forwhich expires in 2004, provides firm
transportation capacity of 1,510 Mcf868 Dt per day for the period November through
March and 798 Dt per day for the period April through October.
Delawares contracts with Eastern Shore include: (a) firm transportation
capacity of 23,494 Dt per day for the period December through February,
22,272 Dt per day for the months of November, March and April, and 13,196
Dt per day for the period May through October, with various expiration
dates ranging from 2004 to 2017; (b) firm storage capacity under Eastern
Shores Rate Schedule GSS providing a peak day entitlement of 2,655 Dt and
a total capacity of 131,370 Dt, which also expires in 2004.2013; (c) firm storage
capacity under Eastern Shores 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 Shores Rate Schedule
LGA providing a peak day entitlement of 911 Dt and a total capacity of
5,708 Dt, which expires in 2006. Delawares firm transportation contracts
with Eastern Shore also include Eastern Shores provision of swing
transportation service. This service includes: (a) firm transportation
capacity of 1,846 Dt per day on Transcos pipeline system, retained by
Eastern Shore, in addition to Delawares Transco capacity referenced
earlier and (b) an interruptible storage service under Transcos Rate
Schedule ESS that supports a swing supply service provided under Transcos
Rate Schedule FS.
Delaware currently has contracts for the purchase of firm natural gas
suppliessuppy with five reputable(5) suppliers. These five supply contracts provide the availability of
a maximum firm daily entitlement of 20,469 Mcf, which is10,958 Dt and the supplies are
transported by both
Transco, Columbia, Gulf and ColumbiaEastern Shore under Eastern Shore's firmDelawares
transportation contracts. The gas purchase contracts have various
expiration dates.
2
AdequacyMaryland. Marylands contracts with Transco include: (a) firm
transportation capacity of Gas Supply.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 1998.
Marylands contracts with Columbia include: (a) firm transportation
capacity of 442 Dt per day, which expires in 2004; (b) firm transportation
capacity of 908 Dt per day, which expires in 2017; (c) firm storage
service providing a peak day entitlement of 3,142 Dt and a total capacity
of 154,756 Dt, which expires in 2004; and (d) firm storage service
providing a peak day entitlement of 521 Dt and a total capacity of 46,881
Dt, which expires in 2017. Marylands 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.
Marylands 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.
Marylands contracts with Eastern Shore'sShore include: (a) firm transportation
capacity of 13,028 Dt per day for the period December through February,
12,304 Dt per day for the months of November. March and April, and 7,743
Dt per day for the period May through October; (b) firm storage capacity
under Eastern Shores 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 Shores 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 Shores Rate
Schedule LGA providing a peak day entitlement of 569 Dt and a total
capacity of 3,560 Dt, which expires in 2006. Marylands firm
transportation contracts with Eastern Shore also include Eastern Shores
provision of swing transportation service. This service includes: (a) firm
transportation capacity of 969 Dt per day on Transcos pipeline system,
retained by Eastern Shore, in addition to Marylands Transco capacity
referenced earlier and (b) an interruptible storage service under
Transcos Rate Schedule ESS that supports a swing supply service provided
under Transcos Rate Schedule FS.
Maryland currently has contracts for the purchase of firm natural gas
obligations to its
customers, including Chesapeake's Delaware and Maryland utility divisions, are
40,237 Mcf for peak days and 9,180,203 Mcf on an annual basis. Eastern Shore'ssupply with five (5) suppliers. These contracts provide the availability
of a maximum daily firm transportation capacity on the Transco and Columbia systems
is 42,452 Mcf per day. Currently, Eastern Shore's firm daily peak supply is
38,540 Mcfentitlement of 6,243 Dt and its total annualthe supplies are
transported by Transco, Columbia, Gulf and Eastern Shore under Marylands
transportation contracts. The gas purchase contracts have various
expiration dates. The Divisions use their firm supply is 6,032,665 Mcf. This is
equivalentsources to 96%meet a
significant percentage of Eastern Shore's firm dailytheir projected demand and approximately 66%
of its annual firm demand being satisfied by firm supply sources. Torequirements. In order to
meet the difference between firm supply and firm demand, Eastern Shore obtainsDelaware and
Maryland obtain gas supply on the "spot market" from various other
suppliers whichthat is transported by Transco and/or Columbiathe upstream pipelines and solddelivered to
the Divisions interconnects with Eastern Shore's customersShore as needed. The Company
believes that Eastern Shore'sDelaware and Marylands available firm and "spot market"
supply is ample to meet the anticipated needs of Eastern Shore'stheir customers.
There was no curtailmentFlorida. 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
20,523 Dt in May through September, 27,105 Dt in October, and 26,919 Dt in
November through April under FGTs firm transportation service (FTS-1)
rate schedule; (b) daily firm transportation capacity of 5,100 Dt in May
through October, and 8,100 Dt in November through April under FGTs firm
transportation service (FTS-2) rate schedule; and (c) daily interruptible
transportation capacity of 20,000 Dt under FGTs interruptible
transportation services (ITS-1) rate schedule. The firm transportation
contract (FTS-1) expires on August 1, 2000 with the Company retaining a
unilateral right to extend the term for an additional ten years. After the
expiration of the primary or secondary term, Chesapeake has the right to
first refuse to match the terms of any competing bids for the capacity.
The firm transportation contract (FTS-2) expires on March 1, 2015. The
interruptible transportation contract is effective until August 1, 2010
and month to month thereafter unless canceled by either party with thirty
days notice.
The Florida division currently receives its gas supply from various
suppliers. If needed, some supply is bought on the spot market; however,
the majority is bought under the terms of two firm supply contacts with
Natural Gas Clearinghouse and LG&E Energy Marketing. Availability of gas
supply to Eastern Shore in 1996, nor does
Eastern Shore anticipate any such curtailment during 1997.the Florida division is also expected to be adequate under
existing arrangements.
Competition
Competition with Alternative Fuels. Historically, the Company'sCompanys natural
gas operationsdistribution divisions have successfully competed with other forms of
energy such as electricity, oil and propane. The principal consideration
in the competition between the Company and suppliers of other sources of
energy is price and, to a lesser extent, accessibility. All of the
Company'sCompanys divisions have the capability of adjusting their interruptible
rates to compete with alternative fuels.
The Company hasdivisions have several large volume industrial customers that have the
capacity to use fuel oil as an alternative to natural gas. When oil prices
decline, some of Chesapeake's natural gas distribution and transmissionthese interruptible customers convert to oil to satisfy their
fuel requirements. Lower levels in interruptible sales occur when oil
prices remain depressed relative to the price of natural gas. However, oil
prices as well as the prices of other fuels are subject to change at any
time for a variety of reasons; therefore, there is always uncertainty in
the continuing competition among natural gas and other fuels. In order to
address this uncertainty, the Company uses flexible pricing arrangements
on both the supply and sales side of its business to maximize sales
volumes.
To a lesser extent than price, availability of equipment and operational
efficiency are also factors in competition among fuels, primarily in
residential and commercial settings. Heating, water heating and other
domestic or commercial equipment is generally designed for a particular
energy source, and especially with respect to heating equipment, the cost
of conversion is a dis-incentivedisincentive for individuals and businesses to change
their energy source.
Competition within the Natural Gas Industry. FERC Order 636 enables all
natural gas suppliers to compete for customers on an equal footing. Under
this open access environment, interstate pipeline companies have unbundled
the traditional components of their service --- gas gathering,
transportation and storage from the sale of the commodity. If they choose
to be a merchant of gas, they must form a separate marketing operation
independent of their pipeline operations. Hence, gas marketers have
developed as a viable option for many companies because they are providing
expertise in gas purchasing along with collective purchasing capabilities
which, when combined, may reduce end-user cost.
Currently, Eastern Shore is notAlso resulting from an open access pipeline andenvironment, the distribution division
can be in competition with the interstate transmission company if the
distribution customer is permitted to
transport gas for only two of its existing customers. Thus, most of Eastern
Shore's customers, including Chesapeake's Maryland and Delaware utility
divisions, and, in turn, customers of these divisions, do not have the
capability of directly contracting for alternative sources of gas supply and
have Eastern Shore transport the gas to them. In December 1995, Eastern
3
Shore appliedlocated close to the FERC for a blanket certificate authorizing open access
transportation service on its pipeline system (see open access plan filing
below).transmission companys
pipeline. The implementation of open access transportation service, expected to
occur during 1997, will provide all of Eastern Shore'scustomers at risk are usually large volume commercial and
industrial customers with the opportunityfinancial resources and capability to transport gas over its system at FERC regulated rates. For
further discussion, see "Open Access Plan Filing"bypass
the distribution division. In certain situations the distribution
divisions may adjust rates and Management Discussion
and Analysis of financial condition and results of operations.serves for these customers to retain their
business.
Rates and Regulation
General. Eastern Shore is subject to regulation by the FERC as an interstate
pipeline and the Delaware Public Service Commission ("Commission") as a
supplier of gas to industrial customers in the state of Delaware. The FERC
regulates the provision of service, terms and conditions of service, and the
rates and fees Eastern Shore can charge its transportation and sale for resale
customers. In addition, the FERC regulates the rates Eastern Shore is charged
for transportation and transmission line capacity or services provided by
Transco and Columbia. Eastern Shore's direct sales rates to industrial
customers are currently not regulated. The rates for such sales are
established by contracts negotiated between Eastern Shore and each industrial
customer.
After Eastern Shore becomes an open access pipeline, the FERC will have sole
regulatory authority over Eastern Shore. Accordingly, the Delaware Public
Service Commission will cease having any regulatory authority over Eastern
Shore.
The rates for Eastern Shore's "sale for resale" customers (i.e., sales to its
utility customers) are subject to a purchased gas adjustment clause. Eastern
Shore's firm industrial contracts generally include tracking provisions that
permit automatic adjustment for the full amount of increases or decreases in
Eastern Shore's suppliers' firm rates.
Regulatory Proceedings
FERC PGA. On May 19, 1994, the FERC issued an Order directing Eastern Shore
to refund, with interest, what the FERC characterized as overcharges from
November 1, 1992 to the current billing month. The May 19, 1994 Order also
directed Eastern Shore to file a report showing how the refund was calculated,
and revised tariff language clarifying the purchased gas adjustment provisions
in its tariff.
On August 17, 1995, the FERC issued an Order approving an Offer of Settlement
submitted by Eastern Shore. The Order approved a change in Eastern Shore's PGA
methodology retroactive to June 1, 1994, which will result in a rate reduction
of approximately $234,000 per year. The estimated liability that the Company
had accrued for the potential refund was significantly greater than the rate
reduction ordered. Accordingly, Eastern Shore reversed a large portion of the
liability that it had accrued. This reversal contributed $1,385,000 to pre-tax
earnings or $833,000 to after-tax earnings during the third quarter of 1995.
In connection with the FERC Order, Eastern Shore applied in December 1995, to
the FERC for a blanket certificate authorizing open access transportation
service on its pipeline system. For further discussion see "Open Access Plan
Filing" below.
Delaware City Compressor Station Filing. On December 5, 1995, Eastern Shore
filed an application before the FERC pursuant to Sections 7(b) and (c) of the
Natural Gas Act for a certificate of public convenience and necessity
authorizing Eastern Shore to: (1) construct and operate a 2,170 horsepower
compressor station in Delaware City, New Castle County, Delaware on a portion
of its existing pipeline system known as the "Hockessin Line", such new
station to be known as the "Delaware City Compressor Station"; (2) construct
and operate slightly less than one mile of 16-inch pipeline in Delaware City,
New Castle County, Delaware to tie the suction side of the proposed Delaware
City Compressor Station into the Hockessin Line; and (3) increase
4
the maximum allowable operating pressure ("MAOP") from 500 PSIG to 590 PSIG on
28.7 miles of Eastern Shore's pipeline from Eastern Shore's existing
Bridgeville Compressor Station in Bridgeville, Sussex County, Delaware to its
terminus in Salisbury, Wicomico County, Maryland.
The 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 Transcontinental Gas Pipe Line Corporation.
Construction of the facilities started during the second half of 1996. The
proposed in-service date of the facilities is March 19, 1997. Eastern Shore
estimates the total cost of the compressor facilities to be $6.9 million.
The proposed facilities would also enable Eastern Shore to provide additional
firm services to several of its customers who have executed agreements for the
additional firm service for terms of 10 and 20 years. Eastern Shore also
requested authorization to abandon 100 Mcf per day of firm sales service to
one of its direct sales customers.
On September 28, 1996 the FERC issued its Final Order, which:
. authorized Eastern Shore to construct and operate the facilities
requested in its application;
. authorized Eastern Shore to roll-in the cost of the facilities into its
existing rates if the revenues from the increase in services exceed the
cost associated with the expansion portion of the project;
. denied Eastern Shore the authority to increase the level of sales and
storage service it provides its customers until it completes its
restructuring in its open access proceeding; and
. authorized Eastern Shore to abandon the 100 Mcf per day of firm sale
service, to one of its direct sale customers.
Rate Case Filing. On October 15, 1996 Eastern Shore filed for a general rate
increase with the FERC. The filing proposed an increase in Eastern Shore's
jurisdictional rates that would generate additional annual operating revenue
of approximately $1,445,000. Eastern Shore also stated in the filing that it
intended to use the cost-of-service submitted in the general rate increase
filing to develop rates in the pending Open Access Docket. The Commission, by
letter order dated November 14, 1995, suspended the tariff sheets for the
maximum five-month period as allowed by Commission regulation.
On March 4, 1997, a pre-hearing conference was conducted at FERC's office to
establish a procedural schedule to establish a preliminary list of contested
issues and to advise the Presiding Judge of any matters which need to be
resolved. Hearings are tentatively scheduled to start in 1997.
Open Access Filing. On December 29, 1995, Eastern Shore filed its abbreviated
application for a blanket certificate of public convenience and necessity
authorizing the transportation of natural gas on behalf of others.
Eastern Shore proposed to unbundle the sales and storage services it currently
provides. Customers receiving firm sales and storage services on Eastern Shore
(the "Converting Customers") would receive entitlements to firm transportation
service on Eastern Shore's pipeline in a quantity equivalent to their current
service rights. Eastern Shore proposed to retain some of its pipeline
entitlements and storage capacity for operational issues and to facilitate
"no-notice" (no prior notification required to receive service) transportation
service on its pipeline system. Eastern Shore will release or assign to the
remaining Converting Customers the firm transportation capacity, including
contract storage, it holds on its upstream pipelines so that the Converting
Customers can become direct customers of such upstream pipelines. Converting
Customers who previously received bundled sales service having no-notice
characteristics will have the right to elect no-notice firm transportation
service.
5
With respect to cost classification, allocation and rate design, Eastern Shore
proposes to implement straight fixed variable ("SFV") cost classification. In
order to accomplish a change from its current modified fixed variable ("MFV")
rate design, Eastern Shore made a Section 4 rate filing with the FERC on
January 17, 1997.
During 1996, numerous technical conferences were held at the FERC's office in
Washington, D.C. to review the proposed Open Access tariff. On December 2,
1996, Eastern Shore filed a revised Pro-forma Open Access tariff. A technical
conference was conducted on December 12, 1996 to discuss Eastern Shore's
filing. As a result of the technical conference, Eastern Shore formally filed
a revised Open Access tariff including rate schedules on January 17, 1997. The
filing included a proposed effective date, the latter of May 1, 1997 or the
effective date of the Open Access blanket certificate. Since January 17, 1997,
several parties have filed comments. Eastern Shore filed reply comments and a
technical was convened on March 4, 1997. As a result of the March 4 technical
conference, Eastern Shore will be submitting a revised proposal to the parties
in an effort to gain consensus on the major issues. While at this time it is
impossible to predict the exact timing of the implementation of Open Access on
Eastern Shore's system, significant progress has been made, and management
expects that implementation will occur sometime during the second or third
quarter.
(i) (b) Natural Gas Distribution
Chesapeake distributes natural gas to approximately 34,700 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, consisting of
one division in Delaware, one division in Maryland and one division in
Florida. In 1993, the Company started natural gas supply management services
in the state of Florida under the name of Peninsula Energy Services Company
("PESCO").
Delaware and Maryland. The Delaware and Maryland divisions serve
approximately 26,160 customers, of which approximately 26,050 are residential
and commercial customers purchasing gas primarily for heating purposes.
Residential and commercial customers account for approximately 69% of the
volume delivered by the divisions, and 78% of the divisions' revenue, on an
annual basis. 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 utilizing gas heating equipment.
Florida. The Florida division distributes natural gas to approximately 8,450
residential and commercial and 87 industrial customers in Polk, Osceola and
Hillsborough Counties. Currently 42 of the division's industrial customers,
which are engaged primarily in the citrus and phosphate industries and
electric cogeneration, and purchase and transport gas on a firm and
interruptible basis, account for approximately 90% of the volume delivered by
the Florida division, and 62% of the division's natural gas sales and
transportation revenues, on an annual basis. The Company's Florida division
also provides natural gas supply services to compete in the open access
environment. Currently, nineteen customers receive such management service
which generated operating income of $209,000 in 1996.
Natural Gas Supply
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions
receive all of their gas supply requirements from Eastern Shore. The divisions
purchase most of this gas under contracts with Eastern Shore which extend
through November 1, 2000. The contracts provide for the purchase of 15,629
firm Mcf daily (up to a maximum of 5,704,585 Mcf annually). The divisions have
additional firm supplies available under contract with Eastern Shore for peak
demand periods occurring during the winter heating season. These
6
contracts, which are renewable on a year-to-year basis, provide for the
purchase of up to 450 Mcf daily (up to a maximum of 13,500 Mcf annually) of
peaking service. In addition, the divisions have contracted with Eastern Shore
for firm and interruptible storage capacity. On days when gas volumes
available to the divisions from Eastern Shore are greater than their
requirements, gas is injected into storage and is then available for
withdrawal to meet heavier winter loads. These storage contracts also permit
the utility divisions to purchase lower cost gas during the off-peak summer
season. Effective July 1, 1996, the storage capacity under contract with
Eastern Shore totaled 820,220 Mcf, with a firm peak daily withdrawal
entitlement of 14,606 Mcf. On those days when requirements exceed these
contract pipeline supplies, the divisions have propane-air injection
facilities for peak shaving.
Eastern Shore has no authority to transport natural gas purchased from a third
party for the Delaware and Maryland divisions currently; however, while
Chesapeake's divisions have no direct access to "spot market" gas, they
benefit from Eastern Shore's ability to obtain "spot market" gas and the
resulting reductions in Eastern Shore's rates. After Eastern Shore becomes an
open access pipeline the Delaware and Maryland divisions will assume the
responsibility of purchasing their natural gas requirements. The two divisions
could contract with a natural gas supply management company or handle the
process internally.
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 20,523
dekatherms in May through September , 27,105 dekatherms in October, and 26,919
dekatherms in November through April under FGT's firm transportation service
(FTS-1) rate schedule; (b) daily firm transportation capacity of 5,100
dekatherms in May through October, and 8,100 dekatherms in November through
April under FGT's firm transportation service (FTS-2) rate schedule; (c)
preferred interruptible transportation service up to 2,300,000 dekatherms
annually under FGT's preferred transportation service (PTS-1) rate schedule;
and (d) daily interruptible transportation capacity of 20,000 dekatherms under
FGT's interruptible transportation services (ITS-1) rate schedule. The firm
transportation contract (FTS-1) expires on August 1, 2000 with the Company
retaining a unilateral right to extend the term for an additional ten years.
After the expiration of the primary or secondary term, Chesapeake has the
right to first refuse to match the terms of any competing bids for the
capacity. The firm transportation contract (FTS-2) expires on March 1, 2015.
The preferred interruptible contract expires on the earlier of: (a) the
effective date of FGT's first rate case which includes costs for phase III
expansion or (b) August 1, 1995, and/or (c) August 1 of any subsequent year,
provided that FGT or Chesapeake gives to the other at least one hundred eighty
(180) days written notice prior to such August 1. 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.
Some supply is bought on the spot market and some is bought under the terms of
two firm supply contacts with MG National Gas Corp. and Hadson Gas Systems,
Inc.
Having restructured its arrangements with FGT, Chesapeake believes it is well
positioned to meet the continuing needs of its customers with secure and cost
effective gas supplies.
Adequacy of Gas Supply. The Company believes that Eastern Shore's available
firm and interruptible supply is ample to meet the anticipated needs of the
Company's Delaware and Maryland natural gas distribution divisions.
Availability of gas supply to the Florida division is also expected to be
adequate under existing arrangements. Moreover, additional supply sources have
become available as a result of FGT becoming an open access pipeline.
7
Competition within the Natural Gas Industry. Historically, Chesapeake's
Florida division has been supplied solely by FGT. In 1990, FGT became an open
access pipeline. The Florida division's large industrial customers now have
the option of remaining with the Florida division for gas supply or obtaining
alternative supplies from gas marketers or other suppliers. These conditions
have increased competition between Chesapeake's Florida division, gas
marketers and other natural gas providers for industrial customers in Central
Florida.
Eastern Shore has an open access filing and associated rate filing pending
before the FERC. When Eastern Shore becomes an open access pipeline, certain
customers in Chesapeake's Delaware and Maryland distribution divisions will be
able to purchase gas from third party gas suppliers in accordance with
regulations established through the respective state commissions.
Rates and Regulation
General. Chesapeake'sChesapeakes 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'sCompanys business,
including the rates for sales to all of their customers in each
jurisdiction. All of Chesapeake'sChesapeakes firm distribution rates are subject to
purchased gas adjustment clauses, which match revenues with gas costs and
normally allow eventual full recovery of gas costs. Adjustments under
these clauses require periodic filings and hearings with the relevant
regulatory authority, but do not require a general rate proceeding. Rates
on interruptible sales by the Florida division are also subject to
purchased gas adjustment clauses.
Management monitors the rate of return in each jurisdiction in order to
ensure the timely filing of rate adjustment applications.
Regulatory Proceedings
Maryland. OnIn July 31, 1995, Chesapeake'sChesapeakes Maryland division filed an
application with the Maryland Public Service Commission ("MPSC")
requesting a rate increase of $1,426,711 or 17.09%. The two largest
components of the increase were attributable to environmental costs and a
new customer information system, implemented in 1995. The request included a return on
equity of 13%.
On November 30, 1995, the MPSC issued an order approving a settlement
proposal of a $975,000 increase in annual base rates effective for gas
provided on or after December 1, 1995. As required in the settlement of
the rate case, the Company filed a cost of service study with the MPSC onin
June 28, 1996. The purpose of a cost of service study iswas to allocate revenue
among customer or rate classifications. The filing, alsowhich included
proposals for:for restructuring sales services that more closely reflect the
cost of serving commercial and industrial customers, the unbundling of gas
costs from distribution system costs, revisions to sharing of
interruptible margins between firm ratepayers and the Company and new
services that would allow customers using more than 30,000 Ccf of gas per
year to purchase gas from suppliers other than the Company.
After negotiations with MPSC staff and other interested parties, a
settlement was reached on most sales service issues and the Commission
approved a proposed order was issued by
the Hearing Examiner onin March 7, 1997. Commission action on the proposed order
is still pending. The settlement includes: 1. Class(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(2) unbundling of gas costs from distribution charges; 8
3. A(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. Interruptible(4) interruptible margins
will continue to be shared, 90% to customers and 10% to the Company, but
distribution costs incurred for incremental load additions can be
recovered with carrying charges utilizing 100% of the incremental margin
if the payback period is within three years.
At the request of MPSC staff, consideration of the new transportation
services has beenwere postponed becauseuntil Eastern Shore'sShores open access filing is still pending
beforewas
settled with the FERC.
It is expected that these services will be addressed in the
spring of 1997.
Delaware. OnIn April 4, 1995, Chesapeake'sChesapeakes Delaware division filed an
application with the Delaware Public Service Commission ("DPSC")
requesting a rate increase of $2,751,000 or 14% over current rates. The
largest component, representing a thirdone-third of the total requested increase, iswas
attributable to projected costs associated with the remediation proposed
by the Environmental Protection Agency ("EPA") of the site of a former
coal gas manufacturing plant operated in Dover, Delaware. The Company and
the DPSC agreed to separate the environmental recovery from the rate
increase so each could be addressed individually. OnIn December 20, 1995, the
DPSC approved an order authorizing a $900,000 increase to base rates
effective January 1,1996.
The Company had interim rates
subject to refund in effect starting June 3, 1995 to collect $1.0 million on
an annualized basis. A refund of $42,000 was calculated and used to offset
environmental costs incurred.
Also onIn December 20, 1995, the DPSC approved a recovery of environmental costs
associated with the Dover Gas Light Site by means of a rider (supplement)
to base rates. The DPSC approved a rider effective January 1, 1996 to
recover over five years all unrecovered environmental costs through
September 30, 1995 offset by the deferred tax benefit of these costs. The
deferred tax benefit equals the projected cashflow savings realized by the
Company in connection with a reduced income tax liability due to the
possibility of accelerated deduction allowed on certain environmental
costs when incurred. Each year, the rider rate will be calculated based on
the amortization of expenses for previous years. The advantage of the
environmental rider is that it is not necessary to file a rate case every
year to recover expenses.
OnIn December 15, 1995, Chesapeake'sChesapeakes Delaware division filed its rate design
proposal with the DPSC to initiate Phase II of this proceeding. The
principal objective of the filing was to prepare the Company for an
increasingly competitive environment anticipated in the near future when Eastern Shore
becomes an open access pipeline. This initial filing proposed new rate
schedules for commercial and industrial sales service, individual pricing
for interruptible negotiated contract rates, a modified purchased gas cost
recovery mechanism and a natural gas vehicle tariff.
OnIn May 15, 1996, the Delaware division filed its proposal relating to
transportation and balancing services with the DPSC, which proposed that
transportation of customer ownedcustomer-owned gas be available to all commercial and
industrial customers with annual consumption over 30,000 Ccf3,000 Mcf per year.
A tentative settlement proposal which was submitted to the DPSC Hearing
Examiner on November 22, 1996. On January 23, 1997 the DPSC Hearing Examiner
issued his proposed findings and recommendations supporting the parties
settlement proposal for final DPSC approval. OnIn February 4, 1997, the DPSC approved an order authorizing new service
offerings and rate design for services rendered on and after March 1,
1997. 9
The approved changes include: 1. Restructured(1) restructured sales services which
provide commercial and industrial customers with various service
classifications such as general service, medium volume, large volume and
high load factor services; 2. A(2) a modified purchased gas cost recovery
mechanism which takes into consideration the unbundling of gas costs from
distribution charges as well as charging certain firm service
classifications different gas cost rates based on a customers'the service
classifications load factor; 3. The(3) the implementation of a mechanism for
sharing interruptible, capacity release and off-system sales margins
between firm sales customers and the Company, with changing margin sharing
percentages based on the level of total margin; and 4. Provision(4) a provision for
transportation and balancing services for commercial and industrial
customers with annual consumption over 30,000 Ccf per year to transport
customer-owned gas on the Company'sCompanys distribution system.
Florida. On September 28, 1995,November 26, 1997, the Florida Division filed a request with
the Florida Public Service Commission issued an
order finalizing(FPSC) in Docket No. 971559-GU, for
a Limited Proceeding to Restructure Rates and for Approval of Gas
Transportation Agreements. The Florida Division has entered into Gas
Transportation Contracts with its two largest customers which resulted in
retaining these two customers on the Florida division's 1994 amount of overearnings. The
division was found to have exceeded its allowed rate of return equity ceiling of
12% by $62,000.Companys distribution system at
rates lower than previously achieved. As a result of an agreement reached February 6, 1995,this reduction in
revenue, the excess earnings were deferred until 1995. The same agreement cappedCompany has proposed in its application to restructure rates
for its remaining customers to more closely reflect the Florida
Division's 1995 return on equity at 12% plus or minus the resultcost of subtracting
the average yield of 30-year U.S. Treasury bondsservice
for the period of October,
Novembereach rate class and December, 1994 from the average yield of 30-year U.S. Treasury
bonds for October, November and December 1995, not to exceed 50 basis points in
either direction. As a result, the Florida Division's return on equity for 1995
was lowered to a midpoint of 10.5% for determiningrecover the level of overearnings.
For 1995,revenues previously
generated by the Florida Division was foundtwo Contract customers.
The Companys restructuring proposal is revenue neutral. Approval of this
request would not result in additional revenues to have exceededthe Company; however,
FPSC approval would enable the Company to retain its allowedtwo largest customers
while providing the Company with the opportunity to achieve its FPSC
authorized rate of return equity ceiling of 11.5% by $230,000. On January 21, 1997 the Florida
Public Servicereturn.
FPSC Staff issued their recommendation in this docket on March 12, 1998.
The Commission voted to allowapprove the division to apply the total
overearnings for 1994 and 1995 in the amount of $292,000 to its environmental
reserve. TheCompanys restructuring proposal on
March 24, 1998. A Commission Order affirmingin this decision was issued in February,
1997.docket is expected April 14, 1998.
(i) (c) Propane Distribution
Chesapeake'sChesapeakes propane distribution group consists of Sharp Energy, Inc.
("Sharp Energy"), a wholly owned subsidiary of Chesapeake, and its wholly
owned subsidiary, Sharpgas, Inc. ("Sharpgas"). and Tri-County Gas Company,
Inc. ("Tri-County") a wholly owned subsidiary of Chesapeake.
On March 6, 1997, Chesapeake acquired all of the outstanding shares of
Tri-
County Gas Company, Inc. ("Tri-County"),Tri-County a family-owned and operated propane distribution business
located in Salisbury and Pocomoke, Maryland. The combined operations of
the Company and Tri-County served approximately 32,00034,000 propane customers
on the Delmarva Peninsula and delivered approximately 30-million27 million retail
and wholesale gallons of propane during 1996.
Sharpgas stores and distributes propane to approximately 23,100 customers on the
Delmarva Peninsula.1997.
The propane distribution business is affected by many factors such as
seasonality, the absence of price regulation and competition among local
providers.
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-burningclean-
burning fuel, gaining increased recognition for its environmental
superiority, safety, efficiency, transportability and ease of use relative
to alternative forms of energy.
10
Propane is sold primarily in suburban and
rural areas which are not served by natural gas pipelines. Demand is
typically much higher in the winter months and is significantly affected by
seasonal variations, particularly the relative severity of winter temperatures,
because of its use in residential and commercial heating.
The Company purchasesAdequacy 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-
paytake-or-pay premiums) and maximum
purchase provisions.
The Company usesSharp Energy and Tri-County use trucks and railroad cars to transport
propane from refineries, natural gas processing plants or pipeline
terminals to the Company'sCompanys bulk storage facilities. From these facilities,
propane is delivered in portable cylinders or by "bobtail" trucks, owned
and operated by the Company,Companies, to tanks located at the customer'scustomers
premises.
Sharpgas competesCompetition
Sharp Energy and Tri-County compete with several other propane
distributors in itstheir 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 both fuel oil and electricity as an energy source.
Propane competes againstwith fuel oil based uponon its cleanliness and its environmental
advantages. Propane is also typically less expensive than both fuel oil
and electricity, based on equivalent BTU value. BecauseSince natural gas has
historically been less expensive than propane, propane is generally not
distributed in geographic areas serviced by natural gas pipeline or
distribution systems.
The Company'sCompanys propane distribution 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'sCompanys propane operations are subject to all operating hazards
normally incident toassociated with the handling, storage and transportation of
combustible liquids, such as the risk of personal injury and property
damage caused by fire. The Company carries general liability insurance in
the amount of $35,000,000 per occurrence, but there is no assurance that
such insurance will be adequate.
(i) (d) Advanced Information Services
Chesapeake'sChesapeakes advanced information services segment is comprised of United
Systems, Inc. ("USI") and Capital Data Systems, Inc. ("CDS"), both wholly
owned subsidiaries of the Company. CDS provided programming support for
application software, until the first quarter of 1997, at which time theyit
disposed of substantially all of theirits assets.
USI is an Atlanta-based company that primarily provides support for users
of PROGRESS/(R)/PROGRESS(TM), a fourth generation computer language and Relational Database
Management System. USI offers consulting, training, software development
"tools" and customer software development for its client base, which
includes many large domestic and international corporations.
11
Competition
The advanced information services businesses face significant competition
from a number of larger competitors having substantially greater resources
available to them than the Company. In addition, changes in the advanced
information services businesses are occurring rapidly, which could
adversely impact the markets for the Company'sCompanys products and services.
(i) (e) Other Subsidiaries
Skipjack, Inc. ("Skipjack") and Chesapeake Investment Company ("Chesapeake
Investment"), are wholly owned subsidiaries of Chesapeake Service Company.
Skipjack owns and leases to affiliates, two office buildings in Dover,
Delaware. Chesapeake Investment is a Delaware affiliated investment
company.
On March 6, 1997, in connection with the acquisition of Tri-County, the
Company acquired Eastern Shore Real Estate, Inc. ("ESR"), which will becomebecame a
wholly owned subsidiary of Chesapeake Service Company. ESR owns and leases
office buildings to affiliates and external companies.
(ii) Seasonal Nature of Business
Revenues from the Company'sCompanys 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
The Company's currentA discussion of capital budget for 1997 contemplates expenditures totaling
approximately $18.9 million. The total includes approximately $8.5 million for
Chesapeake's natural gas distribution divisions, consisting mainly of extensions
toby business segment is included in
Item 7 under the heading "Liquidity and replacements of the distribution facilities and related equipment; $4.5
million for natural gas transmission operations, providing principally for
improvements to the pipeline system and for finishing construction of a
compressor station in Delaware City, $3.8 million for environmental related
expenditures, $1.8 million for propane distribution, principally for the
purchase of storage facilities, additional tanks and the construction of a new
operation center in Pocomoke, Maryland; $150,000 for computer hardware,
furniture and fixtures for the Company's advanced information services group;
along with $150,000 for general plant. These capital requirements are expected
to be financed by cash flow provided by the Company's operating activities
short-term borrowing, and the issuance of long-term debt, common equity or a
combination thereof.Capital Resources".
(iv) Employees
The Company has 338397 employees, including 131114 in natural gas distribution,
employees,
18nine in natural gas transmission, employees, 97131 in propane distribution employees and 4963 in
advanced information services employees.services. The remaining 4380 employees are considered
general and administrative and include officers of the Company and
marketing, engineering, treasury, accounting, data processing, planning,
human resources and other administrative personnel. The acquisition of
Tri-County will add approximatelyadded 43 employees to the total number of employees of the
Company.
12
Item 2. Properties
(a) General
The Company owns offices and operates buildingsfacilities in Pocomoke, Salisbury,
Cambridge, and Princess Anne, Maryland; Dover, Seaford, Laurel and
Georgetown, Delaware; and Winter Haven, Florida, and rents office space in
Dover, Delaware; Plant City, Florida; Chincoteague and Belle Haven, Virginia;
Easton and Pocomoke, Maryland; Detroit, Michigan; 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'sCompanys facilities can
vary significantly due to the seasonal nature of the natural gas and propane
distribution businesses.
(b) Natural Gas Distribution
Chesapeake owns over 514542 miles of natural gas distribution mains (together
with related service lines, meters and regulators) located in its Delaware
and Maryland service areas, and 459469 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. A portion of the properties constituting Chesapeake'sChesapeakes
distribution system are encumbered pursuant to Chesapeake'sChesapeakes First Mortgage
Bonds.
(c) Natural Gas Transmission
Eastern Shore owns approximately 271 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 station is currently
under construction with a proposed in-service date of March 19,1997. The
Delaware City compressor facility
and associated piping are needed to stabilize capacity on Eastern Shore'sShores
system as a result of steadily declining inlet pressures at the Hockessin
interconnect with Transcontinental Gas Pipe Line Corporation. The Daleville
station is utilizedused to increase Columbia supply pressures to match Transco supply
pressures, and to increase Eastern Shore'sShores pressures in order to serve
Eastern Shore'sShores firm customers'customers demands, including demands from Chesapeake'sthose of Chesapeakes
Delaware and Maryland divisions. The Bridgeville station is being used to
provide increased pressures required to meet the
demands on the system.
(d) Propane Distribution
Sharpgas ownsand Tri-County own bulk propane storage facilities with an aggregate
capacity of 1,482,0001.9 million gallons at 2633 plant facilities in Delaware, Maryland
and Virginia, located on real estate itthey either ownsown or leases.lease.
Item 3. Legal Proceedings
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.
13
Environmental
(a) Dover Gas Light Site
In 1984, the State of Delaware notified the Company that a parcel of land it
purchased in 1949 from Dover Gas Light Company, a predecessor gas company,
containscontained hazardous substances. The State also asserted that the Company is
responsible for any clean-up and prospective environmental monitoring of the
site. The Delaware Department of Natural Resources and Environmental Control
("DNREC") investigated the site and surroundings, finding coal tar residue
and some ground-water contamination.
In October 1989, the Environmental Protection Agency Region III ("EPA")
listed the Dover Site on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA" or
"Superfund"). At that time under CERCLA, both the State of Delaware and the
Company were named as potentially responsible parties ("PRP"PRPs") for clean-up
of the site.
The EPA issued the site Record of Decision ("ROD") dated August 16, 1994. The
remedial action selected by the EPA in the ROD addressesaddressed the ground-water
contamination with a combination of hydraulic containment and natural
attenuation. Remediation selected for the soil at the site iswas to meet
stringent cleanup standards for the first two feet of soil and less stringent
standards for the soil below two feet. The ROD estimatesestimated the costs of
selected remediation of ground-water and soil at $2.7 million and $3.3
million, respectively.
On November 18, 1994, EPA issued a "Special Notice Letter" (the "Letter") to
Chesapeake and three other PRPs. The Letter includes, inter alia, (1) a demand
----- ----
for payment by the PRPs of EPA's past costs (estimated to be approximately
$300,000) and future costs incurred overseeing Site work; (2) notice of EPA's
commencement of a 60 day moratorium on certain EPA response activities at the
Site; (3) a request by EPA that Chesapeake and the other PRPs submit a "good
faith proposal" to conduct or finance the work identified in the ROD; and (4)
proposed consent orders by which Chesapeake and other parties may agree to
perform the good faith proposal.
In January 1995, Chesapeake submitted to the EPA a good faith proposal to
perform a substantial portion of the work set forth in the ROD, which was
subsequently rejected . The Company and the EPA each attempted to secure
voluntary performance of part of the remediation by other parties. These
parties include the State of Delaware, which is the owner of the property and
was identified in the ROD as a PRP, and a business identified in the ROD as a
PRP for having contributed to ground-water contamination.
On May 17, 1995, EPA issued an order to the Company under section 106 of CERCLA
(the "Order"), which requiresrequired the Company to fund or implement the ROD. The
Order was also issued to General Public Utilities Corporation, Inc. ("GPU"),
which both EPA and the Company believe is liable under CERCLA. Other PRPs
such as the State of Delaware were not ordered to perform the ROD. EPA may
seek judicial enforcement of its Order, as well as significant financial
penalties for failure to comply. Although notifying EPA of objections to the
Order, the Company agreed to comply. GPU informed EPA that it doesdid not intend
to comply with the Order.
OnIn March 6, 1995, the Company commenced litigation against the State of Delaware
for contribution to the remedial costs being incurred to carry out the ROD.
In December of 1995, this case was dismissed without prejudice based on a
settlement agreement between the parties (the "Settlement"). Under the
Settlement, the State agreed to support the Company'sCompanys proposal to reduce the
soil remedy for the site, described below, to contribute $600,000 toward the
cost of implementing the ROD and to 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 being reached
14
within the next two years.Delaware. Upon satisfaction of all
conditions of the Settlement, the litigation will be dismissed with
prejudice.
On July 7, 1995, the Company submitted to EPA a study proposing to reduce the
level and cost of soil remediation from that identified in the ROD. Although
this proposal was supported by the State of Delaware, as required by the
Settlement, it was rejected by the EPA on January 30, 1996.
OnIn June 25, 1996, the Company initiated litigation against GPU for contribution
to the remedial costs incurred by Chesapeake in connection with complying
with the ROD. At this time, management cannot predict the outcome of the
litigation or the amount, if any, of proceeds to be received.
In July 1996, the Company commencedbegan the design phase of the ROD, on-site pre-
design and investigation. A pre-design investigation report ("the report")
was filed in October 1996 with the EPA. The report, which requiresrequired EPA
approval, will provideprovided up to date status on the site, which the EPA will useused to
determine if the remedial design selected in the ROD iswas still the
appropriate remedy.
In the report, the Company proposed a modification to the soil clean-up
remedy selected in the ROD to take into account an existing land use
restriction banning future development at the site. In April of 1997, the EPA
issued a fact sheet stating that the EPA was considering the proposed
modification. The fact sheet included an overall cost estimate of $5.7
million for the proposed modified remedy and a new overall cost estimate of
$13.2 million for the remedy selected in the ROD. On August 28, 1997, the EPA
issued a Proposed Plan to modify the current clean-up plan that would
involve: (1) excavation of off-site thermal treatment of the contents of the
former subsurface gas holders; (2) implementation of soil vaporization
extraction; (3) pavement of the parking lot; and (4) use of institutional
controls that would restrict future development of the Site. The overall
estimated clean-up cost of the Site under the proposed plan was $4.2 million,
as compared to EPAs estimate of the current clean-up plan at $13.2 million.
In January 1998, the EPA issued a revised ROD, which modified the soil
remediation to conform to the proposed plan and included the estimated clean-
up costs of $4.2 million.
The Company is currently engaged in investigations related to additional
parties who may be PRPs. Based upon these investigations, the Company will
consider suit against other PRPs. The Company expects continued negotiations
with PRPs in an attempt to resolve these matters.
In the third quarter of 1994, theThe Company increasedadjusted its accrued liability recorded with respect to the Dover
Site to $6.0$4.2 million. This amount reflects the EPA'sEPAs estimate, as stated in
the ROD issued in 1998 for remediation of the site according to the ROD. The
recorded liability may be adjusted upward or downward as the design phase
progresses and the Company obtains construction bids for performance of the
work. The Company has also recorded a regulatory asset of $6.0$4.2 million,
corresponding to the recorded liability. Management believes that in addition
to the $600,000 expected to be contributed by the State of Delaware under the
Settlement, the Company will be equitably entitled to contribution from other
responsible parties for a portion of the expenses to be incurred in
connection with the remedies selected in the ROD. Management also believes
that the amounts not so contributed will be recoverable in the Company'sCompanys
rates.
As of December 31, 1996,1997, the Company has incurred approximately $4.2$5.0 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 beginning in 1990.period. In December 1995, the Delaware
Public Service Commission, authorized recovery of all unrecovered
environmental cost incurred by a means of a rider (supplement) to base rates,
applicable to all firm service customers. The costs would be recovered
through a five-year amortization offset by the deferred tax benefit
associated with those environmental costs. The deferred tax benefit equals
the projected cashflow savings realized by the Company in connection with a
reduced income tax liability due to the possibility of accelerated deduction
allowed on certain environmental costs when incurred. Each year a new rider
rate will beis calculated to become effective December 1. The rider rate will beis based on
the amortization of expenditures through September of the filing years plus
amortization of expenses from previous years. The advantage of the rider is
that it is not necessary to file a rate case every year to recover expenses
incurred. As of December 31, 1996,1997, the unamortized balance and amount of
environment costenvironmental costs not included in the rider, effective January 1, 19971998 was
$1,206,000$2.1 million and $191,000,$190,000, respectively. With the rider mechanism
established, it is management'smanagements opinion that these costs and any future cost,
net of the deferred income tax benefit, will be recoverable in rates.
15
(b) Salisbury Town Gas Light Site
In cooperation with the Maryland Department of the Environment ("MDE"), the
Company has completed an assessment, construction and has begun remediation of
the Salisbury manufactured gas plant site. The assessment determined that
there was localized contamination of ground-water. A remedial design report
was submitted to MDE in November 1990 and included a proposal to monitor,
pump and treat any contaminated ground-water on-site. Through negotiations
with the MDE, the remedial action workplanwork plan was revised with final approval
from MDE obtained in early 1995. The remediation process for ground-water was
revised from pump-and-treat to Air Sparging and Soil-Vapor Extraction,
resulting in a substantial reduction in overall costs. During 1996, the
Company completed construction and began remediation procedures at the
Salisbury site and will behas been reporting on an ongoing basis the remediation and monitoring results
to the Maryland Department of the Environment.Environment on an ongoing basis.
The cost of remediation is estimated to range from $140,000 to $190,000 per
year for operating expenses. Based on these estimated costs, the Company
recorded both a liability and a deferred regulatory asset of $650,088$665,000 on
December 31, 1996,1997, to cover the Company'sCompanys projected remediation costs for
this site. The liability payout for this site is expected to be over a five-yearfive-
year period. As of December 31, 1996,1997, the Company has incurred approximately
$2.2$2.4 million for remedial actions and environmental studies and has charged
such costs to accumulated depreciation. In January 1990, the Company entered
into settlement agreements with a number of insurance companies resulting in
proceeds to fund actual environmental costs incurred over a three to five-yearfive-
year period beginning in 1990. The final insurance proceeds were requested
and received in 1992. In December 1995, the Maryland Public Service
Commission approved recovery of all environmental cost incurred through
September 30, 1995 less amounts previously amortized and insurance proceeds.
The amount approved for a 10-year amortization was $964,251. Of the $2.2$2.4
million in costs reported above, approximately $417,000$597,000 has not been
recovered through insurance proceeds or received ratemaking treatment. It is
management'smanagements opinion that these costs incurred and future costs incurred, if
any, will be recoverable in rates.
(c) Winter Haven Coal Gas Site
The Company is currently conducting investigations of a site in Winter Haven,
Florida, where the Company's predecessors manufactured coal gas earlier this
century. A Contamination Assessment Report ("CAR") was submitted to the Florida
Department of Environmental Protection ("FDEP") in July, 1990. The CAR
contained the results of additional investigations of conditions at the site.
These investigations confirmed limited soil and ground-water impacts to the
site. In March 1991, FDEP directedMay 1996, the Company to conduct additional
investigations on-site to fully delineate the vertical and horizontal extent of
soil and ground-water impacts.
Additional contamination assessment activities were conducted at the site in
late 1992 and early 1993. In March 1993, a Contamination Assessment Report
Addendum ("CAR Addendum") was delivered to FDEP. The CAR Addendum concluded
that soil and ground-water impacts have been adequately delineated as a result
of the additional field work. The FDEP approved the CAR and CAR Addendum in
March of 1994. The next step is a Risk Assessment ("RA") and a Feasibility
Study ("FS") on the site. A draft of the RA and FS were filed with the FDEP
during 1995; however, until the RA and FS are not complete until accepted as
final by the FDEP. On May 10, 1996, CFGC transmitted to FDEP an Air Sparging and Soil Vapor Extraction
Pilot Study Work Plan for FDEP's review and approval.the Winter Haven site with the Florida Department
of Environmental Protection ("FDEP"). The Work Plan described CFCG'sthe Companys
proposal to undertake an Air Sparging and Soil Vapor Extraction ("AS/SVE")
pilot study to evaluate the effectiveness of air sparging as a
groundwater remedy combined with soil vapor extraction at the Property. CFGC is
currentlysite. After discussions with the FDEP, the
Company filed a modified AS/SVE Pilot Study Work Plan, scope of work to
complete the site assessment activities and a report describing a limited
sediment investigation performed recently. The Company will be awaiting
FDEP'sFDEPs comments to the modified Work Plan. It is not possible to determine
whether remedial action will be required by FDEP and, if so, the cost of such
remediation.
16
The company has spent and received ratemaking treatment of approximately
$678,000 on these investigations as of September 30, 1997. The Company has
spent approximately $660,000, as of December 31, 1996, on these
investigations, and expects to recover these expenses, as well as any future
expenses, through base rates. These costs have been accounted for as charges to
accumulated depreciation. The Company requested and received fromallowed by the Florida Public Service Commission ("FPSC") approval to amortize through base rates
$359,659 of clean-up and removal costs incurred as of December 31, 1986. As of
December 31, 1992, these costs were fully amortized. In January 1993, the
Company received approval to recover through base rates approximately $217,000
in additional costs related to the former manufactured gas plant. This amount
represents recovery of $173,000 of costs incurred from January 1987 through
December 1992, as well as prospective recovery of estimated future costs which
had not yet been incurred at that time. The FPSC has allowed for amortization
of these costs over a three-year period and provided for rate base treatment for
the unamortized balance. In a separate docket before the FPSC, the Company has
requested and received approval to apply a refund of 1991 overearnings of
approximately $118,000 against the balance of unamortized environmental charges
incurred as of December 31, 1992. As a result, these environmental charges were
fully amortized as of June 1994. The FPSC issued an order in January 1997,
applying a refund of $292,000, pertaining to 1994 and 1995 overearnings, toward
the balance of unamortized environmental charges. Of the $660,000 in costs
reported above, all costs have received ratemaking treatment. The FPSC has
allowed the Company to continue to accrue
for future environmental costs. At December 31, 1996,September 30, 1997, the Company has $396,000had
$432,000 accrued. It is management'smanagements opinion that future costs, if any, will be recoverable in rates.
(d) Smyrna Coal Gas Site
On August 29, 1989 and August 4, 1993, representatives of DNREC conducted
sampling on property owned by the Company in Smyrna, Delaware. This property is
believed to be the location of a former manufactured gas plant. Analysis of the
samples taken by DNREC show a limited area of soil contamination.
On November 2, 1993, DNREC advised the Company that it would require a
remediation of the soil contamination under the state's Hazardous Substance
Cleanup Act and submitted a draft Consent Decree to the Company for its review.
The Company met with DNREC personnel in December 1993 to discuss the scope of
any remediation of the site and, in January 1994, submitted a proposed workplan,
together with comments on the proposed Consent Decree. The final Work Plan was
submitted on September 27, 1994. DNREC has approved the Work Plan and the
Consent Decree. Remediation based on the Work Plan was completed in 1995, at a
cost of approximately $263,000. In June 1996, the Company received the
certificate of completion from DNREC. It is management's opinion that these
costs will
be recoverable in rates.
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 10. Executive Officers of the Registrant
Information pertaining to the Executive Officers of the Company is as
follows:
Ralph J. Adkins (age 54) (present term expires May 20, 1997).
---------------55) Mr. Adkins is PresidentChairman of the Board and Chief
Executive Officer of Chesapeake. He has served as PresidentChairman of the Board
and Chief Executive Officer since November 8, 1990.August 1997. Prior to holding his
present position, Mr. Adkins served as 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 also Chairman and Chief Executive Officer of Chesapeake Service
Company, and Chairman and Chief Executive Officer of Sharp Energy, Inc.,
Tri-County Gas Company, Inc., Chesapeake Service Company and Eastern Shore
Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He has
been a director of Chesapeake since 1989.
17
John R. Schimkaitis (age 49) (present term expires May 20, 1997).
- -------------------50) Mr. Schimkaitis is Executive Vice President and Chief
Operating Officer and
Assistant Treasurer.Officer. He has served as President since August 1997. He
previously served as Executive Vice President, since February
23, 1996. He previously served as 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.
Philip S. Barefoot (age 50) (present term expires May 20, 1997).
- ------------------
Mr. Barefoot joined Chesapeake as Division Manager of Florida Operations in July
1988. In May 1994 he was elected Senior Vice President of Natural Gas
Operations, as well as Vice President of Chesapeake Utilities Corporation. Prior
to joining Chesapeake, he was employed with Peoples Natural Gas Company where he
held the positions of Division Sales Manager, Division Manager and Vice
President of Florence Operations.
Michael P. McMasters (age 38) (present term expires May 20, 1997).
- --------------------39) 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 37) Mr. Thompson is Vice President of the Natural
Gas Operations, as well as Vice President of Chesapeake Utilities
Corporation. He has served as Vice President since May 1997. He has served
as President, Vice President, Manager, Director of Gas Supply and
Marketing and Superintendent of Eastern Shore and Regional Manager for the
Florida distribution Operations.
Philip S. Barefoot (age 51) Mr. Barefoot joined Chesapeake as Division
Manager of Florida Operations in July 1988. In May 1994 he was elected
Vice President of Chesapeake Utilities Corporation. Prior to joining
Chesapeake, he was employed by Peoples Natural Gas Company where he held
the positions of Division Sales Manager, Division Manager and Vice
President of Florence Operations.
Jeremy D. West (age 48) Mr. West joined Chesapeake as President of Sharp
Energy in June 1990. In May 1992 he was elected Vice President of
Chesapeakes Propane Operations and in May 1997, he was promoted to Vice
President of Strategic Planning and Acquisitions. Prior to joining
Chesapeake, he was employed by Columbia Propane Corporation, a subsidiary
of Columbia Gas System, as Vice President of Marketing, and later,
President of Columbia Propane Corporation. He has also serviced as
Regional Manager of Suburban Propane.
PART II
Item 5. Market for the Registrant'sRegistrants Common Stock and Related Security Holder
Matters
(a) Common Stock Dividends and Price Ranges:
The following table sets forth sale price and dividend information for each
calendar quarter during the years December 31, 1997 and 1996:
- ---------------------------------------------------------------------------
Dividends
Declared
Quarter Ended: High Low Close Per Share
- ---------------------------------------------------------------------------
1997
March 31 $18.000 $16.500 $17.375 $0.2425
June 30 17.500 16.000 17.000 0.2425
September 30 18.500 16.250 18.375 0.2425
December 31 21.750 18.375 20.500 0.2425
- ---------------------------------------------------------------------------
1996
and 1995:
- ---------------------------------------------------------
Dividends
Declared
Quarter Ended High Low Close Per Share
- ---------------------------------------------------------
1996
- ---------------------------------------------------------
March 31 $17.000 $14.500 $16.750 $0.2325
June 30 17.875 15.875 16.000 0.2325
September 30 17.750 15.125 17.500 0.2325
December 31 18.000 16.375 16.875 0.2325
- ---------------------------------------------------------
1995
- ---------------------------------------------------------
March 31 $13.625 $12.125 $13.250 $0.2250
June 30 13.375 12.250 13.125 0.2250
September 30 14.375 12.250 14.000 0.2250
December 31 15.500 14.000 14.625 0.2250
- ---------------------------------------------------------
March 31 $17.000 $14.500 $16.750 $0.2325
June 30 17.875 15.875 16.000 0.2325
September 30 17.750 15.125 17.500 0.2325
December 31 18.000 16.375 16.875 0.2325
- ---------------------------------------------------------------------------
The common stock of the Company trades on the New York Stock Exchange under
the symbol "CPK".
(b) Approximate number of holders of common stock as of December 31, 1996:
Number of Shareholders
Title of Class of Record
-------------- --------
Common stock, par value $.4867 2,213
18
1997:
Number of Shareholders
Title of Class of Record
--------------------------- ----------------------
Common stock, par value $.4867 2,178
(c) Dividends:
During the years ended December 31, 19961997 and 1995,1996, cash dividends paid by
Chesapeake have been declared each quarter, in the amounts set forth in the
table above. During 1996 and 1995, Tri-County paid dividends of $79,000 and
$592,000, respectively.
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, 1996,1997, the amounts available for future dividends
permitted by the Series I covenant are $13.0$14.6 million.
(d) On March 6, 1997, in conjunction with the acquisition of Tri-County Gas
Company, Inc., the Company issued 639,000 shares of Company stock to William
P. Schneider and James R. Schneider in reliance on the private placement
exemption provided by Section 4(2) of the Securities Act of 1933 and
Regulation D, thereunder.
19
Item 6. Selected Financial Data
Finacial Highlights page from Annual Report, followed by Annual Report MD&A
FINANCIAL HIGHLIGHTS
Item 6. Selected Financial Data
- ----------------------------------------------------------------------------------------------------------------------------
(Dollars--------------------------------------------------------------------------------------------------
(dollars in Thousands Except Stock Data)thousands except stock data)
For the Years Ended December 31, 1997 1996 1995 1994 (1) 1993 1992(1)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating
Operating revenues $119,330 $104,020$122,775 $130,213 $111,796 $98,572 $85,873
$75,935
Operating income $9,244 $9,562$8,559 $10,110 $10,067 $7,227 $6,311 $5,770
Income before cumulative effect of
change in accounting principle and discontinued operations $6,910 $7,237$5,683 $7,605 $7,594 $4,460 $3,914 $3,475
Cumulative effect of change in
accounting principle $58
Income from discontinued operations $74
Net income $6,910 $7,237$5,683 $7,605 $7,594 $4,460 $3,972
$3,549
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
Gross plant $127,961 $115,283$143,345 $133,001 $119,837 $110,023 $100,330
$91,039
Net plant $90,564 $81,716$99,517 $93,570 $84,589 $75,313 $69,794
$64,596
Total assets $131,138 $118,794$137,379 $136,046 $123,339 $108,271 $100,988 $89,557
Long-term debt, net $38,226 $28,984 $29,795$31,619 $24,329 $25,682 $25,668
Common stockholders' equity $47,153 $42,301$50,336 $47,537 $42,582 $37,063 $34,878
$33,126
Capital expenditures $14,302 $12,100$11,381 $14,837 $12,887 $10,653 $10,064
$6,720
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Common Stock
PrimaryBasic earnings per share:
Income before cumulative effect of
change in accounting principle and discontinued operations $1.82 $1.95$1.27 $1.72 $1.75 $1.23 $1.10 $1.00
Cumulative effect of change in
accounting principle $0.02
Income from discontinued operations $0.02
Net income $1.82 $1.95$1.27 $1.72 $1.75 $1.23 $1.12
$1.02
Average shares outstanding 3,793,467 3,701,981 3,632,413 3,556,037 3,477,244
Fully dilutedDiluted earnings per share:
Income before cumulative effect of
change in accounting principle and discontinued operations $1.76 $1.89$1.24 $1.67 $1.70 $1.20 $1.08 $0.99
Cumulative effect of change in
accounting principle $0.02
Income from discontinued operations $0.02
Net income $1.76 $1.89$1.24 $1.67 $1.70 $1.20 $1.10 $1.01
Average shares outstanding 4,037,048 3,950,724 3,888,190 3,816,295 3,749,1304,472,087 4,412,137 4,336,431 3,628,056 3,551,932
Cash dividends per share $0.97 $0.93 $0.90 $0.88 $0.86 $0.86
Book value per share $12.41 $11.37$11.18 $10.71 $9.77 $10.15 $9.76 $9.50
Common equity/Total capitalization 61.93% 58.67%56.80% 62.10% 57.40% 60.37% 57.59% 56.34%
Return on equity 14.66% 17.11%11.29% 16.00% 17.80% 12.03% 11.39%
10.71%
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Other
Number of Employees 338 335397 386 383 320 326 317
Number of Registered Stockholders 2,178 2,213 2,098 1,721 1,743
1,674
Heating Degree Days 4,418 4,717 4,593 4,398 4,705 4,645
Heating Degree Days (10-year average) 4,577 4,596 4,586 4,564 4,588
4,598
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(1) 1994 and 1993 have not been restated to include the business combination
with Tri-County Gas Company, Inc.
20
Item 7. Management'sManagements Discussion and Analysis of Financial Condition
and Results of Operations
Liquidity and Capital Resources
The Company's capital requirements of Chesapeake Utilities Corporation ("Chesapeake"
or "the Company") reflect the capital intensivecapital-intensive nature of its business and
are attributable principally to itsthe construction program and the retirement
of its outstanding debt. The Company relies on cash generated from operations
and short-term borrowingsborrowing to meet normal working capital requirements and
to temporarily finance capital expenditures. During 1996, the Company's1997, net cash provided by
operating activities, net cash used by investing activities and net cash providedused by financing
activities were $11.3$12.3 million, $14.1$12.4 million and $3.7$1.5 million, respectively.
On January 23, 1997, theThe Board of Directors increased the amounthas authorized the Company was
authorized to borrow up to $20.0
million from various banks and trust companies from $14.0 million
to a ceiling of $20.0 million.companies. As of December 31, 1996, the Company1997,
Chesapeake had four unsecured bank lines of credit, each in the amount of $8,000,000. Funds
provided from these lines of credit are usedtotaling $34.0 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 borrowingsborrowing at December 31, 1997 and 1996 and 1995 were $12.0$7.6
million and $4.8$12.7 million, respectively.
Based upon
anticipatedIn 1997, Chesapeake used cash requirements in 1997, the Company may refinance the short-term
debtprovided by operations and provide 1997 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 marketdebt to fund capital expenditures and economic conditions.
Inreduce short-term borrowing.
During 1996, the Company used cash provided by operating activities coupled withand
short-term borrowingsborrowing to fund the capital expenditures and increases in
working capital requirements.
The increase in workingDuring 1997, 1996 and 1995, capital was primarily due to the
significant increase inexpenditures were approximately $12.8
million, $14.8 million and $12.9 million, respectively. Chesapeake has
budgeted $15.6 million for capital expenditures during 1998. This amount
includes $8.7 million and $2.7 million for natural gas and propane
prices during the fourth quarter
of 1996. In 1995, the Company's capital additions were funded by operating
activities. In 1994, cash provided by operations increased due to the
collection of a large amount of underrecovered purchased gas costs present at
the end of 1993.
During 1996, 1995 and 1994, capital expenditures were approximately $14,302,000,
$12,100,000 and $10,653,000, respectively. For 1997, the Company has budgeted
$18.9 million for capital expenditures. This amount includes $8.5 million for
natural gas distribution, $4.5respectively; $3.1 million for natural gas transmission,
$3.8
million for environmental related expenditures, $1.8 million for propane
distribution, $150,000$395,000 for advanced information services and $150,000$632,000 for general plant.
The natural gas and propane distribution expenditures are for expansion and
improvement of facilities in existing service territories. Natural gas
transmission expenditures are for improvement and expansion of the pipeline
system
and completion of the Delaware City compressor station.system. The advanced information services expenditures are for computer
hardware, software and related equipment. Financing for the 19971998
construction program is expected to be provided from short-term borrowings,borrowing
and cash from operations and from an
issuance of long-term debt.operations. The construction program is subject to continuous
review and modification. Actual construction expenditures may vary from the
above estimates due to a number of factors including inflation, changing
economic conditions, regulation, loadsales growth and the cost and availability
of capital.
The Company expects to incurChesapeake has budgeted $2.8 million for environmental related expenditures
during 19971998 and expects to incur additional expenditures in future years
(see Note J to the Consolidated Financial Statements), a portion of which
may need to be financed through external sources. 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, 1996,1997, common equity represented 61.9%56.8% of permanent
capitalization compared to 58.7%62.1% in 19951996 and 60.4%57.4% in 1994. The Company1995. Chesapeake
remains committed to maintaining a sound capital structure and strong credit
ratings in order to provide the financial flexibility needed to access the capital
markets when required. This 21
commitment, along with adequate and timely rate
relief for the Company'sCompanys regulated operations, helps to ensure that
the CompanyChesapeake 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'sCompanys investors.
Financing Activities
OnIn December 1997, Chesapeake finalized a private placement of $10 million of
6.85% Senior Notes due January 1, 2012. The Company used the proceeds to
repay a portion of its short-term borrowing. In October 2, 1995, the Company
finalized a private placement of $10 million of 6.91% Senior Notes due in
2010. The Company used the proceeds to retire $4,091,000$4.1 million of the 10.85%
Senior Notes of Eastern Shore Natural Gas Company, the Company'sCompanys natural gas
transmission subsidiary ("Eastern Shore"), originally due October 1,in 2003. The
remaining proceeds of $5,909,000 were used to repay short-
term borrowings under the Company's lines of credit.reduce short-term borrowing. The Company
issued no long-term debt in 1996 and 1994.1996. During 1996,1997, the Company repaid
a total of
approximately $869,000$3.1 million of long-term debt, compared to $5,018,000$823,000 and $1,291,000$5.4
million in 19951996 and 1994,1995, respectively. The increase in debt payments for
1997 resulted from the payoff of $2.2 million of debt assumed in the pooling
of interests with Tri-County Gas Company, Inc. ("Tri-County").
On March 6, 1997, the Company acquired all of the outstanding common stock
of Tri-County and associated properties. Tri-County distributes propane to
both retail and wholesale customers on the peninsula. The transaction was
effected through the exchange of 639,000 shares of the Companys common
stock and was accounted for as a pooling of interests.
Chesapeake issued 32,169, 33,926 38,660 and 30,92838,660 shares of common stock in
connection with its Automatic Dividend Reinvestment and Stock Purchase Plan
during the years of 1997, 1996 1995 and 1994,1995, respectively.
Results of Operations
Net income for 19961997 was $6,910,428,$5,682,946 as compared to $7,236,695$7,604,915 for 1996. The
decrease in net income is primarily related to temperatures in the Companys
northern service territory, which were, on average, 6% warmer than in 1996.
The warmer weather resulted in a reduction in volumes sold by the natural
gas and propane distribution segments. The lower gas volumes contributed to
the reduction in Earnings Before Interest and Taxes ("EBIT") for both
distribution segments as shown in the table below.
EARNINGS BEFORE INTEREST AND TAXES (in thousands):
- -------------------------------------------------------------------------------------------------------
Increase/ Increase/
For the Years Ended December 31, 1997 1996 (decrease) 1996 1995 (decrease)
- -------------------------------------------------------------------------------------------------------
EBIT by Business Segment:
Natural gas distribution $5,498 $7,167 ($1,669) $7,167 $4,728 $2,439
Natural gas transmission 3,721 2,458 1,263 2,458 6,083 (3,625)
Propane distribution 1,064 2,815 (1,751) 2,815 2,252 563
Advanced information services 1,046 1,056 (10) 1,056 1,061 (5)
Other 558 561 (3) 561 (32) 593
- -------------------------------------------------------------------------------------------------------
Total EBIT $11,887 $14,057 ($2,170) $14,057 $14,092 ($35)
=======================================================================================================
Chesapeakes 1996 net income was $7,604,915, as compared to $7,593,506 for
1995. Exclusive of matters relatingAlthough net income was relatively unchanged, the contribution to net
income from each business segment differed during the settlement and associated accruals
described below, earningstwo-year period.
Natural gas distribution EBIT was higher in 1996 due to rate increases
placed in effect in two of the three service territories during 1995. EBIT
for the propane distribution segment increased by $320,969. Thedue to greater volumes sold
due to temperatures being 3% colder than in 1995. Natural gas transmissions
contribution decreased due to a reduction in volumes sold to industrial
interruptible customers during 1996. In addition, 1995 net income reflected theincludes a
one-time benefit from a settlement between Eastern Shore andwith the Federal Energy Regulatory
Commission ("FERC") regarding Eastern Shore's purchased gas adjustment ("PGA")
computation. This settlement, which was a non-recurring event, contributed
$833,000 to 1995 net income due(see Note K to the reversal of the excess liability for a
potential refund previously recorded, and resulted in a reduction in the
required level of accruals from $750,000 after tax in 1994 to $186,000 after tax
in 1995. Earnings before interest and taxes ("EBIT") for the years 1996, 1995
and 1994 were $13.2 million, $13.6 million and $9.8 million.Consolidated Financial Statements).
Natural Gas Distribution
The reduction in EBIT of $1.7 million from 1996 to 1997 is primarily related
to a decline in total gross margin, as indicated in the following table,
coupled with an overall increase in expenses. The reduction in gross margin
earned on volumes sold is primarily the result of a 3% decline in volumes
sold to residential and commercial customers and a decrease in volumes sold
to industrial interruptible customers in Chesapeakes Florida service
territory. The reduction in volumes sold to residential and commercial
customers was directly related to warmer temperatures, primarily during the
first quarter of 1997. Operations and maintenance expenses increased
$633,000 and $108,000, respectively. Compensation, regulatory commission
expenses and costs related to data processing and billable service revenue
contributed to the increase in operations expenses. A greater level of
maintenance to the gas pipeline system resulted in an increase in
maintenance expenses.
The $2.4 million rise in EBIT from 1995 to 1996 resulted from an increase in
gross margin earned on sales of natural gas distribution segment contributed EBITin two of $7.2 million in 1996
compared to $4.7 million in both 1995 and 1994. TheChesapeakes three
service territories, offset by an overall increase in EBITexpenses. The $4.0
million increase in 1996
was due to higher gross margin was partially offset by higher operating expenses.
Gross margin in 1996 increased $4.0 million due to a full year of rate
increases, which went into effect in 1995. Maryland operations rates became
effective during December and interim rates were in effect during June of
1995 coupled with afor Delaware operations. In addition, colder temperatures contributed
to the 20% increase in deliveries to residential and commercial customers
located in the Company'sChesapeakes northern service territory. The rate increase became effective during December,
1995 for Maryland operations and interim rates were in effect during June, 1995
for Delaware operations. The rate increases were designed to increase revenues
$975,000 and $900,000 annually for the Maryland and Delaware operations,
respectively. The$583,000 increase in
deliveries to residential and commercial
customers located inoperations expenses was primarily the Company's northern service territory was related to
temperatures which were colder than the previous year.
Gross margin in 1995 increased $1.7 million due to the partial yearresult of rate
increases for the Maryland and Delaware operations in 1995 and an increase of
88% and 23% in transportation and delivery volumes, respectively, by the Florida
distribution operations. These increases in Florida's volumes reflected sales
to phosphate producing and citrus processing customers and to three co-
generation plants.
Operations expenses for 1996 increased by $583,000 or 7% after increasing by
$1.2 million or 16% in 1995 over 1994. The 1996 increases related tohigher compensation,
benefits, data processing costs, uncollectiblesbad debts and regulatory expenses. The increases in 1995 related to compensation, data processing
conversion costs, consulting, legal and regulatory expenses.
22
Maintenance expenses were slightly less in 1996 compared to 1995, when expenses
were $66,000 or 7% higher than 1994 expenses due to a greater level of
maintenance on meter and regulating stations. Depreciation and amortization
expense increased due to plantPlant
additions placed in service during the past two
years. Other1996 resulted in higher depreciation
expense. In addition, other taxes increased by $460,000 or 23% in 1996,, partially
due to the inclusion of certain state revenue related taxes, in 1996.which were
previously included as reductions to revenue.
GROSS MARGIN SUMMARY (in thousands)
- -------------------------------------------------------------------------------------------------------
Increase/ Increase/
For the Years Ended December 31, 1997 1996 (decrease) 1996 1995 (decrease)
- -------------------------------------------------------------------------------------------------------
Revenues:
Gas sold $54,205 $52,290 $1,915 $52,290 $42,784 $9,506
Gas transported 3,061 2,991 70 2,991 2,618 373
Gas marketed 18,419 19,382 (963) 19,382 8,555 10,827
Other 275 193 82 193 168 25
- -------------------------------------------------------------------------------------------------------
Total Revenues $75,960 $74,856 $1,104 $74,856 $54,125 $20,731
=======================================================================================================
Cost of Sales:*
Gas sold $35,507 $32,846 $2,661 $32,846 $26,789 $6,057
Gas marketed 18,233 19,117 (884) 19,117 8,410 10,707
- -------------------------------------------------------------------------------------------------------
Total Cost of Sales $53,740 $51,963 $1,777 $51,963 $35,199 $16,764
=======================================================================================================
Gross Margin:
Gas sold $18,698 $19,444 ($746) $19,444 $15,995 $3,449
Gas transported 3,061 2,991 70 2,991 2,618 373
Gas marketed 186 265 (79) 265 145 120
Other 275 193 82 193 168 25
- -------------------------------------------------------------------------------------------------------
Total Gross Margin $22,220 $22,893 ($673) $22,893 $18,926 $3,967
=======================================================================================================
* Transportation service does not have an associated cost of sales.
Natural Gas Transmission
The Companys natural gas transmission segment, contributedEastern Shore, which became
an open access pipeline on November 1, 1997, had an increase in EBIT of $2.5$1.3
million $6.1
millionfor 1997. The rise in EBIT is partially attributable to a rate
increase and $3.0 million during 1996, 1995 and 1994, respectively. The largean increase in 1995 EBIT includes the effectfirm services implemented in 1997, as well as an
overall reduction in expenses. The rate increase is designed to generate
additional gross margin of the settlement between Eastern
Shore and the FERC regarding Eastern Shore's PGA computation (see Note Kapproximately $1.2 million annually. Also
contributing to the Consolidated Financial Statements). The settlement, which was a non-recurring
event, contributedincrease in EBIT were additional revenues generated by
the increase in transportation services that were effective with the
implementation of open access. On an annual basis, the additional services
will generate revenue of approximately $1.3 million to EBIT for 1995million. Operations expense
decreased by $143,000 or 5%, primarily consisting of compensation,
relocation costs and property insurance. Maintenance expenses were also
lower due to reduced maintenance required during the reversal of excess
liability foryear on the potential refund previously recorded, andgas
pipeline system. Capital additions during the year resulted in a
reduction in the required level of accruals from $1.2higher
depreciation expense.
The $3.6 million in 1994 to
$289,000 in 1995. Exclusive of matters relating to the settlement and
associated accruals, EBIT decreased $2.6 million in 1996, increased $890,000 in
1995 and increased $1.1 million in 1994.
The reduction in 1996 EBIT of $2.6 million was primarily the result of a
decrease indue to lower gross
margin on sales to industrial customers. Contributing to the
increases in 1995 and 1994 EBIT were increased gross margins, primarily
attributable to increased deliveries of industrial sales volumes, offset
slightly by higher operating expenses.
The decline in 1996 gross margin resulted fromdecreased due to a
67% decreasereduction in volumes delivered, primarily reflecting decreasedlower deliveries to
two industrial interruptible customers -- a municipal power plant and a
methanol plant. The methanol plant shut down operations on April 1, 1996.
The management of the
methanol plant has indicated that they would monitor methanol prices and would
re-evaluate their position as to reopening or permanently closing on or about
April 1, 1997. To our knowledge, no decision has been made regarding reopening
or permanently closing the methanol plant. During 1996 1995 and 1994,1995, deliveries to the methanol and power plants
contributed approximately $284,000 and $2.4 million, respectively to gross
margin
approximately $284,000, $2.4 million and $1.4 million, respectively. These two
customers aremargin. As interruptible customers, and havethey had no ongoing commitment,
contractual or otherwise, to purchase natural gas from the Company (see Note
A to the Consolidated Financial Statements). Operations expense increased 4%The $109,000 increase in
1996, primarily reflectingoperating expenses reflects increased compensation and benefit related
expenses. Operations expenseDepreciation increased by
$314,000 or 14% in 1995 compared to 1994. The majority of the increases were in
payroll, telemetering and legal fees.
Maintenance expense declined slightly in 1996 after declining by $47,000 or 8%
in 1995. Maintenance expenses in 1994 increased by $125,000 due to the painting
of a pipeline bridge structure and a higher level of natural gas main
maintenance. Depreciation expense increased in 1996 due to plant placed in service during the past two years.
On October 15, 1996,service.
With Eastern Shore filed with the FERC for a rate increase of
approximately $1,445,000. This increase would be effective for only revenues
earned on salesShores conversion to regulated customers.
In connection with the FERC Order relating to the settlement, Eastern Shore
applied in December of 1995 to the FERC for a blanket certificate authorizing open access, transportation service on its pipeline system. The implementation
of open access transportation service, expected to occur during 1997, will
provide all of Eastern Shore'sits customers withwill
have the opportunity to transport gas over its system at FERCrates regulated rates. Open access is thus likelyby
the FERC. The variability in Eastern Shores margins, historically driven by
the sales to result
in a shift of Eastern Shore's business from margins earned on sales of gas to
large industrial customers, to a possibly lower margin earned onwill dramatically decrease, as capacity
reservation fees for transportation services. After the implementation of open access, itservices will drive prospective margins.
It is expected that Eastern
Shore's earnings, which in the past have been driven to a substantial extent by
widely varying levels of unregulated sales,future, Eastern Shores EBIT will tend to be more
stable and closerresemble a fully regulated return. Taking the 1997 rate increase,
revenues associated with additional capacity and lower margins on services
provided to industrial customers into account, the Company expects gross
margin during 1998 to be between $7.9 and $8.2 million (see Cautionary
Statement). Comparatively, gross margin for the past three years has been
$7.9 million, $6.7 million and $10.2 million for 1997, 1996 and 1995,
respectively.
Propane Distribution
In 1997, Chesapeake integrated the operations of Tri-County and the
Companys existing propane distribution operations. Like Chesapeakes
existing propane operations, Tri-Countys earnings are heavily dependent
upon weather conditions.
The reduction in 1997 EBIT of $1.8 million was primarily due to a regulated return.
23
Propane Distributionreduction
in gross margin, partially offset by a reduction in expenses. Gross margin
decreased due to an 11% reduction in sales volumes coupled with a 13% lower
margin per gallon sold. The propane distribution segment contributed EBITdecline in sales volumes is directly related to
the warmer temperatures, which averaged 6% warmer than the prior year.
Furthermore, during the first quarter of $2.1 million, $1.9 million
and $2.3 million for 1996, 1995 and 1994, respectively.1997 temperatures were 14% warmer
than normal. The 1996 increaseCompany normally sells a high percentage of its annual
volume during this period. The reduction in EBITmargin per gallon sold was primarilyalso
the result of an increaseabnormally warmer temperatures. As temperatures warmed during
the first quarter, demand decreased and supply-prices declined rapidly. Due
to the low cost of wholesale-supply, retail prices declined, thereby
reducing margins. Operations expenses decreased $554,000 or 7% primarily in
gross margin mostly offset by
greater operating expenses. The 1995 decreasethe areas of compensation, delivery related costs, advertising and legal
fees. Maintenance expenses declined primarily in EBIT was a combined impact of
a decrease in gross margin coupled with greater operating expenses.
The increase in gross margin of $1.1 millionequipment and structures.
Depreciation and amortization expenses declined $477,000 or 12% for 1996 was28% primarily
the result of a non-compete agreement, which became fully amortized in
November of 1996.
The increase in 1996 EBIT of $563,000 is primarily attributable to a rise in
gross margin partially offset by higher expenses. Gross margin was higher
due to a 12% increase in sales volumes duesold and a slight increase in margin earned
per gallon sold. The increases are directly related to temperatures beingwhich
were 3% colder than the previous year. The decreasethose in gross margin of $281,000 for 1995 was1995. Operating expenses increased $1.3 million
or 19% in 1996 primarily due to a 4% decline in sales volume, partially offset by a higher
average margin per gallon. Overall, temperatures in 1995 were 4% colder than
temperatures in 1994, yet volumes were lower due to the timing and severity of
weather conditions experienced in 1994. In 1995, the segment did not secure a
contract with one wholesale customer under which it had supplied large
quantities of propane, contributing $64,000 to gross margin, in 1994.
Operations expense for 1996 increased by $766,000 or 14% after increasing by
$225,000 or 4% in 1995. The increase in expenses for 1996 and 1995 occurred
primarily in compensation, delivery related costs,
benefits and outside services. Maintenance expenses increased by $84,000 or 28% in 1996 after reducing by $42,000 or 12% in 1995.
The maintenance expense increases occurred primarily on vehicles.
Starting in 1997, the Company will be integrating the operationsareas
of Tri-County
Gas Company, Inc. ("Tri-County"), acquired on March 6, 1997,propane storage facilities, equipment and the Company's
current propane distribution operations.structures.
Advanced Information Services
The advanced information services segment contributed EBIT of $1.3 million, $1.2
million and $174,000 for the years 1996, 1995 and 1994. During 1996, revenue
and operating expenses decreased by $1.4 million and $1.5 million, respectively.
These declines resulted from the segment no longer providing facilities
management services during 1996. These 1996 declines were partially offset by
increases in consulting and programming revenues along with associated operating
expenses, such as compensation, benefits and reimbursed costs.
In 1995 revenues increased due to higher consulting and programming revenues,
placement services and non-recurring revenue earned by providing services to a
large facilities management customer. These services were provided during a
period of system conversion by this customer in connection with the termination
of its contract. Operating expenses declined in 1995 due to downsizing efforts
at the Company's North Carolina operation to change the focus from a product
development and facilities management company to a fixed price contract
programming services company.
Included in the results of the advanced information services segment consisted primarily
of those of United Systems, Inc. ("USI"), due to the downsizing of
Chesapeakes North Carolina operations in early 1997. Although the EBIT
contribution of this segment has remained unchanged from 1996 to 1997, USIs
gross margin has increased by $970,000 or 34%. Operating expenses increased
due to the opening of a new office in Detroit, Michigan and the expansion of
staff training and marketing efforts to position USI to be able to provide
new services and for future growth of current services. Since the years ended December 31, 1996, 1995 and 1994 were intersegment revenues of
$711,000, $1,722,000 and $2,277,000, respectively, which were eliminatedrise in
consolidation. The intercompany LBIT (Loss Before Interest and Taxes) connected
with the developmentoperating costs offset most of the Company's natural gas distribution billing system,
whichgrowth in gross margin, EBIT remained
constant.
Although the EBIT contributed by the advanced information segment was
finalizedrelatively unchanged from 1995 to 1996, EBIT contributed by USI increased
$268,000. This was mostly offset by a reduction in EBIT contributed by the
North Carolina operation as they ceased to provide facilities management
services beginning in early 1996.
Income Taxes
Operating income taxes in 1997 decreased $619,000 due to a reduction in
EBIT. This was partially offset by the one-time expense of $318,000 recorded
in 1997 to establish the deferred income tax liability for Tri-County. Prior
to 1997, Tri-County was a subchapter S Corporation for income tax reporting;
therefore, no deferred income taxes were recorded on its balance sheet. In
addition, the Companys 1996 and 1995 restated financial statements do not
include any income tax expense for Tri-County due to its subchapter S status
during 1995, totaled $165,000 and $468,000 for the years
1995 and 1994, respectively.those years.
Other
Non-operating income was $379,000, $357,000$428,000, $458,000 and $16,000$391,000 for 1997, 1996 1995 and
1994,1995, respectively. The 1995 increase wasdecrease in 1997 is primarily due to a one-time termination fee
paid to the advanced information services segment by its largest facilities
management customerreduction in
connection with a change in control of that customer.
This was somewhat
24
interest income, partially offset by costs to downsize the operation to no longer provide facilities
management servicegain on the sale of fixed assets.
The increase in connection with its Page-IT/(TM)/ software.1996 is primarily the result of a rise in interest income
earned partially offset by a reduction in the gain on sales of fixed assets.
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 J to the Consolidated
Financial Statements). The Company believes that any future costs associated
with these sites will be recoverable in rates.
The Year 2000
Chesapeake is dependent upon information systems to operate efficiently and
effectively. In order to address the impact of the year 2000 on its many
information systems, Chesapeake is in the process of evaluating and
remediating any deficiencies. The Company has segregated the evaluation of
its readiness and the potential impact of the year 2000 on its systems into
two components: primary internal applications and other applications. The
Companys primary applications include systems for its financial
information; natural gas customer information and billing; and propane
customer information, billing and delivery. Other applications include
systems for services such as telephone, system control and data acquisition
for the pipeline, as well as other vendors systems. With respect to the
three primary applications, Chesapeake has updated its propane customer
information, billing and delivery system to a year 2000 compliant version.
This system will be tested further to insure compliance during 1998. With
respect to the other two primary applications, Chesapeake has conducted
initial evaluations and estimates that the cost of any remediation will not
be significant. Each application will be tested during 1998. Chesapeake has
developed an inventory of other applications and is in the process of
developing plans to contact its vendors, test and remediate to the extent
necessary.
Competition
Historically, the Company'sCompanys natural gas operations have successfully
competed with other forms of energy such as electricity, oil and propane.
The principalprinciple considerations have been price, and to a lesser extent,
accessibility. SinceAs a result of Eastern Shore has only recently electedShores recent conversion to open
access, the Company expects to be an open access pipeline, with
implementation during 1997, the Company has not previously been subject to the competitive pressures from
other sellers of natural gas. Upon implementation ofWith open access transportation services
available on Eastern Shore'sShores system, third party suppliers will compete with
the CompanyChesapeake to sell gas to the local distribution companies and the end users
on Eastern Shore'sShores system. Eastern Shore will shifthas shifted from providing sales
service to providing transportation and contract storage and transportation
services.
The Company'sCompanys distribution operations located in Delaware and Maryland will then
face the possibility of the unbundling of theirbegan to offer
transportation services to certain industrial customers thus increasingin December 1997.
Chesapeake expects that during 1998, the competition for salesdistribution operations located in
Maryland will also begin offering transportation services. The Company
has
already addressed these issuesexpects to expand the availability of transportation services to additional
customers in 1994 and 1993 in itsthe future. Since the Florida distribution operation, whenoperations have been
open to certain industrial customers since 1994, the Company was required to unbundle its services to large
industrial customers.has gained
experience in operating in an open access environment. The Company
established a natural gas brokering and supplysupplies operation in Florida to
compete for these customers' business.customers. The Company is evaluating whether to establish
similar services in our northern service territory.
Both the propane distribution and the advanced information services
businesses face significant competition from a number of larger competitors
with substantially greater resources available to them than those of the
Company. In addition, in the advanced information services business, changes
are occurring rapidly, which could adversely impactaffect the markets for the
Company'sCompanys services.
Inflation
Inflation impactsaffects the prices the Company must pay forcost of labor and other goods and services required
for operation, maintenance and capital improvements. In
recent years, however, theThe impact of inflation
has lessened in recent years, except for itsthe effect on purchased gas costs. Although historically stable, these costs were
higher in 1996.
These costs are passed on to customers through the purchased gas adjustment
clause in the Company'sCompanys tariffs. To help cope with the effects of inflation
on its capital investments and returns, the Company seeks rate relief from
its regulatory commissions for its regulated operations and
constantly monitorswhile monitoring the returns
of its unregulated business operations.
Cautionary Statement
Statements made herein and elsewhere in this Form 10-K, which are not
historical fact, are forward lookingforward-looking statements. In connection with the
"Safe Harbor" provisions of the Private Securities Litigation Reform Act of
1995, the CompanyChesapeake is providing the following cautionary statement to identify
important factors that could cause its actual results to differ materially from
those anticipated in forward lookingforward-looking statements made herein or otherwise by
or on behalf of the Company.
A number of factors and uncertainties make it difficult to predict the
effect on future operating results of Eastern Shore operating as an open
access pipeline, relative to historical results, of Eastern Shore
becoming anresults. While open access
pipeline. First, while open access is likely to
diminisheliminates industrial interruptible sales margins, such sales have varied
widely from year to year and, in future years, might makehave made a less
significant contribution to earnings even in the absence of open access.
Second, the level
of regulated
25
transportation rates that will be in effect under open access has not yet been
determined. Third, the outcome of Eastern Shore's rate increase filing with
FERC for an increase in revenue earned on sales to regulated customers has not
yet been determined. Fourth,Additionally, there are a number of uncertainties, including the
outcome offuture open
access proceedings and the effects of competition, which will affect whether
the Company will be able to provide economical gas marketing, transportation
and other services.
In addition, a number of factors and uncertainties affecting other aspects
of the Company'sCompanys business could have a material impact on earnings. With respect
to the acquisition of Tri-County, these include: actual performance for the
future periods, the actual costs of the acquisition and the ability of the
combined company to execute the integration and realize the expected synergies.
With respect to the Company's business in general, theseThese
include: the seasonality and temperature sensitivity of ourChesapeakes natural
gas and propane businesses, the relative price of alternative energy sources
and the effects of competition on both on our unregulated businesses and on natural gas sales,
oncenow that the Company operates in an open access environment. 26
There are also
uncertainties relative to the impact of the year 2000 on the information
systems of the Company, its vendors and other third parties.
Item 8. Financial Statements and Supplemental Data
REPORT OF INDEPENDENT ACCOUNTANTS
________
To the Stockholders of
Chesapeake Utilities Corporation
We have audited the accompanying consolidated balance sheetsfinancial statements and
consolidated financial statement schedules of Chesapeake
Utilities Corporation and Subsidiaries as of December 31, 1996 and
1995, and the related consolidated statements of income, cash flows,
stockholders' equity, and income taxes for each of the three years in the period
ended December 31, 1996, and the consolidated financial statement schedule
listed in Item 14(a)(1) and (2) of
this Form 10-K. These financial statements and the financial
statement scheduleschedules are the responsibility of the Company'sCompanys
Management. Our responsibility is to express an opinion on these
financial statements and the financial statement scheduleschedules based
on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards 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. An audit also includes assessing the accounting
principles used and significant estimates made by Management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Chesapeake Utilities Corporation and
Subsidiaries as of December 31, 19961997 and 1995,1996, and the
consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 19961997 in
conformity with generally accepted accounting principles. In
addition, in our opinion, the consolidated financial statement
scheduleschedules referred to above, when considered in relation to the
basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information
required to be included therein.
We have also previously audited, in accordance with
generally accepted standards, the consolidated balance sheets and
statements of capitalization as of December 31, 1995, 1994 1993 and
1992,1993, and the related consolidated statements of income, cash
flows, common stockholders'stockholders equity, and income taxes for each of the two
years in the period ended December 31, 19931994 (none of which are
presented herein) and we expressed unqualified opinions on those
consolidated financial statements. In our opinion, the
information set forth in the Financial Highlights included in the
Selected Financial Data for each of the five years in the period
ended December 31, 1996,1997, appearing on page 2017 is fairly stated in
all material respects in relation to the financial statements
from which it has been derived.
CoopersCOOPERS & LybrandLYBRAND L.L.P.
Baltimore, Maryland
February 13, 1997
2712, 1998
CONSOLIDATED BALANCE SHEETS
Assets
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
At December 31, 1997 1996
1995
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Natural gas distribution $70,497,872 $64,785,616$74,769,458 $69,853,054
Natural gas transmission 33,856,873 30,655,492 25,651,558
Propane distribution 21,101,579 19,645,97326,920,403 25,279,217
Advanced information services 841,757 1,003,850
841,661Other plant 6,161,631 5,414,249
Gas plant acquisition adjustment 795,004 795,004
Other plant 3,907,657 3,563,247
------------------------------------------ ----------------------------------------------------------------------------------------------
Total property, plant and equipment 127,961,454 115,283,059143,345,126 133,000,866
Less: Accumulated depreciation and amortization (37,397,752) (33,567,446)
-----------------------------------------(43,827,961) (39,430,738)
- ----------------------------------------------------------------------------------------------
Net property, plant and equipment 90,563,702 81,715,613
-----------------------------------------99,517,165 93,570,128
- ----------------------------------------------------------------------------------------------
Investments 2,721,443 2,263,068
1,957,218
------------------------------------------ ----------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 1,952,998 977,407555,198 2,213,529
Accounts receivable (less allowance for uncollectibles
13,328,333 12,701,256
of $331,775 and $392,412 in 1997 and $309,955 in 1996, and 1995, respectively) 13,087,999 14,488,944
Materials and supplies, at average cost 1,160,522 844,7861,380,120 1,284,876
Propane inventory, at average cost 2,129,914 1,442,6332,288,516 2,345,531
Storage gas prepayments 2,926,618 3,731,680 2,663,721
Underrecovered purchased gas costs 1,673,389 2,192,170
Income taxes receivable 112,902 193,916849,623 112,942
Prepaid expenses 801,939 842,4601,060,911 942,359
Deferred income taxes 247,487 158,010
1,362,289
------------------------------------------ ----------------------------------------------------------------------------------------------
Total current assets 25,568,468 21,028,468
-----------------------------------------24,069,861 27,470,041
- ----------------------------------------------------------------------------------------------
Deferred Charges and Other Assets
Environmental regulatory assets 4,865,073 6,650,088 7,113,572
Environmental expenditures, net 2,372,929 1,778,348 1,505,140
Order 636 transition cost 943,209 1,463,157
Other deferred charges and intangible assets 3,371,027 4,010,812
-----------------------------------------3,832,389 4,314,235
- ----------------------------------------------------------------------------------------------
Total deferred charges and other assets 12,742,672 14,092,681
-----------------------------------------11,070,391 12,742,671
- ----------------------------------------------------------------------------------------------
Total Assets $131,137,910 $118,793,980
=========================================$137,378,860 $136,045,908
==============================================================================================
See accompanying notes
Capitalization and Liabilities
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
At December 31, 1997 1996
1995
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Capitalization
Stockholders' equity
Common stock $1,849,626 $1,811,211$2,191,792 $2,160,628
Additional paid-in capital 18,848,851 17,592,24219,819,604 18,745,718
Retained earnings 26,780,831 23,385,09728,218,763 26,957,048
Less: Unearned compensation related to restricted stock awarded (190,886) (364,529) (415,107)
Unrealized gain (loss) on marketable securities, net 296,872 38,598
(72,839)
---------------------------------------------- ----------------------------------------------------------------------------------------------
Total stockholders' equity 47,153,377 42,300,60450,336,145 47,537,463
Long-term debt, net of current portion 38,226,000 28,984,368
29,794,639
---------------------------------------------- ----------------------------------------------------------------------------------------------
Total capitalization 76,137,745 72,095,243
---------------------------------------------88,562,145 76,521,831
- ----------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 791,271 864,849582,500 3,078,489
Short-term borrowings 12,000,000 4,800,000borrowing 7,600,000 12,700,000
Accounts payable 13,176,126 11,162,77512,451,570 14,426,983
Refunds payable to customers 357,041 353,734 966,940
Accrued interest 784,533 741,768 742,701
Dividends payable 1,092,168 883,621 837,358
Overrecovered purchased gas costs 53,374
Other accrued expenses 3,447,397 3,123,191
---------------------------------------------3,807,484 3,733,233
- ----------------------------------------------------------------------------------------------
Total current liabilities 31,393,917 22,551,188
---------------------------------------------26,675,296 35,917,828
- ----------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 11,490,358 9,798,676 9,136,808
Deferred investment tax credits 821,617 876,432 931,247
Environmental liability 4,865,073 6,650,088 7,113,572
Order 636 transition liability 943,209 1,463,157
Accrued pension costs 1,866,660 2,118,5451,754,715 1,866,661
Other liabilities 3,471,183 3,384,220
---------------------------------------------3,209,656 4,414,392
- ----------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 23,606,248 24,147,549
---------------------------------------------22,141,419 23,606,249
- ----------------------------------------------------------------------------------------------
Commitments and Contingencies
(Notes J and K)
Total Capitalization and Liabilities $131,137,910 $118,793,980
=============================================$137,378,860 $136,045,908
==============================================================================================
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
1994
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $119,330,068 $104,020,416 $98,572,297
----------------------------------------------------------$122,774,593 $130,213,409 $111,795,778
Cost of Sales 77,764,830 82,226,644 65,616,368
- -----------------------------------------------------------------------------------------------------------
Gross Margin 45,009,763 47,986,765 46,179,410
- -----------------------------------------------------------------------------------------------------------
Operating Expenses
Purchased gas costs 72,530,507 58,454,410 59,013,165
Operations 22,954,470 21,387,989 19,681,43521,831,194 22,230,425 20,612,585
Maintenance 2,014,106 2,079,121 2,181,4042,041,043 2,504,894 2,477,454
Depreciation and amortization 5,101,823 5,461,752 5,140,6795,396,975 5,504,637 5,802,884
Other taxes 3,538,402 3,050,351 2,798,9053,853,954 3,689,748 3,194,673
Income taxes 3,946,9863,327,627 3,947,056 4,025,274
2,529,635
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total operating expenses 110,086,294 94,458,897 91,345,223
----------------------------------------------------------36,450,793 37,876,760 36,112,870
- -----------------------------------------------------------------------------------------------------------
Operating Income 9,243,774 9,561,519 7,227,0748,558,970 10,110,005 10,066,540
- -----------------------------------------------------------------------------------------------------------
Other Income
Interest income 174,359 141,161 123,271239,543 249,509 191,845
Other income, and (deductions), net 173,231 256,237 (144,038)405,156 177,045 239,687
Income taxes (216,988) (83,739) (105,280) (12,733)
Allowance for equity funds used during construction 115,434 65,198
49,154
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total other income 379,285 357,316 15,654
----------------------------------------------------------427,711 458,249 391,450
- -----------------------------------------------------------------------------------------------------------
Income Before Interest Charges 9,623,059 9,918,835 7,242,728
----------------------------------------------------------8,986,681 10,568,254 10,457,990
- -----------------------------------------------------------------------------------------------------------
Interest Charges
Interest on long-term debt 2,347,369 2,392,458 2,282,247 2,322,942
Amortization of debt expense 119,401 120,345 109,399
103,859
Other 264,148 383,976 426,242922,110 514,856 566,320
Allowance for borrowed funds used during construction (85,145) (64,320) (93,482)
(70,237)
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total interest charges 2,712,631 2,682,140 2,782,806
----------------------------------------------------------3,303,735 2,963,339 2,864,484
- -----------------------------------------------------------------------------------------------------------
Net Income $6,910,428 $7,236,695 $4,459,922
==========================================================$5,682,946 $7,604,915 $7,593,506
===========================================================================================================
Earnings Per Share of Common Stock (1):
Primary:
Earnings per share $1.82 $1.95 $1.23
Average shares outstanding 3,793,467 3,701,891 3,632,413
Fully diluted:
Earnings per share $1.76 $1.89 $1.20
Average shares outstanding 4,037,048 3,950,724 3,888,190Stock:
Basic: $1.27 $1.72 $1.75
Diluted: $1.24 $1.67 $1.70
See accompanying notes
30
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
1994
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income $6,910,428 $7,236,695 $4,459,922$5,682,946 $7,604,915 $7,593,506
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization 5,782,759 5,905,090 5,786,0136,090,665 6,148,232 6,246,222
Allowance for equity funds used during construction (115,434) (65,198) (49,154)
Investment tax credit adjustments (54,815) (54,815) (54,815)
Deferred income taxes, net 1,794,1471,437,206 1,794,146 252,727 (669,404)
Employee benefits 471,869(238,826) 471,870 178,803 492,082
Employee compensation from lapsing of stock restrictions 173,643 334,745 431,694 374,121
Allowance for refund (1,356,705)
1,238,705
Other, net 438,510 (339,080) 424,832(286,147) 83,301 (339,081)
Changes in assets and liabilities:
Accounts receivable, net (627,077) (4,284,963) 1,303,5171,400,945 (904,516) (4,727,364)
Other current assets (1,949,441) 1,380,216 (979,125)648,282 (2,141,048) 1,588,675
Other deferred charges (502,491)(625,395) (977,652) (946,450) (271,937)
Accounts payable, net 1,300,252 3,149,573 382,913(1,823,912) 1,422,807 3,619,023
Refunds payable to customers 3,307 (613,206) 399,123 59,999
(Underrecovered)400,192
Overrecovered (underrecovered) purchased gas costs 518,781 (2,245,544) 162,399 1,723,432
Other current liabilities 369,536 948,846 159,910
----------------------------------------------------------(619,668) 396,326 939,750
- -----------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 11,294,238 12,997,955 14,381,011
----------------------------------------------------------12,307,012 11,204,127 13,923,378
- -----------------------------------------------------------------------------------------------------------
Investing Activities
Property, plant and equipment expenditures, net (14,045,947) (11,691,192) (10,473,565)(12,380,826) (14,069,116) (11,666,442)
Allowance for equity funds used during construction 115,434 65,198
49,154
Purchases of investments (36,167) (129,406) (38,836)
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Net cash used by investing activities (14,059,919) (11,664,830) (10,424,411)
----------------------------------------------------------(12,416,993) (14,083,088) (11,640,080)
- -----------------------------------------------------------------------------------------------------------
Financing Activities
Common stock dividends, net of amounts reinvested of $555,121, $506,941$382,932,
$346,308 and $427,190$304,106 in 1997, 1996 and 1995, and 1994, respectively (2,959,573) (2,791,373) (2,736,388)
Sale(3,829,752) (3,337,755) (3,324,376)
Issuance of stock 369,709 254,484 201,704-- Dividend Reinvestment Plan optional cash 167,337 208,813 202,835
Issuance of stock -- Retirement Savings Plan 404,297 349,031
Net (repayments) borrowings (repayments) under line of credit agreements 7,200,000 (3,200,000) (900,000)(5,100,000) 7,300,000 (3,197,039)
Proceeds from issuance of long-term debt 10,000,000
Repayments9,908,223 10,428,753
Repayment of long-term debt (868,864) (5,017,580) (1,285,962)
----------------------------------------------------------(3,098,455) (823,213) (5,439,151)
- -----------------------------------------------------------------------------------------------------------
Net cash used(used) provided by financing activities 3,741,272 (754,469) (4,720,646)
----------------------------------------------------------(1,548,350) 3,696,876 (1,328,978)
- -----------------------------------------------------------------------------------------------------------
Net (Decrease) Increase (Decrease) in Cash and Cash Equivalents 975,591 578,656 (764,046)(1,658,331) 817,915 954,320
Cash and Cash Equivalents at Beginning of Year 977,407 398,751 1,162,797
----------------------------------------------------------2,213,529 1,395,614 441,294
- -----------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $1,952,998 $977,407 $398,751
==========================================================$555,198 $2,213,529 $1,395,614
===========================================================================================================
Supplemental Disclosure of Cash Flow Information
Cash paid for interest $2,660,595 $2,657,972 $2,652,323$3,203,709 $2,831,109 $2,884,864
Cash paid for income tax $3,400,479 $2,122,120 $3,288,895 $3,509,034
See accompanying notes
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
1994
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Common Stock
Balance -- beginning of year $1,811,211 $1,785,514 $1,754,547$2,160,628 $2,122,212 $2,096,515 (1)
Dividend Reinvestment PlantPlan 15,398 16,514 18,816 15,046
USI restricted stock award agreements 10,639 6,881
15,778
Conversion of debentures 4,461 429 143
Company's Retirement Savings Plan 9,92711,305 9,928
Exercised stock options 906
----------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Balance -- end of year 1,849,626 1,811,211 1,785,514
----------------------------------------------------2,191,792 2,160,628 2,122,212
- -----------------------------------------------------------------------------------------------------------
Additional Paid-in Capital
Balance -- beginning of year 17,592,242 16,834,823 15,850,31918,745,718 17,489,108 16,731,689 (1)
Dividend Reinvestment PlantPlan 529,453 538,607 488,125 412,144
USI restricted stock award agreements 344,570 176,029 458,335
Sale of treasury stock to Company's
Retirement Savings Plan 93,265
109,184
Conversion of debentures 151,441 14,557 4,841
Company's Retirement Savings Plan 328,464392,992 328,465
Exercised stock options 30,411
----------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Balance -- end of year 18,848,851 17,592,242 16,834,823
----------------------------------------------------19,819,604 18,745,718 17,489,108
- -----------------------------------------------------------------------------------------------------------
Retained Earnings
Balance -- beginning of year 23,385,09726,957,048 23,458,776 19,480,374 18,219,083
Net income 6,910,428 7,236,695 4,459,9225,682,946 7,604,915 7,593,506 (1)
Cash dividends (1)-- Chesapeake (2) (4,341,964) (3,514,694) (3,331,972)
(3,198,631)
----------------------------------------------------Cash dividends -- Pooled companies (79,267) (591,949) (283,132)
- -----------------------------------------------------------------------------------------------------------
Balance -- end of year 26,780,831 23,385,097 19,480,374
----------------------------------------------------28,218,763 26,957,048 23,458,776
- -----------------------------------------------------------------------------------------------------------
Treasury Stock Balance -- beginning of year (99,842) (192,362)
Sale of treasury stock to Company's
Retirement Savings Plan 99,842 92,520
-------------------------------
Balance -- end of year (99,842)
-------------------------------(3)
Unearned Compensation
Balance -- beginning of year (364,529) (415,107) (696,679) (663,557)
Issuance of award (284,167) (121,343)
(474,113)
Amortization of prior years' awards 173,643 334,745 402,915
440,991
----------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Balance -- end of year (190,886) (364,529) (415,107)
(696,679)
----------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Unrealized Gain (Loss) on Marketable Securities (2)(4) 296,872 38,598 (72,839)
(241,609)
----------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $47,153,377 $42,300,604 $37,062,581
====================================================$50,336,145 $47,537,463 $42,582,150
===========================================================================================================
(1) The following adjustments have been made to 1995 presentation to reflect the Tri-County pooling of
interests: Begining balances of Common Stock and Additional Paid-in Capital have been adjusted by
$311,001 and ($103,314), respectively. Net income as shown in the Retained Earnings section has
been adjusted by $356,811.
(2) Dividends per share of common stock were $.97, $.93 and $.90 for the years 1997, 1996
and 1995, respectively.
(3) The entire Treasury Stock balance of ($99,842) was sold to the Company's Retirement Savings Plan
during 1995, leaving a zero balance.
(4) Net of income tax expense (benefit) of approximately $190,000, $25,000 and ($48,000) for the
the years 1997, 1996 and 1995, respectively.
(1) Dividends per share of common stock were $.93, $.90 and $.88 for the years
1996, 1995 and 1994, respectively.
(2) Net of income tax expense (benefit) of approximately $25,000, ($48,000) and
($160,000) for the years 1996, 1995 and 1994, respectively.
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME TAXES
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
1994
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Current Income Tax Expense
Federal $1,916,654 $1,884,609 $3,182,346
$2,375,332
State 442,563 356,576 621,238 707,190
Investment tax credit adjustments, net (54,815) (54,815) (54,815)
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total current income tax expense 2,304,402 2,186,370 3,748,769
3,027,707
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Deferred Income Tax Expense
Property, plant and equipment 1,335,802 581,373 455,151 383,306
Deferred gas costs (204,170) 873,904 (56,915) (656,772)
Pensions and other employee benefits (19,508) 107,131 57,508
(169,731)
Alternative minimum tax 230,575
Unbilled revenue (104,632) 54,320 (260,922) 188,356
Contributions in aid of construction (33,028) (6,979) (283,033)
(32,345)
Environmental expenditures 249,417 108,578 272,068 (22,067)
Allowance for refund 121,671 442,064
(580,361)
Other 4,35716,332 4,427 (244,136)
173,700
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total deferred income tax expense (1) 1,844,3551,240,213 1,844,425 381,785
(485,339)
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total Income Tax Expense $4,030,725$3,544,615 $4,030,795 $4,130,554
$2,542,368
==========================================================
(1) Total deferred income tax expense includes $392,000, $108,000 and $66,000
of deferred state income taxes for the years 1996, 1995 and 1994,
respectively.
===========================================================================================================
Reconciliation of Effective Income Tax Rates
Federal income tax expense at 34% 3,719,992 3,864,864 2,380,7793,171,505 3,956,118 3,986,180
State income taxes, net of Federal benefit 505,481 530,471 322,105399,213 537,566 546,955
Acquisition of subchapter S Corporation (2) 317,821 (268,211) (137,800)
Other (194,748)(343,924) (194,678) (264,781)
(160,516)
----------------------------------------------------------- -----------------------------------------------------------------------------------------------------------
Total income tax expense $4,030,725$3,544,615 $4,030,795 $4,130,554
$2,542,368
=====================================================================================================================================================================
Effective income tax rate 38.4% 36.8% 36.3%
36.3%- ----------------------------------------------------------------------------------------------
At December 31, 1997 1996
- ----------------------------------------------------------------------------------------------
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment $12,095,782 $10,716,757 $10,363,259
Deferred gas costs 649,681 853,851
Other 1,560,988 1,322,272
1,149,563
--------------------------------------- ----------------------------------------------------------------------------------------------
Total deferred income tax liabilities 14,306,451 12,892,880
11,512,822
--------------------------------------- ----------------------------------------------------------------------------------------------
Deferred income tax assets:
State operating loss carryforwards 57,303 3,320 126,073
Deferred investment tax credit 403,789 426,565 454,590
Unbilled revenue 968,311 863,679 918,001
Pension and other employee benefits 898,060 917,568 1,024,698
Self insurance 585,995 545,836
529,559
Other 150,122 495,246
685,382
--------------------------------------- ----------------------------------------------------------------------------------------------
Total deferred income tax assets 3,063,580 3,252,214
3,738,303
--------------------------------------- ----------------------------------------------------------------------------------------------
Deferred Income Taxes Per Consolidated Balance Sheet $11,242,871 $9,640,666
$7,774,519
====================================================================================================================================
(1) Includes $208,000, $392,000 and $108,000 of deferred state income taxes for
the years 1997, 1996 and 1995, respectively.
(2) Accounted for as a pooling of interests (see Note B to the Consolidated
Financial Statements).
See accompanying notes
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Accounting Policies
Nature of Business
Chesapeake Utilities Corporation (the "Company") is a diversified utility
company. The Company is engaged in natural gas
distribution to approximately 34,70035,800 customers located in southern Delaware,
Maryland'sMarylands Eastern Shore and Central Florida. The Company owns aCompanys natural gas
transmission subsidiary which operates a pipeline from various points in
Pennsylvania to the Company'sCompanys Delaware and Maryland distribution divisions,
as well as other utility and industrial customers in Delaware and the
Eastern Shore of Maryland. The Company'sCompanys propane distribution segment serves
approximately 23,10034,000 customers in southern Delaware, the Eastern Shore of
Maryland and Virginia. The advanced information services segment provides
software services and products to a wide variety of clients.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company
and its wholly owned subsidiaries, Eastern Shore Natural Gas Company
("Eastern Shore"), Sharp Energy, Inc. ("Sharp Energy"), Tri-County Gas
Company, Inc. ("Tri-County") and Chesapeake Service Company. Sharp Energy, Inc.'sEnergys
accounts include those of its wholly owned subsidiary, Sharpgas, Inc.
Chesapeake Service Company'sCompanys accounts include United Systems, Inc. ("USI"),
Capital Data Systems, Inc. and Skipjack, Inc. Investments in entities in
which the Company owns more than 20 percent but 50 percent or less, are
accounted for by the equity method. All significant intercompany
transactions have been eliminated in consolidation.
System of Accounts
The natural gas distribution divisions of the Company located in Delaware,
Maryland and Florida are subject to regulation by the Delaware, Maryland and
Florida Public Service Commissions with respect to their rates for service,
maintenance of their accounting records and various other matters. Eastern
Shore is subject to regulation by the Federal Energy Regulatory Commission
("FERC") and the Delaware Public Service Commission.. The Company'sCompanys financial statements are prepared on the basis of
generally accepted accounting principles which give appropriate recognition
to the ratemaking and accounting practices and policies of the various
commissions. The propane and advanced information services subsidiaries are
not subject to regulation with respect to rates or maintenance of accounting
records.
Cash and Cash Equivalents
The Company'sCompanys policy is to invest cash in excess of operating requirements
in overnight income producing accounts. Such amounts are stated at cost,
which approximates market. Investments with an original maturity of three
months or less are considered cash equivalents.
Property, Plant, and Equipment and Depreciation
Utility property is stated at original cost while the assets of the propane
subsidiary are valued at cost. The costs of repairs and minor replacements
are charged to income as incurred and the costs of major renewals and
betterments are capitalized. Upon retirement or disposition of utility
property, the recorded cost of removal, net of salvage value, is charged to
accumulated depreciation. Upon retirement or disposition of non-utility
property, the gain or loss, net of salvage value, is charged to income. The
provision for depreciation is computed using the straight-line method at
rates, which will amortize the unrecovered cost of depreciable property over
the estimated useful life. Depreciation and amortization expense for
financial statement purposes is provided at an annual rate for each segment
averaging 4.50%4.73% for natural gas distribution, 2.70%distribution; 3.04% for natural gas
transmission 4.56%and 5.46% for propane distribution, 5.11%distribution. In addition, annualized
rates average 4.73% for gas plant acquisition adjustments, 16.10%17.78% for the
advanced information services segment and 2.22%2.59% for othergeneral plant.
34
Allowance for Funds Used During Construction
The allowance for funds used during construction ("AFUDC") is an accounting
procedure whereby the cost of borrowed funds and other funds used to finance
construction projects is capitalized as part of utility plant on the balance
sheet, crediting the cost as a non-cash item on the income statement. The
costcosts of borrowed and equity funds isare segregated between interest expense
and other income, respectively. AFUDC was capitalized on utility plant
construction at the rates of 9.51%5.63%, 9.51% and 7.31% for 1997, 1996 and 7.15% for 1996, 1995, and 1994,
respectively.
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 can be reduced along with the
environmental regulatory asset. These amounts are recorded to either
environmental expenditures or accumulated depreciation as cost of removal.
All amounts incurred are amortized in accordance with the ratemaking
treatment granted in each jurisdiction.
Other Deferred Charges and Intangible Assets
Other deferred charges include discount, premium and issuance costs
associated with long-term debt restricted stock earned for services performed but not yet
awarded and rate case expenses. The discount, premium
and issuance costs are deferred, andthen amortized over the original lives of
theirthe respective debt issues. Gains and losses on the reacquisition of debt
are amortized over the remaining lives of the original issuances.issuance(s). Rate
case expenses are deferred, andthen amortized over periods approved by the
applicable regulatory authorities. Intangible assets are associated with the
acquisition of non-utility companies, and are being amortized on a straight-line
basis over a period of twelvefive to 40 years. The gross intangible assets were
$1,920,851$2,516,120 and $5,020,851$1,920,851 at December 31, 19961997 and 1995,1996, respectively.
Accumulated amortization related to intangible assets was $962,227$1,093,905 and
$3,587,090$962,227 at December 31, 1997 and 1996, respectively. In addition, the 1997
acquisition of a propane business resulted in the Company acquiring
goodwill, a customer list and 1995,a non-compete agreement valued at $437,000,
$108,000 and $50,000, respectively.
Income Taxes and Investment Tax Credit Adjustments
The Company files a consolidated federal income tax return. Income tax
expense allocated to the Company'sCompanys 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'sCompanys deferred tax liabilities applicable to
utility operations which has not been reflected in current service rates
represents income taxes recoverable through future rates. Investment tax
credits on utility property have been deferred and are allocated to income
ratably over the lives of the subject property.
The Company had state tax loss carryforwards of $46,000$796,000 and $2,004,000$46,000 at
December 31, 19961997 and 1995,1996, respectively. The Company anticipates usingexpects to use all of
the loss carryforwards at December 31, 1996, andcarryforwards; therefore, no valuation allowance was recorded at
December 31, 1996 and 1995 had been recorded.1997 or 1996. The loss carryforwards expire in various years beginning in 19972006 through 2007.2012.
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 C to
the Consolidated Financial Statements for disclosure of fair value of
investments). The fair value of the Company'sCompanys long-term debt is estimated
using a discounted cash flow methodology. BasedThe estimated fair value of the
Companys long-term debt at December 31, 1997, including current maturities,
is approximately $40.7 million as compared to a carrying value of $38.8
million. At December 31, 1996, the estimated fair value was approximately
$30.3 million as compared to a carrying value of $29.8 million. These
estimates are based on published corporate borrowing rates for debt
instruments with similar terms and average maturities, the estimated fair value
of the Company's long-term debt
35
(including current maturities) at December 31, 1996, is approximately $30.3
million as compared to the carrying value of $29.8 million. At December 31,
1995, the estimated fair value was approximately $32.8 million as compared to a
carrying value of $30.7 million.maturities.
Operating Revenues
Revenues for the natural gas distribution divisions of the Company and a portion
of Eastern Shore's revenues are based
on rates approved by the various commissions. Customers'Customers base rates may not
be changed without formal approval by these commissions. The Company, except for itsWith the exception
of the Companys Florida division, the Company recognizes revenues from
meters read on a monthly cycle basis. This practice results in unbilled and
unrecorded revenue from the cycle date through month-end. The Florida
division recognizes revenues based on services rendered and records an
amount for gas delivered but not billed. The propane segment recognizes
revenue for certain customers on a metered basis and all other customers on
an as-
deliveredas-delivered basis.
The natural gas distribution divisions of the Company and Eastern Shore have purchased gas
adjustment ("PGA") clauses that provide 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 natural gas transmission segment became an open access pipeline on
November 1, 1997 with revenues based on rates approved by FERC. Before open
access, only portions of revenues were based on rates approved by FERC. In
addition, the transmission segment had a PGA clause similar to those in the
distribution operations. Since the transmission segment records revenue for
service only, the PGA clause no longer applies, now that open access is in
effect.
The Company had salescharges flexible rates to one customer in 1995, anthe industrial interruptible customercustomers
of the natural gas transmissiondistribution segment which exceeded 10% of total
revenue. Total sales were approximately $10,600,000 or 10.2% of total revenue
during 1995. During 1996 and 1994, no individual customer accounted for 10% or
more of operating revenues.
The Company's natural gas transmission and distribution segments have industrial
interruptible customers that are charged rates which can be adjusted up or down to make natural gas competitive with
alternative fuels. Thesetypes of fuel. Based on pricing, these customers based
on competitive pricing, can choose
natural gas or alternative types of supply. Neither the customerCompany nor the
Companycustomer is contractually obligated by contract to receivedeliver or deliverreceive natural gas.
Earnings Per Share
PrimaryThe Company has adopted Statement of Financial Accounting Standards ("SFAS")
No. 128, issued by the Financial Accounting Standards Board ("FASB") in
February 1997, requiring dual presentation of basic and diluted per share
earnings on the face of the income statement. Basic earnings per common share areis
based on the weighted average number of shares of common stock outstanding, adjusted for stock options for each year
presented.outstanding.
On a fully diluted basis, both earnings and shares outstanding are adjusted to assumefor
stock options for each year presented and the assumed conversion of the
convertible debentures. The adoption of SFAS No. 128 did not have a material
effect on the Companys financial statements. Prior years presentations of
earnings per share have been restated to conform to the guidelines of SFAS
No. 128.
CALCULATION OF DILUTED EARNINGS PER SHARE
- -------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
- -------------------------------------------------------------------------------------------------
Reconciliation of Numerator:
Net Income - basic $5,682,946 $7,604,915 $7,593,506
Effect of 8.25% Convertible debentures 204,070 207,825 213,043
- -------------------------------------------------------------------------------------------------
Adjusted numerator - diluted $5,887,016 $7,812,740 $7,806,549
=================================================================================================
Reconciliation of Denominator:
Weighted Shares Outstanding - basic 4,472,087 4,412,137 4,336,431
Effect of Dilutive Securities
8.25% Convertible debentures 238,353 242,742 248,833
Stock options and performance shares * 38,462 22,053 4,487
- -------------------------------------------------------------------------------------------------
Adjusted denominator - diluted 4,748,902 4,676,932 4,589,751
=================================================================================================
Diluted Earnings per Share $1.24 $1.67 $1.70
=================================================================================================
* The impact of the 95,492 stock options that were granted in 1997 (see Note H to
the Consolidated Financial Statements) could potentially dilute earnings per share
in the future.
Certain Risks and Uncertainties
The financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates (see Note J
to the Consolidated Financial Statements for significant estimates) in
measuring assets and liabilities and related revenue and expenses. These
estimates involve judgements with respect to, among other things, various
future economic factors whichthat are difficult to predict and are beyond the
control of the Company. Therefore,Company; therefore, actual results could differ from those
estimates.
The Company records certain assets and liabilities in accordance with Statement
of Accounting Standards ("SFAS")SFAS
No. 71. If the Company were required to terminate application of SFAS No. 71
for all of its regulated operations, all such deferred amounts that are deferred would be recognized in
the income statement at that time, resulting in a charge to earnings, net of
applicable income taxes.
Impairment of Long-Lived Assets
During 1996,FASB Statements Issued
Comprehensive Income. In June 1997, the Company adoptedFASB issued SFAS No. 121 "Accounting130 regarding
the reporting of comprehensive income in the full set of financial
statements. The Company must adopt the requirements of the standard in its
financial statements for the Impairmentyear beginning January 1, 1998. The effect of
Long-Lived Assets." This statement requires that long-lived assets be reviewed
for impairment whenever events or changes in circumstances indicate that the carrying amountadoption of an asset may not be recoverable. Additionally, the standard requires rate-
36
regulated companiespertains primarily to write off regulatory assets to earnings whenever those
assets no longer meet the criteria for recognition of a regulatory asset as
defined by SFAS No. 71, "Accounting115 regarding
held for the Effects of Certain Types of
Regulation." When circumstances indicate that the carrying amount of an asset
may be impaired, the Company estimates the future cash flowssale investments, and is not expected to result
fromhave a material impact
on the useCompanys financial statements.
Segment Information. In June 1997, FASB issued SFAS No. 131, establishing
standards for public business enterprises to report information about
operating segments in annual financial statements and requiring that those
enterprises report selected information about operating segments in
interim financial reports to shareholders. The Company will adopt the
requirements of this standard in the first quarter of the asset and its eventual disposition. If the sum of the
undiscounted expected future cash flows is less than the carrying amount of the
asset, the Company recognizes an impairment loss in accordance with SFAS No.
121.1998 fiscal
year. The adoption of SFAS No. 121 didthe standard is not expected to have a material
effectimpact on the Company'sCompanys financial statements.
Reclassification of Prior Years'Years Amounts
Certain prior years'years amounts have been reclassified to conform with the 1996to current
year presentation.
B. AcquisitionBusiness Combinations
In JanuaryMarch 1997, the Company entered into an agreement and planacquired all of merger to
acquire all the outstanding common stock of
Tri-County Gas Company, Inc. ("Tri-
County") and associated properties. TheTri-Countys
principal business of Tri-County is the distribution of propane to both retail and
wholesale customers onin southern Delaware, the Delmarva
Peninsula.
The transaction, which is expected to be completed in the first calendar
quarter, will be effected through the exchangeEastern Shore of 639,000Maryland and
Virginia. Six hundred thirty-nine thousand shares of the Company'sCompanys common
stock andwere exchanged in the transaction, which was accounted for as a
pooling of interests. Accordingly,
historicalAll prior period consolidated financial data in future reports will bestatements
presented have been restated to include Tri-
County data. The following unaudited pro forma data summarizes the combined results of operations,
financial position and cash flows of Tri-County. All material transactions
between the Company and Tri-County as thoughhave been eliminated in consolidation.
The results of operations for the transaction
had occurred atseparate companies and the beginning of calendar year 1995.combined
amounts are presented in the consolidated financial statements to follow.
For the Years- ---------------------------------------------------------------------------------------------------------------
Two months ended Year Ended Year Ended
February 28, 1997 December 31, (Unaudited pro forma) 1996 December 31, 1995
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating revenue $130,234,503 $111,825,347
OperatingRevenues
Chesapeake $29,690,819 $119,330,068 $104,020,416
Tri-County 2,652,910 10,883,341 7,775,362
- ---------------------------------------------------------------------------------------------------------------
Combined $32,343,729 $130,213,409 $111,795,778
===============================================================================================================
Net Income
Chesapeake $2,434,351 $6,910,428 $7,236,695
Tri-County 265,059 694,487 356,811
- ---------------------------------------------------------------------------------------------------------------
Combined $2,699,410 $7,604,915 $7,593,506
===============================================================================================================
Unaudited Pro Forma Net Income*
Chesapeake N/A $6,910,428 $7,236,695
Tri-County N/A 426,276 219,011
- ---------------------------------------------------------------------------------------------------------------
Combined N/A $7,336,704 $7,455,706
===============================================================================================================
* Unaudited pro forma net income beforereflects adjustments to net income to record an estimated provision
for income taxes, $ 14,034,590 $ 14,050,757
Operatingassuming Tri-County was a tax paying entity in 1996 and 1995. During 1997, Tri-County
was a C Corporation for federal income $ 9,857,769 $ 9,916,355
Nettax purposes. Tri-County will be included in the Company's
U.S. federal income $ 7,335,790 $ 7,455,242
Primary earnings per share $ 1.66 $ 1.72
Fully diluted earnings per share $ 1.61 $ 1.67
- --------------------------------------------------------------------------------tax return, effective March 1997.
The unaudited pro forma data does not purport to be indicative of what results
may occur of the combined companies in the future.
C. Investments
The investment balance at December 31, 19961997 and 19951996 consists primarily of
the common stock of Florida Public Utilities Company ("FPU"). The Company'sCompanys
ownership at December 31, 19961997 and 19951996 represents a 7.41%7.34% and 7.04%7.41%
interest, respectively. The Company has classified its investment in FPU as
an "Available for Sale" security, which requires that all unrealized gains
and losses be excluded from earnings and be reported net of income tax as a
separate component of stockholders'stockholders equity. At December 31, 1997 and 1996,
the market value exceeded the aggregate cost basis of the Company'sCompanys
portfolio by $63,598. The aggregate cost
basis of the Company's portfolio at December 31, 1995 exceeded its market value
by $120,839.
37
$486,872 and $63,598, respectively.
D. Lease Obligations
The Company has entered into several operating leaseslease arrangements for office
space at various locations. Rent expense related to these leases was
$293,038, $409,214$277,000, $293,000 and $418,047$409,000 for 1997, 1996 1995 and 1994,1995, respectively.
Future minimum payments under the Company'sCompanys current lease agreements are
$220,103; $139,533; $141,958;
$146,454$236,000; $228,000; $232,000; $145,000 and $74,396$91,000 for the years of 19971998
through 2001, respectfully;2002, respectively; and $114,261$198,000 thereafter.
E. Segment Information
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
1994
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues, Unaffiliated Customers
Natural gas distribution $74,904,076$75,940,968 $74,904,100 $54,120,280 $49,523,743
Natural gas transmission 15,188,77712,164,369 15,188,752 24,984,767 22,191,896
Propane distribution 22,333,969 17,607,956 20,684,15026,994,404 33,179,114 25,345,696
Advanced information services and other7,636,407 6,903,246 7,307,413
6,172,508
----------------------------------------------------------Other 38,445 38,197 37,622
- ----------------------------------------------------------------------------------------------------------
Total operating revenues, unaffiliated customers $119,330,068 $104,020,416 $98,572,297
==========================================================$122,774,593 $130,213,409 $111,795,778
==========================================================================================================
Intersegment Revenues *
Natural gas distribution $8,711 $42,037 $55,888$18,970 $12,232 $5,095
Natural gas transmission 21,543,32719,282,359 21,543,352 16,663,043 17,303,529
Propane distribution 52,230 2,059 139,052 85,552
Advanced information services and other 710,949 1,722,135 2,277,361
----------------------------------------------------------149,602 326,913 1,554,498
Other 523,007 332,512 349,508
- ----------------------------------------------------------------------------------------------------------
Total intersegment revenues $22,265,046 $18,566,267 $19,722,330
==========================================================$20,026,168 $22,217,068 $18,711,196
==========================================================================================================
Operating Income Before Income Taxes
Natural gas distribution $7,167,236$5,498,471 $7,167,237 $4,728,348 $4,696,659
Natural gas transmission 3,721,148 2,458,442 6,083,440
3,018,212
Propane distribution 2,053,299 1,852,630 2,287,6881,063,554 2,814,958 2,252,165
Advanced information services and other 1,305,203 1,170,970 174,033
----------------------------------------------------------1,045,912 1,056,201 1,061,309
Other 524,785 406,632 215,146
- ----------------------------------------------------------------------------------------------------------
Total 12,984,180 13,835,388 10,176,59211,853,870 13,903,470 14,340,408
Add (Less): Eliminations 206,580 (248,595) (419,883)
----------------------------------------------------------32,727 153,591 (248,594)
- ----------------------------------------------------------------------------------------------------------
Total operating income before income taxes $13,190,760 $13,586,793 $9,756,709
==========================================================$11,886,597 $14,057,061 $14,091,814
==========================================================================================================
Depreciation and Amortization
Natural gas distribution $2,854,843 $2,502,531 $2,136,979$3,076,654 $2,907,831 $2,468,141
Natural gas transmission 892,258 697,834 638,099
641,485
Propane distribution 1,306,053 1,312,048 1,323,6981,204,968 1,681,588 1,629,971
Advanced information services 122,081 131,877 969,588 1,021,944969,587
Other plant 111,216 39,486 16,573
----------------------------------------------------------101,014 85,507 97,086
- ----------------------------------------------------------------------------------------------------------
Total depreciation and amortization $5,101,823 $5,461,752 $5,140,679
==========================================================$5,396,975 $5,504,637 $5,802,884
==========================================================================================================
Capital Expenditures
Natural gas distribution $6,634,827 $7,236,848 $8,160,874$5,826,065 $6,472,459 $7,424,489
Natural gas transmission 3,286,860 5,567,509 1,335,793
619,852
Propane distribution 1,693,113 1,640,203 828,5192,820,166 2,189,368 2,427,773
Advanced information services 277,015 162,189 114,461
411,957
Other plant 244,120 1,772,454 632,137
----------------------------------------------------------559,043 445,916 1,584,813
- ----------------------------------------------------------------------------------------------------------
Total capital expenditures $14,301,758 $12,099,759 $10,653,339
==========================================================$12,769,149 $14,837,441 $12,887,329
==========================================================================================================
Identifiable Assets, at December 31,
Natural gas distribution $81,250,030 $75,630,741 $68,528,774$78,732,860 $77,426,232 $72,256,841
Natural gas transmission 24,781,292 23,981,989 19,292,524
17,792,415
Propane distribution 20,791,588 18,855,507 16,949,43124,209,693 25,009,751 22,723,647
Advanced information services 1,496,4181,751,192 1,496,419 1,635,100
3,196,064
Other 3,617,885 3,380,108 1,803,933
----------------------------------------------------------7,903,823 8,131,517 7,430,616
- ----------------------------------------------------------------------------------------------------------
Total identifiable assets $131,137,910 $118,793,980 $108,270,617
==========================================================
$137,378,860 $136,045,908 $123,338,728
==========================================================================================================
* All significant intersegment revenues have been eliminated from consolidated revenues.
38
F. Long-TermLong-term Debt
The outstanding long-term debt, net of current maturities, is as follows:
- ------------------------------------------------------------------------------------
At December 31, 1997 1996
1995- ------------------------------------------------------------------------------------
First mortgage sinking fund bonds:
Adjustable rate Series G*, due January 1, 1998 $ 62,500 $ 312,500$0 $62,500
9.37% Series I, due December 15, 2004 4,300,000 4,820,000 5,340,000
12.00% Mortgage, due February 1, 1998 14,868
28,139
8.25% Convertible debentures, due March 1, 2014 3,926,000 4,087,000
4,114,000Uncollateralized Senior notes:
7.97% Senior uncollateralized note, due February 1, 2008 10,000,000 10,000,000
6.91% Senior uncollateralized note, due October 1, 2010 10,000,000 10,000,000
-------------------------6.85% note, due January 1, 2012 10,000,000
- ------------------------------------------------------------------------------------
Total long-term debt $38,226,000 $28,984,368
$29,794,639
-------------------------
====================================================================================
* The Series G bonds are subject to an interest rate equal to seventy-three
percent (73%) of the prime rate (8.50% and 8.25% at December 31, 1997 and
1996, respectively).
Annual maturities of consolidated long-term debt for the five years are as
follows: $582,500 for 1998, $1,520,000 for 1999 and $2,665,091 for the
years 2000 through 2002.
On December 15, 1997, the Company issued $10 million of 6.85% senior notes
due January 1, 2012. The Company used the proceeds to repay a portion of the
prime rate (8.25% and 8.5% at December 31, 1996 and 1995),
respectively.Companys short-term borrowing.
The convertible debentures may be converted, at the option of the holder,
into shares of the Company'sCompanys common stock at a conversion price of $17.01
per share. During 1996, $15,0001997, $156,000 in debentures were converted. The
debentures are redeemable at the option of the holder, subject to an annual
non-cumulative maximum limitation of $200,000 in the aggregate. As of
December 31, 1996, approximately
$8,000 of the1997, no debentures have been accepted for redemption in 1997.1998.
At the Company'sCompanys option, the debentures may be redeemed at the stated
amounts.
On October 2, 1995, the Company issued $10,000,000 of 6.91% senior notes due on
October 1, 2010. The Company used a portion of the proceeds to repay $4,091,000
of the 10.85% senior notes that were originally due October 1, 2003.
Indentures to the long-term debt of the Company and its subsidiaries contain
various restrictions. The most stringent restrictions state that the Company
must maintain equity of at least 40% of total capitalization, the times
interest earned ratio must be at least 2.5 and the Company cannot, until the
retirement of its Series I bonds, pay any dividends after December 31, 1988
which exceed the sum of $2,135,188 plus consolidated net income recognized
on or after January 1, 1989. As of December 31, 1996,1997, the amounts available
for future dividends permitted by the Series I covenant approximated $13.0$14.6
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'sCompanys
first mortgage sinking fund bonds are issued.
Annual maturities of consolidated long-term debt for the years 1997 through 2001
are $791,271, $597,368, $1,520,000, $2,665,091 and $2,665,091.
G. Short-TermShort-term Borrowings
The Board of Directors has authorized the Company to borrow up to $20,000,000$20.0
million from various bank and trust companies. As of December 31, 1996,1997, the
Company had four $8,000,000 unsecured bank lines of credit totaling $34.0 million, none
of which required compensating balances. Under these lines of credit at
December 31, 19961997 and 1995,1996, the Company had short-term debt outstanding of
$12,000,000$7.6 million and $4,800,000,$12.7 million, respectively, with a weighted average
interest rate of 6.12%5.63% and 6.00%6.12%, respectively.
39
H. Common Stock, Additional Paid-in Capital and Treasury Stock
The following is a schedule of changes in the Company'sThe following is a schedule of changes in the Companys shares of common
stock.
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995 1994(1)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Common Stock: Shares issuedIssued and outstanding*outstanding (2)
Balance - beginning of year 3,721,589 3,668,791 3,605,1524,439,516 4,360,589 4,307,791
Dividend Reinvestment Plan (3) 32,169 33,926 38,660 30,928
USI restricted stock award agreements 21,859 14,138 32,418
Conversion of debentures 881 293
Exercised stock options 1,863
Sale of stock to Company's Retirement Savings Plan 23,228 20,398
USI restricted stock award agreements 21,859 14,138
Conversion of debentures 9,166 881
Exercised stock options 1,863
- ----------------------------------------------------------------------------------------------------
Balance - end of year 3,800,516 3,721,589 3,668,791
-------------------------------------------
Shares4,504,079 4,439,516 4,360,589
====================================================================================================
(1) The 1995 beginning balance of common stock held in treasury
Balance - beginning4,307,791 has been restated to include 639,000 shares
of year 15,609 30,084
Sale of stockCommon Stock that were issued to Company's Retirement Savings Plan (15,609) (14,475)
-------------------------------------------
Balance - end of year 15,609
-------------------------------------------
*12,000,000effect the business combination with Tri-County
Gas Company, Inc.
(2) 12,000,000 shares are authorized at a par value of $.4867 per share.
(3) Includes dividends and reinvested optional cash payments.
At the beginning of 1995, the Company had 15,609 shares of common stock held
in treasury. During 1995, all of these were sold to the Companys retirement
savings plan.
Certain key USI employees entered into restricted stock award agreements
under which shares of Chesapeake common stock can be issued. Shares were
awarded as a non-cash transaction over a five-year period beginning in 1992,
and restrictions lapse over a five to ten-year period from the award date,
if certain financial targets are met. At December 31, 1997 and 1996,
respectively, 12,515 and 1995, respectively, 24,350 and 29,598 shares valued at $364,529$190,886 and $415,107$364,529
remain restricted.
The Performance Incentive Plan, which was adopted in 1992, provides for the
granting of stock options to certain officers of the Company over a 10-year
period. In November 1994, the Company executed Tandem Stock Option and
Performance Share Agreements ("Agreements") with certain executive officers.
These Agreements provide the participants an option to purchase shares of
the Company'sCompanys common stock, exercisable in cumulative installments of one-thirdone-
third on each anniversary of the commencement of the award period. The
Agreements also enable the participants the right to earn performance shares
upon the Company'sCompanys achievement of the performance goals set forth in the
Agreements. WhenDuring the three-year period ended December 31, 1997, the
aforementioned performance goals were achieved. Following the approval of
the Board of Directors on February 27, 1998, the Company issued 44,081
performance shares. Forty-four thousand ninety-six stock options expired
upon the issuance of the performance shares are issued, the option will expire. Exercise of the option
will cancel the participant's right to earn a corresponding number of
performance shares.on February 27. In 1996,1997, the
Company recorded $276,522$415,681 to recognize the compensation expense associated
with the performance shares. Changes in outstanding options were as follows:
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1997 1996 1995
1994- --------------------------------------------------------------------------------------------------------------------
Number Option Number Option Number Option
of shares pricePrice of Shares Price of shares price of shares pricePrice
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year 125,186 $12.625 - $12.75 136,186 $12.625 - $12.75 80,280 $ 12.75
Options granted 55,906 $12.625
Options exercised (12,135) $12.75
Options forfeited (11,000) $ 12.625
Balance - end of year 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75 136,186 $12.625 - $12.75
Options granted 95,492 $20.50
Options exercised (12,135) $12.75
Options forfeited (11,000) $12.625
- --------------------------------------------------------------------------------------------------------------------
Balance - end of year 208,543 $12.625 - $20.50 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75
====================================================================================================================
Exercisable 98,083 $12.625 - $12.75 83,114 $12.625 - $12.75 80,280 $ 12.75 53,520 $ 12.75$12.75
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
40
During 1996,In December 1997, the Company adoptedgranted stock options to certain executive
officers of the Company. As required by SFAS No. 123, "Accounting for Stock-Based
Compensation", for note disclosure purposes only, as prescribed by the standard.
No stock options were granted during 1996 or 1995, and therefore, no1997 pro forma net
income as if fair value based accounting had been used to account for the
stock-based compensation costs is $5,679,603. Pro forma basic and diluted
earnings per share are $1.27 and $1.24, respectively. Pro forma disclosures
have been provided.for 1997 are not likely to be representative of future effects of reported
net income. The fair value of each option grant was estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions used for grants in 1997: dividend yield of
4.73%; expected volatility of 15.53%; risk-free interest rate of 5.89%; and
expected lives of four years.
I. Employee Benefit Plans
Pension Plan
The Company sponsors a defined benefit pension plan covering substantially
all of its employees. Benefits under the plan are based on each
participant'sparticipants years of service and highest average compensation. The
Company'sCompanys 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.
Total Net Pension CostPENSION COST
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
1994
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Service cost $ 656,985 $ 474,000 $ 592,294$680,192 $656,985 $474,000
Interest cost 732,188 658,238 562,003
518,184
Less: Actual (return) lossreturn on assets (2,427,768) (1,142,287) (1,546,325) 742,949
Net amortization and deferral 1,421,028 269,135 689,947
(1,465,744)
--------------------------------------------------- ---------------------------------------------------------------------------------------------
Total net pension cost 405,640 442,071 179,625 387,683
Amounts capitalized as construction cost (33,942) (38,860) (30,740)
(52,549)
--------------------------------------------------- ---------------------------------------------------------------------------------------------
Amount charged to expense $ 403,211 $ 148,885 $ 335,134
---------------------------------------------------
Discount rate used in calculating net pension cost 7.25% 8.50% 7.00%$371,698 $403,211 $148,885
=============================================================================================
The following schedule sets forth the funding status of the pension plan at
December 31, 19961997 and 1995.1996.
Accrued Pension CostACCRUED PENSION COST
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
At December 31, 1997 1996
1995
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Vested $ 6,834,661 $ 5,730,239$7,615,194 $6,834,661
Non-vested 123,255 139,483
100,878
------------------------------- ------------------------------------------------------------------------------------
Total accumulated benefit obligation $7,738,449 6,974,144
$ 5,831,117
------------------------------====================================================================================
Plan assets at fair value $ 10,720,514 $ 9,173,094$13,592,699 $10,720,514
Projected benefit obligation (11,534,355) (10,265,987)
(9,331,890)
------------------------------- ------------------------------------------------------------------------------------
Plan assets less projected benefit obligation 2,058,344 454,527 (158,796)
Unrecognized net gain (4,038,679) (2,820,957) (2,319,138)
Unamortized net assets from adoption of SFAS No. 87 (198,326) (141,579)
(156,683)
-------------------------------- ------------------------------------------------------------------------------------
Accrued pension cost ($2,178,661) ($2,508,009)
($2,634,617)
-------------------------------====================================================================================
Assumptions:
Discount rate 7.25% 7.25%
Average increase in future compensation levels 4.75% 5.50%4.75%
Expected long-term rate of return on assets 8.50% 8.50%
8.50%- ------------------------------------------------------------------------------------
41
Other PostretirementPost-retirement Benefits
The Company sponsors a defined benefit postretirementpost-retirement health care and life
insurance plan that covers substantially all natural gas and corporate
employees. In the first quarter of 1994, the Company increased the amount that
future retirees would be required to contribute to participate in the Company's
health care program. The change reduced the Company's transition obligation and
annual costs to $357,000 and $70,000, respectively. The change also resulted in
a one-time curtailment loss of $64,000 in 1994. The Company had deferred approximately $126,000, which
represented the difference between the Maryland division'sdivisions 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 is $101,000$78,000 at
December 31, 1996.1997.
Net Periodic Postretirement Benefit Cost
At December 31, 1996 1995 1994POST-RETIREMENT COST
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
- ---------------------------------------------------------------------------------------------
Service cost $ 2,820 $ 1,827 $ 3,553$3,287 $2,820 $1,827
Interest cost on APBO 60,221 54,651 59,706 44,118
Amortization of transition obligation over 20 years 29,413 27,859 27,859
22,148
Curtailment loss 63,821
-------------------------------------------- ---------------------------------------------------------------------------------------------
Net periodic postretirementpost-retirement benefit cost 92,921 85,330 89,392 133,640
Amount capitalized as construction cost (16,274) (16,672) (14,010)
(20,134)
Amount deferredamortized (deferred) 25,254 25,254 (20,561)
(13,212)
-------------------------------------------- ---------------------------------------------------------------------------------------------
Amount charged to expense $ 68,658 $ 54,821 $100,294
--------------------------------------------$101,901 $93,912 $54,821
=============================================================================================
ACCRUED POST-RETIREMENT LIABILITY
- ------------------------------------------------------------------------------------
At December 31, 1997 1996
- ------------------------------------------------------------------------------------
Accumulated post-retirement benefit obligation:
Retirees $621,203 $567,599
Fully eligible active employees 145,356 137,378
Other active 102,340 86,894
- ------------------------------------------------------------------------------------
Total accumulated post-retirement benefit obligation 868,899 791,871
Unrecognized transition obligation (245,154) (273,013)
Unrecognized net (loss) gain (147,422) (67,155)
- ------------------------------------------------------------------------------------
Accrued post-retirement liability $476,323 $451,703
====================================================================================
Assumption:
Discount rate 7.25% 8.50% 7.00%
Accrued Postretirement Benefit Liability7.25%
- --------------------------------------------------------------------------------------------------------
At December 31, 1996 1995
- --------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 567,599 616,664
Fully eligible active employees 137,378 135,297
Other active 86,894 90,724
---------------------------
Total accumulated postretirement benefit obligation 791,871 842,685
Unrecognized transition obligation (273,013) (300,872)
Unrecognized net (loss) gain (67,155) (70,873)
---------------------------
Accrued postretirement liability $451,703 $470,940
---------------------------
Assumption:
Discount rate 7.25% 7.25%------------------------------------------------------------------------------------
The health care inflation rate for 19961997 is assumed to be 10%9.5%. This rate is
projected to gradually decrease to an ultimate rate of 5% by the year 2007.
A one percentage point increase in the health care inflation rate from the
assumed rate would increase the accumulated postretirementpost-retirement benefit
obligation by approximately $90,396$98,650 as of January 1, 1997,1998, and would
increase the aggregate of the service cost and interest cost components of
net periodic postretirementpost-retirement benefit cost for 19971998 by
approximately $7,366.
42$8,293.
Retirement Savings Plan
The Company sponsors a Retirement Savings Plan, a 401(k) plan ("Plan"), that
provides participants a mechanism for making contributions for retirement
savings. Each participant may make pre-tax contributions based upon eligible
compensation. The Company makes a contribution equal exceed 6%, of
the to 60% or 100% of each
participant's pre-participant'sparticipants pre-tax contributions, not to exceed 6%, of the participants
eligible compensation for the plan year. The Company'sCompanys contributions totaled
$404,406, $353,350 $301,794 and $240,103$301,794 for the years ended December 31, 1997, 1996
1995 and 1994,1995, respectively. As of December 31, 1996,1997, there are 79,60256,374 shares
reserved to fund future contributions to the Plan.
J. Environmental Commitments and Contingencies
The Company currently is participating in the investigation, assessment or
remediation of fourthree 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.
The Dover site has been listed by the Environmental Protection Agency Region III
("EPA") on the Superfund National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"). On August 19,
1994, the EPA issuedsites remediation costs are estimated at $4.2 million in the
Record of Decision ("ROD") forissued by the site, which selected
a remedial planEnvironmental Protection Agency
("EPA") in January 1998. The Company and estimatedGeneral Public Utilities
Corporation, Inc. ("GPU") were ordered by the costs of the selected remedy at $2.7 million
for ground-water remediation and $3.3 million for soil remediation. On May 17,
1995, EPA issued an order to the Company under Section 106 of CERCLA (the
"Order"), which requires the Company to fund or implement the
ROD. The Order was
also issued to General Public Utilities Corporation, Inc. ("GPU"), which both
EPA andDuring 1998, the Company believe is liable under CERCLA. Other potentially
responsible parties ("PRPs") such as the State of Delaware were not ordered to
perform the ROD. In July 1996, the Company commencedwill commence with the design phase ofphase. The
Company has adjusted the ROD, on-site pre-design and investigation. A pre-design investigation report
("the report") was filed in October 1996liability associated with the EPA.Dover site from $6.0
million to $4.2 million. The report, which
requires EPA approval, will provide up to date statusCompany has also recorded a regulatory asset in
the same amount. The previous accrual of $6.0 million was based on the
site, whichoriginal Record of Decision issued by the EPA will use to determine if the remedial design selected in the ROD is still the
appropriate remedy.
On March 6, 1995, the Company commenced litigation against the State of Delaware
for contribution to the remedial costs being incurred to carry out the ROD. In
December of 1995, this case was dismissed without prejudice based on a
settlement agreement between the parties (the "Settlement"). Under the
Settlement, the State agreed to contribute $600,000 toward the cost of
implementing the ROD and to reimburse the EPA for $400,000 in oversight costs.1994.
The Settlement is contingent upon a formal settlement agreement between EPA and
the State of Delaware being reached within the next two years. Upon satisfaction
of all conditions of the Settlement, the litigation will be dismissed with
prejudice.
On June 25, 1996, the Company initiated litigation against one of the other PRPspotentially
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. The Company is currently engaged in investigations related to additional parties
who may be PRPs. Based upon these investigations, the Company will consider suit
against other PRPs. The Company expects continued negotiations with PRPs in an
attempt to resolve these matters.
In the third quarter of 1994, the Company increased its liability recorded with
respect to the Dover site to $6.0 million. This amount reflected the EPA's
estimate, as stated in the ROD, for remediation of the site according to the
ROD. The recorded liability may be adjusted upward or downward as the design
phase progresses and the Company obtains construction bids for performance of
the work. The Company has also recorded a regulatory asset of $6.0 million,
corresponding to the recorded liability. Management believes that in addition to
the $600,000 expected to be contributed by the State of Delaware under the
Settlement, the Company will
be equitably entitled to contribution from other responsible parties for a
portion of the expenses to be incurred in connection with the remedies
selected in the ROD. Management also believes that the amounts not so
contributed will be recoverable in the Company'sCompanys rates.
43
DuringIn cooperation with the Maryland Department of the Environment ("MDE"), in
1996 the Company completed construction and began remediation procedures at
the Salisbury site and will besite. In addition, the Company began quarterly reporting on an ongoing basis,of
the remediation and monitoring results to the Maryland Department of the
Environment.MDE. The Company has
accruedestablished a liability with respect to the Salisbury site of $650,088$665,000 as of
December 31, 1996.1997. This amount is based on the estimated operating costs of
the remediation facilities. A corresponding regulatory asset has been
recorded, reflecting the Company'sCompanys belief that costs incurred will be
recoverable in rates.
Portions of the liability payouts for the Dover and Salisbury sites are
expected to be over 30 and five-year periods, respectively. In addition, the
Company has two other sites. Onea site located in the state of Florida, which is currently being
evaluated for whichevaluated. At this time, no estimate of liability can be made at this time. The other
site has been remediated, and in 1996 the Company received the site closure
certificate.made. It is
management'smanagements opinion that any unrecovered current costs and any other future
costs incurred will be recoverable through future rates or sharing
arrangements with other responsible parties.
ENVIRONMENTAL COSTS INCURRED
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------
At December 31, 1997 1996
1995
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------
Environmental Costs Incurred
Delaware $ 4,423,843 $3,929,417$5,317,380 $4,423,843
Maryland 2,368,168 2,187,810
1,805,572
Florida 692,391 660,828
629,153
------------------------ ------------------------------------------------------------------------------------
Total costs incurred 8,377,939 7,272,481 6,364,142
Less: Amounts, net of insurance proceeds, which
have been approved for ratemaking treatment net of insurance proceeds 6,396,108 6,066,096
-----------------------(7,319,496) (6,396,108)
- ------------------------------------------------------------------------------------
Amounts pending ratemaking recovery $1,058,443 876,373
$ 298,046
-----------------------====================================================================================
K. Commitments and Contingencies
FERC PGA
On May 19, 1994,In the third quarter of 1995, Eastern Shore reached a settlement with the
FERC issued an Order directingpertaining to Eastern Shore Natural Gas
Company ("Eastern Shore") to refund, with interest, what the FERC characterized
as overcharges from November 1, 1992 to the current billing month. Eastern Shore
contested the order and requested a rehearing. Subsequently, Eastern Shore and
the FERC entered into negotiations to resolve this issue.
In response to the FERC's May 19, 1994 Order, Eastern Shore accrued $412,000
during the second quarter of 1994 as an estimated liability for potential
refunds relating to prior periods. Thereafter, Eastern Shore accrued each month
to ensure that the potential refund was fully accrued. On August 17, 1995, the
FERC issued an Order approving an Offer of Settlement submitted by Eastern
Shore. The Order approved a change in Eastern Shore'sShores PGA methodology
retroactive to June 1, 1994, which resulted in a rate reduction of approximately
$234,000 per year. The reserves that the Company had accrued for the potential
refund were significantly greater than the rate reduction ordered.methodology. Accordingly, Eastern
Shore reversed a large portion of the estimated liability that had been
accrued. This reversal contributed $1,385,000 to pre-tax earnings, or
$833,000 to after-tax earnings, duringfor the third quarter of 1995. In connection with the
offer of settlement and the resulting FERC Order, Eastern Shore applied in
December 1995 to the FERC for a blanket certificate authorizing open access
transportation service on its pipeline system. The implementation of open access
transportation service, expected to occur during 1997, will provide all of
Eastern Shore's customers with the opportunity to transport gas over its system
at FERC regulated rates. Open access is thus likely to result in a shift of
Eastern Shore's business from margins earned on sales of gas to large industrial
customers, to a possibly lower margin earned on transportation services.period.
Other Commitments and Contingencies
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 44
concerning
rates. In the opinion of management, the ultimate dispositondisposition of these
proceedings will not have a material effect on the consolidated financial
position of the Company.
L. 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'sCompanys
business, there are substantial variations in operations reported on a
quarterly basis.
- -----------------------------------------------------------------------------------
First Second Third Fourth
1996 Quarter Quarter Quarter QuarterFor the Quarters Ended: March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------------
1997
Operating Revenue $44,270,265 $23,850,551 $18,475,914 $32,733,338$43,645,111 $24,805,428 $19,910,307 $34,413,746
Operating Income $ 5,277,681 $ 1,401,082 $ 153,444 $ 2,411,5674,104,438 1,409,752 25,177 3,019,603
Net Income $ 4,649,009 $ 832,457 ($390,871) $ 1,819,833
Primary3,366,113 692,841 (739,193) 2,363,185
Earnings Per Share $ 1.24 $ 0.22 ($0.10) $ 0.48
Fullyper share:
Basic 0.76 0.16 (0.17) 0.53
Diluted Earnings Per
Share $ 1.17 $ 0.22 ($0.10) $ 0.460.72 0.15 (0.17) 0.51
- -----------------------------------------------------------------------------------
1995
- -----------------------------------------------------------------------------------1996
Operating Revenue $30,896,798 $22,074,663 $20,564,994 $30,483,961$49,026,542 $25,213,979 $19,637,074 $36,335,814
Operating Income $ 4,330,962 $ 1,369,342 $ 1,492,200 $ 2,369,0156,667,499 1,084,392 (160,422) 2,518,536
Net Income $ 3,658,431 $ 764,085 $ 988,122 $ 1,826,057
Primary6,000,157 486,311 (747,779) 1,866,226
Earnings Per Share $ 1.00 $ 0.21 $ 0.27 $ 0.49
Fullyper share:
Basic 1.37 0.11 (0.17) 0.42
Diluted Earnings Per
Share $ 0.95 $ 0.21 $ 0.26 $ 0.471.30 0.11 (0.17) 0.41
- -----------------------------------------------------------------------------------
Results for the third quarter 1995 refelect a non-recurring increase in net
income of $833,000, (see Note K to the Consolidated Financial Statements).
45
OPERATING STATISTICS
Operating Statistics
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995 1994 (1) 1993 1992(1)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Revenues (In(in thousands)
Natural gas
Residential $21,540 $18,256 $14,857 $15,228 $14,007
$12,935
Commercial 16,557 14,339 11,383 11,594 10,837
9,857
Industrial 22,625 28,546 36,898 32,718 31,622
26,977
Sale for resale 23,010 24,481 12,459 9,586 5,242
3,843
Transportation 4,212 3,369 2,993 2,639 2,480
2,400
Other 162 1,102 515 (50) 193
(134)
------------------------------------------------------------------------------------ --------------------------------------------------------------------------------------------------
Total natural gas revenues 88,106 90,093 79,105 71,715 64,381
55,878
Propane 22,334 17,608 17,789/*/(1) 26,994 33,179 25,346 17,789 16,908
16,489
Other 6,903 7,3077,675 6,941 7,345 6,173 4,584
3,568
===================================================================================- --------------------------------------------------------------------------------------------------
Total revenues $119,330 $104,020$122,775 $130,213 $111,796 $95,677 $85,873
$75,935
=====================================================================================================================================================================================
Volumes
Natural gas deliveries (in MMCF)
Residential 1,753 1,987 1,686 1,665 1,596
1,561
Commercial 2,138 2,092 1,792 1,771 1,676
1,633
Industrial 5,946 7,501 13,622 10,752 9,308
8,014
Sale for resale 872 1,065 990 998 984
997
Transportation 12,559 12,096 11,131 7,542 5,880
5,139
------------------------------------------------------------------------------------ --------------------------------------------------------------------------------------------------
Total natural gas deliveries 23,268 24,741 29,221 22,728 19,444
17,344
=====================================================================================================================================================================================
Propane (in thousands of gallons) 19,853 17,748 18,395/*/(1) 26,682 29,975 26,184 18,395 17,250
17,125
=====================================================================================================================================================================================
Customers
Natural gas
Residential 31,277 30,349 29,285 28,260 27,312
26,523
Commercial 4,288 4,151 4,030 3,879 3,759
3,683
Industrial/**/Industrial (2) 229 210 212 204 196
198
Sale for resale/**/resale (2) 3 3 3 3 3
------------------------------------------------------------------------------------ --------------------------------------------------------------------------------------------------
Total natural gas customers 35,797 34,713 33,530 32,346 31,270
30,407
Propane 23,096 22,60933,998 32,218 31,372 22,180 21,622
21,132
------------------------------------------------------------------------------------ --------------------------------------------------------------------------------------------------
Total customers 57,809 56,13969,795 66,931 64,902 54,526 52,892
51,539
=====================================================================================================================================================================================
(1) 1994 and 1993 have not been restated to include the business combination
with Tri-County Gas Company, Inc.
(2) 1994 amounts exclude $2,895,000 in revenue and nine million gallons of
propane sold to one large wholesale customer.
(3) Includes transportation customers.
/*/ Excludes revenue of $2,895,000, which resulted from the sale of nine
million gallons of propane to one large wholesale customer in 1994.
/**/Includes transportation customers.
Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure
None
PART III
Item 10. Directors and Executive Officers of the Registrant
Information pertaining to the Directors of the Company is incorporated herein
by reference to the Proxy Statement, under "Information Regarding the Board
of Directors and Nominees", dated and to be filed on or before April 4, 1997March 30, 1998
in connection with the Company'sCompanys Annual Meeting to be held on May 20, 1997.19, 1998.
The information required by this item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Item 10 of Part I of this Form 10-K under "Executive Officers of the
Registrant."
Item 11. Executive Compensation
This information is incorporated herein by reference to the Proxy Statement,
under "Report on Executive Compensation", dated and to be filed on or before
April 4, 1997March 30, 1998 in connection with the Company'sCompanys Annual Meeting to be held on
May 20, 1997.19, 1998.
Item 12. Security Ownership of Certain Beneficial Owners and Management
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company'sCompanys Securities", dated and to be
filed on or before April 4, 1997March 30, 1998 in connection with the Company'sCompanys Annual
Meeting to be held on May 20, 1996.19, 1998.
Item 13. Certain Relationships and Related Transactions
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company'sCompanys Securities", dated and to be
filed on or before April 4, 1997March 30, 1998 in connection with the Company'sCompanys Annual
Meeting to be held on May 20, 1997.19, 1998.
PART IV
Item 14. Financial Statements, Financial Statement Schedules, and Exhibits
and Reports on Form 8-K
(a) The following documents are filed as a part of this report:
1. Financial Statements:
- Accountants'Accountants Report dated February 13, 199712, 1998 of Coopers & Lybrand
L.L.P., Independent Accountants
- Consolidated Statements of Income for each of the three years
ended December 31, 1997, 1996 1995 and 19941995
- Consolidated Balance Sheets at December 31, 19961997 and
December 31, 19951996
- Consolidated Statements of Cash Flows for each of the three years
ended December 31, 1997, 1996 1995 and 19941995
- Consolidated Statements of Common Stockholders'Stockholders Equity for each
of the three years ended December 31, 1997, 1996 and 1995
- Consolidated Statements of Income Taxes for each of the three
years ended December 31, 1997, 1996 and 1995
- Notes to Consolidated Financial Statements
47
2. The following additional information for the years 1997, 1996 1995 and
19941995 is submitted herewith:
- Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not required, are
inapplicable or the information is otherwise shown in the financial
statements or notes thereto.
(b) Reports on Form 8-K
OnNone.
(c) Exhibits
Exhibit 2(a) - Agreement and Plan of Merger by and between Chesapeake
Utilities Corporation and Tri-County Gas Company, Inc., filed on
the Companys Form 8-K, File No. 001-11590 on January 13, 1997, the Company filed a report on Form 8-K, reporting
under Item 5 that the Company has agreed to purchase all of the
outstanding shares of Tri-County Gas Company, Inc.
(c) Exhibitsis
incorporated herein by reference.
Exhibit 3.(a)3(a) - Certificate of Incorporation Amended Certificate of Incorporation of Chesapeake Utilities
Corporation is incorporated herein by reference to Exhibit 3.(b) to3 of the
Companys Quarterly Report on Form 10-Q for the quarterly period ended June
30, 1995, of Chesapeake Utilities Corporation.File No. 001-11590.
Exhibit 3.(b)3(b) - Bylaws Amended Bylaws of Chesapeake Utilities Corporation, effective
July 11, 1997, are incorporated herein by reference to Exhibit 3.(b) to3 of
the AnnualQuarterly Report on Form 10-K10-Q for the yearperiod ended December 31,
1994 of Chesapeake Utilities Corporation.June 30,
1997, File No. 001-11590.
Exhibit 4.(a)4(a) - The Form of Indenture between the Company and Boatmen'sBoatmens Trust
Company, Trustee, with respect to the 8 1/4% Convertible Debentures
is incorporated herein by reference to Exhibit 4.2 of the Company'sCompanys
Registration Statement on Form S-2, Reg. No. 33-26582, filed on
January 13, 1989.
Exhibit 4.(b)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 $10,000,000$10 million of 7.97%
Unsecured Senior Notes due February 1, 2008, is incorporated herein
by reference to Exhibit 4.(b)4 to the Companys Annual Report on Form
10-K for the year ended December 31, 1992, of Chesapeake Utilities Corporation.*File No. 0-593.
Exhibit 4.(c)4(c) - The Directors Stock Compensation Plan adopted by Chesapeake
Utilities Corporation in 1995 is incorporated herein by reference
to the Company'sCompanys Proxy Statement dated April 17, 1995 in connection
with the Company's annual meetingCompanys Annual Meeting held in May 1995.
Exhibit 4.(d) The4(d) Note Purchase Agreement entered into by the Company on October
2, 1995, pursuant to which the Company privately placed $10 million
of its 6.91% Senior Notes due in 2010, is not being filed herewith,
in accordance with Item 601(b)(4)(iii) of Regulation S-K. The
Company hereby agrees to furnish a copy of that agreement to the
Commission upon request.
Exhibit 10.(a)4(e) Note Purchase Agreement entered into by the Company on
December 15, 1997, pursuant to which the Company privately placed
$10.million of its 6.85 senior notes due 2012, is not being filed
herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K.
The Company hereby agrees to furnish a copy of that agreement to
the Commission upon request.
Exhibit 10(a) - Service Agreement dated November 1, 1989, by and between
Transcontinental Gas Pipe Line Corporation and Eastern Shore
Natural Gas Company, is incorporated herein by reference to Exhibit
10.(a)10 to the Companys Annual Report on Form 10-K for the year ended
December 31, 1989, of Chesapeake Utilities Corporation.*
48
File No. 0-593.
Exhibit 10.(b)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.(b)10 to the
Companys Annual Report on Form 10-K for the year ended December
31, 1989, of Chesapeake Utilities Corporation.*File No. 0-593.
Exhibit 10.(c)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.(c)10 to the Companys Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake Utilities Corporation.*File No. 0-593.
Exhibit 10.(d)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.(d)10 to the Companys Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake Utilities
Corporation.*File No. 0-593.
Exhibit 10.(e)10(e) - Service Agreement for Firm Transportation Service dated
November 1, 1989, by and between Florida Gas Transmission Company
and Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10.(e)10 to the Companys Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake
Utilities Corporation.*File No. 0-593.
Exhibit 10.(f)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.(f)10 to the Companys
Annual Report on Form 10-K for the year ended December 31, 1990,
of Chesapeake
Utilities Corporation.*File No. 0-593.
Exhibit 10.(g)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.(g)10 to the Companys Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake Utilities
Corporation.*File No. 0-593.
Exhibit 10.(h)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.(h)10 to the Companys Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake Utilities
Corporation.*File No. 0-593.
Exhibit 10.(i)10(i) - Executive Employment Agreement dated March 26, 1992,1997, by and
between Chesapeake Utilities Corporation and each Ralph J. Adkins
is incorporated herein by reference to Exhibit 10.(a) to the
Quarterly Report on Form 10-Q for the quarter ended June 30,
1992, of Chesapeake Utilities Corporation.*
Exhibit 10.(j) - Executive Employment Agreement dated March 26, 1992, by and
between Chesapeake Utilities Corporation
and John R. Schimkaitis is incorporated herein by reference to
Exhibit 10.(b)10 to the Companys Quarterly Report on Form 10-Q for the
quarterperiod ended June 30, 1992,1997, File No. 001-11590.
Exhibit 10(j) - Form of Performance Share Agreement dated January 1, 1998,
pursuant to Chesapeake Utilities Corporation.*Corporation Performance Incentive
Plan by and between Chesapeake Utilities Corporation and each of
Ralph J. Adkins and John R. Schimkaitis is filed herewith.
Exhibit 10.(k)10(k) - Chesapeake Utilities Corporation Cash Bonus Incentive Plan
dated January 1, 1992, is incorporated herein by reference to
Exhibit 10.(o)10 to the Companys Annual Report on Form 10-K for the year
ended December 31, 1991, of Chesapeake Utilities Corporation.*
49
File No. 0-593.
Exhibit 10.(l)10(l) - Chesapeake Utilities Corporation Performance Incentive Plan
dated January 1, 1992, is incorporated herein by reference to the
Company'sCompanys Proxy Statement dated April 20, 1992, in connection with
the Company'sCompanys Annual Meeting held on May 19, 1992.
Exhibit 10.(m)10(m) - Form of Tandem Stock Option and Performance Share Agreement dated November 18, 1994,January 1, 1998,
pursuant to Chesapeake Utilities Corporation Performance Incentive
Plan by and between Chesapeake Utilities Corporation and Ralph J. Adkins, John R.
Schimkaitis,each of
Michael P. McMasters, Stephen C. Thompson, William C. Boyles,
Philip S. Barefoot, and JerryJeremy D. West, filedWilliam P. Schneider and James
R. Schneider, is
incorporated herein by reference to exhibit 3.(b) to the
Annual Report on Form 10-K for the year ended December 31,
1994 for Chesapeake Utilities Corporation.*
Exhibit 10.(n) - Agreement and Plan of Merger by and between Chesapeake
Utilities Corporation and Tri-County Gas Company, Inc. is
incorporated herein by reference from the Form 8-K filed on
January 13, 1997.
Exhibit 11. - Computation of Primary and Fully Diluted Earnings Per Share, filed herewith.
Exhibit 12.12 - Computation of Ratio of Earning to Fixed Charges, filed herewith.
Exhibit 21.21 - Subsidiaries of the Registrant, filed herewith.
Exhibit 23.23 - Consent of Independent Accountants, filed herewith.
* Filed under commission file #0-593.
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//S/ RALPH J. ADKINS
-----------------------------------------------------
Ralph J. Adkins
PresidentChairman of the Board and Chief
Executive Officer
Date: March 17, 199720, 1998
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
/s/ JOHN W. JARDINE, JR. /s//S/ RALPH J. ADKINS /S/ JOHN R. SCHIMKAITIS
- ------------------------- --------------------
John W. Jardine, Jr.,------------------------------ ------------------------------
Ralph J. Adkins, President,
Chairman of the John R. Schimkaitis,
Board, President, Chief Executive Chief Operating Officer
Officer and Director Chief Executive Officer and Director
Date: March 17, 199720, 1998 Date: March 17, 1997
/s/ JOHN R. SCHIMKAITIS /s/20, 1998
/S/ MICHAEL P. MCMASTERS /S/ RICHARD BERNSTEIN
- ------------------------- -------------------------
John R. Schimkaitis, Executive Vice------------------------------ ------------------------------
Michael P. McMasters, President, Chief Operating Officer, Vice President, Richard Bernstein, Director
Chief Financial
Director Officer and Treasurer
(Principal Financial Officer)
Date: March 17, 199720, 1998 Date: March 17, 1997
/s/ JEREMIAH P. SHEA /s/20, 1998
/S/ WALTER J. COLEMAN /S/ JOHN W. JARDINE, JR.
- ------------------------------ ------------------------------
Walter J. Coleman, Director John W. Jardine, Jr., Director
Date: March 20, 1998 Date: March 20, 1998
/S/ RUDOLPH M. PEINS, JR. /S/ ROBERT F. RIDER
- --------------------- --------------------
Jeremiah P. Shea,------------------------------ ------------------------------
Rudolph M. Peins, Jr., Director Robert F. Rider, Director
Date: March 17, 199720, 1998 Date: March 17, 1997
/s/20, 1998
/S/ JEREMIAH P. SHEA /S/ WILLIAM G. WARDEN, III
/s/ RUDOLPH M. PEINS, JR.
- --------------------------- -------------------------------------------------------- ------------------------------
Jeremiah P. Shea, Director William G. Warden, III, Director
Rudolph M. Peins, Jr., Director
Date: March 17, 199720, 1998 Date: March 17, 1997
/s/ RICHARD BERNSTEIN /s/ WALTER J. COLEMAN
- ---------------------- ----------------------
Richard Bernstein, Director Walter J. Coleman, Director
Date: March 17, 1997 Date: March 17, 1997
5120, 1998
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
======================================== =============== =================================== =============== =================- ----------------------------------------------------------------------------------------------------------------
----- Additions -----
===================================
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Description of Period Expense Accounts Deductions of Period
======================================== =============== =============== ================== =============== =================
- ----------------------------------------------------------------------------------------------------------------
Valuation accounts deducted from assets
to which they apply for doubtful
accounts receivable:
1997 . . . . . . . . . . . . . . $392,412 $203,624 $68,038 (B) ($332,299) (A) $331,775
1996 . . . . . . . . . . . . . . $309,955 $364,622 $55,631 (B) ($337,796) (A) $392,412
1995 . . . . . . . . . . . . . . $202,152 $328,012 $43,151 (B) ($263,360) (A) $309,955
1994 . . . . . . . . . . . . . $186,018 $130,263 $57,633 (B) ($171,762) (A) $202,152
Notes:
(A) Uncollectible accounts charged off.
(B) Recoveries.
52