<PAGE>
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MARCH 26, 1996
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995 COMMISSION FILE NUMBER 0-593
----------------
CHESAPEAKE UTILITIES CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
STATE OF DELAWARE 51-0064146
(I.R.S. EMPLOYER
(STATE OR OTHER JURISDICTION OF IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
909 SILVER LAKE BOULEVARD, DOVER, DELAWARE 19904
(ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 302-734-6713
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 NEW YORK STOCK EXCHANGE, INC.
$.4867
----------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
8.25% CONVERTIBLE DEBENTURES DUE 2014
(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendments to this Form 10-K. [X]
As of March 22, 1996, 3,758,082 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 21,
1996, as reported by the New York Stock Exchange, was approximately
$62,008,353.
DOCUMENTS INCORPORATED BY REFERENCE
DOCUMENTS PART OF FORM 10-K
Definitive Proxy Statement dated April Part III
8, 1996
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<PAGE>
CHESAPEAKE UTILITIES CORPORATION
FORM 10-K
YEAR ENDED DECEMBER 31, 1995
TABLE OF CONTENTS
PART I
<TABLE>
<CAPTION>
PAGE
----
<C> <S> <C>
Item 1. Business....................................................... 1
Item 2. Properties..................................................... 10
Item 3. Legal Proceedings.............................................. 11
Item 4. Submission of Matters to a Vote of Security Holders............ 14
Item 10. Executive Officers of the Registrant........................... 14
PART II
Item 5. Market for Registrant's Common Stock and Related Security
Holder Matters................................................ 15
Item 6. Selected Financial Data........................................ 16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................... 17
Item 8. Financial Statements and Supplementary Data.................... 23
Item 9. Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure.......................................... 43
PART III
Item 10. Directors and Executive Officers of the Registrant............. 43
Item 11. Executive Compensation......................................... 43
Item 12. Security Ownership of Certain Beneficial Owners and Management. 43
Item 13. Certain Relationships and Related Transactions................. 43
PART IV
Item 14. Financial Statements, Financial Statement Schedules, Exhibits
and Reports on Form 8-K....................................... 43
Signatures............................................................... 46
</TABLE>
<PAGE>
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 information technology services.
Chesapeake's three natural gas distribution divisions serve approximately
33,500 residential, commercial and industrial customers in southern Delaware,
Maryland's Eastern Shore and Central Florida. The natural gas transmission
subsidiary operates a 271-mile interstate pipeline system that transports gas
from various points in Pennsylvania to the Company's Delaware and Maryland
distribution divisions, as well as to other utilities and industrial customers
in Delaware and the Eastern Shore of Maryland. The Company's propane segment
serves approximately 22,600 customers in southern Delaware and the Eastern
Shore of Maryland and Virginia. The information technology services segment
provides software services to a wide variety of customers and clients.
(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
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<S> <C> <C> <C>
Operating Revenues, Unaffiliated
Customers
Natural gas distribution........... $ 54,120,280 $ 49,523,743 $ 44,286,243
Natural gas transmission........... 24,984,767 22,191,896 20,094,343
Propane distribution............... 17,607,956 20,684,150 16,908,289
Information technology services and
other............................. 7,307,413 6,172,508 4,583,757
------------ ------------ ------------
Total operating revenues,
unaffiliated customers.......... $104,020,416 $ 98,572,297 $ 85,872,632
============ ============ ============
Intersegment Revenues
Natural gas distribution........... $ 42,037 $ 55,888 $ 52,577
Natural gas transmission........... 16,663,043 17,303,529 17,345,800
Propane distribution............... 139,052 85,552 48,248
Information technology services.... 1,722,135 2,277,361 2,311,498
------------ ------------ ------------
Total intersegment revenues...... $ 18,566,267 $ 19,722,330 $ 19,758,123
============ ============ ============
Operating Income Before Income Taxes
Natural gas distribution........... $ 4,728,348 $ 4,696,659 $ 4,114,683
Natural gas transmission........... 6,083,440 3,018,212 3,091,843
Propane distribution............... 1,852,630 2,287,688 1,588,383
Information technology services.... 1,170,970 174,033 156,910
------------ ------------ ------------
Total............................ 13,835,388 10,176,592 8,951,819
Less: Eliminations................. (248,595) (419,883) (651,439)
------------ ------------ ------------
Total operating income before
income taxes.................... $ 13,586,793 $ 9,756,709 $ 8,300,380
============ ============ ============
Identifiable Assets, At December 31,
Natural gas distribution........... $ 75,630,741 $ 68,528,774 $ 59,404,795
Natural gas transmission........... 19,292,524 17,792,415 18,212,489
Propane distribution............... 18,855,507 16,949,431 18,244,020
Information technology services.... 3,380,108 3,196,064 3,896,201
Other.............................. 1,635,100 1,803,933 1,230,596
------------ ------------ ------------
Total identifiable assets........ $118,793,980 $108,270,617 $100,988,101
============ ============ ============
</TABLE>
1
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(C) NARRATIVE DESCRIPTION OF BUSINESS
The Company is engaged in four primary business activities: natural gas
transmission; natural gas distribution; propane distribution; and information
technology services. In addition to the four primary groups, Chesapeake has
three subsidiaries engaged in other service related businesses. In 1995 and
1993, the Company had sales to one customer, Texaco Refining and marketing, an
industrial interruptible customer of the natural gas transmission segment,
which exceeded 10% of total revenue. Total sales to this customer were
approximately $10.6 million or 10.2% and $9.6 million or 11.2% of total
revenue during 1995 and 1993. During 1994, no individual customer accounted
for 10% or more of operating revenues.
(I) (A) NATURAL GAS TRANSMISSION
Eastern Shore Natural Gas Company ("Eastern Shore"), the Company's wholly
owned transmission subsidiary, operates an interstate pipeline that
delivers gas to five utility and thirteen industrial customers in Delaware
and the Eastern Shore of Maryland. Eastern Shore is the sole source of gas
supply for Chesapeake's Maryland and Delaware divisions and for two
unaffiliated distribution entities. During 1995 and previously, Eastern
Shore was not an "open access" pipeline which would provide transportation
service to all customers. However, Eastern Shore has authority from the
Federal Energy Regulatory Commission ("FERC") to provide firm
transportation to two of its customers for gas they own and deliver to
Eastern Shore for redelivery.
Operating income before income taxes attributed to natural gas
transmission was $6.1 million, $3.0 million and $3.1 million for the years
1995, 1994 and 1993, respectively. Operating income for 1995 increased $3.1
million due to a combination of the settlement between Eastern Shore and
the FERC, a reduction in the required levels of accruals in 1995 as
compared to 1994 and a 29% increase in deliveries to industrial
interruptible customers. Exclusive of matters relating to the settlement
and associated accruals operating income increased $890,000 in 1995 as
compared to 1994 and $1.1 million in 1994 as compared to 1993. These
fluctuations have resulted primarily from variations in volumes and margins
on Eastern Shore's interruptible sales to industrial customers that have
the capability of switching to oil for their fuel requirements. Rates
charged to these customers are determined through negotiation and thus are
flexible. When lower oil prices prevail Eastern Shore normally reduces the
price it charges to its interruptible customers, thereby reducing the
profit margin on such sales. In addition, certain customers switch from
natural gas to oil, reducing volumes sold. For further discussion, see the
Management Discussion and Analysis.
NATURAL GAS SUPPLY
General. Eastern Shore has firm contracts with three major interstate
pipelines, Transcontinental Pipe Line Corporation ("Transco"), Columbia Gas
Transmission Corporation ("Columbia") and Columbia Gulf Transmission
Corporation ("Gulf"), all of which are "open-access" pipelines.
Eastern Shore's contracts with Transco include (a) firm transportation
capacity of 22,900 MCF per day, which expires in 2005; (b) firm
transportation capacity of 500 MCF per day for December through February,
which expires in 2006; (c) three firm storage services providing a peak day
entitlement of 7,046 MCF and a total capacity of 288,739 MCF; and (d) two
interruptible storage services with a total capacity of 432,663 MCF.
Eastern Shore's contracts with Columbia include: (1) firm transportation
capacity of 1,481 MCF per day, which expires in 2004 and (b) firm storage
service providing a peak day entitlement of 10,525 MCF per day and a total
capacity of 509,954 MCF.
Eastern Shore's contract with Gulf is for firm transportation of 1,510
MCF per day, which also expires in 2004.
Eastern Shore currently has contracts for the purchase of firm natural
gas supplies with five reputable suppliers. These five contracts provide a
maximum daily entitlement of 15,855 MCF and the supplies are transported by
both Transco and Columbia under Eastern Shore's firm transportation
agreements. The gas purchase contracts have various expiration dates.
2
<PAGE>
Adequacy of Gas Supply. Eastern Shore's firm obligations to its
customers, including Chesapeake's Delaware and Maryland utility divisions,
are 40,237 MCF for peak days and 9,190,678 MCF on an annual basis. Eastern
Shore's 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 33,926 MCF and its total annual firm supply is
6,697,815 MCF. This is equivalent to 80% of Eastern Shore's firm daily
demand and 73% of its annual firm demand being satisfied by firm supply
sources. To meet the difference between firm supply and firm demand,
Eastern Shore obtains gas supply on the "spot market" from various other
suppliers which is transported by Transco or Columbia and sold to Eastern
Shore's customers as required. The Company believes that Eastern Shore's
available firm, interruptible and "spot market" supply is ample to meet the
anticipated needs of Eastern Shore's customers.
There was no curtailment of firm gas supply to Eastern Shore in 1995, nor
does Eastern Shore anticipate any such curtailment during 1996.
COMPETITION
Competition with Alternative Fuels. Historically, the Company's natural
gas operations have successfully competed with other forms of energy such
as electricity, oil and propane. The principal consideration in the
competition between the Company and suppliers of other sources of energy is
price and, to a lesser extent, accessibility. All of the Company's
divisions have the capability of adjusting their interruptible rates to
compete with alternative fuels.
The Company has 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 transmission
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 high
cost of conversion is a disincentive for individuals and businesses to
change their energy source.
Competition within the Natural Gas Industry. FERC Order 636 enables all
natural gas suppliers to compete for customers on an equal footing. Under
this "open access" environment, interstate pipeline companies have
unbundled the traditional components of their service--gas gathering,
transportation and storage. 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 not an "open access" pipeline and 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 Shore applied to the FERC for a blanket certificate
authorizing open access transportation service on its pipeline system (see
open access plan filing below). The implementation of open access
transportation service, expected to occur during the second half of 1996,
will provide all of Eastern Shore's customers with the opportunity to
transport gas over its system at FERC regulated rates. For further
discussion, see Management Discussion and Analysis.
3
<PAGE>
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 purchases 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.
During 1996, after Eastern Shore becomes an open access pipeline, the
FERC will have sole regulatory authority over Eastern Shore while 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.
RATE 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.
Eastern Shore filed a request for rehearing of the Order on June 20, 1994
based on what Eastern Shore believed was the FERC's erroneous
interpretation of Eastern Shore's tariff. It was Eastern Shore's position
that the FERC's Order essentially required a retroactive change to the FERC
approved PGA procedures which Eastern Shore had consistently applied over
the prior six years.
On June 21, 1994, in compliance with the FERC's May 19, 1994 Order,
Eastern Shore filed: (1) revised tariff sheets clarifying its PGA
methodology and (2) two alternative refund calculations based on the FERC's
Order. The two alternatives were filed due to what Eastern Shore believed
to be an inconsistency or contradiction with respect to the FERC's language
in its Order.
On July 18, 1994, the FERC issued an "Order Granting a Rehearing Solely
for the Purpose of Further Consideration". This Order was issued only to
afford the FERC additional time for consideration of the issues raised in
Eastern Shore's request for rehearing.
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 been accruing 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 been accruing. 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)
provide additional firm contract demand sales and storage service to
several of its existing customers, (2) abandon firm sales service to one of
its existing customers and (3) construct and operate
4
<PAGE>
certain new pipeline and compressor facilities required to stabilize
capacity on its system and to provide the additional firm sales and storage
service.
Specifically, Eastern Shore requested authority 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
("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 proposed 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 proposed
facilities is planned to be undertaken during the 1996 summer and fall
seasons and completed by a proposed in-service date of November 1, 1996.
The proposed facilities will 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, effective
September 30, 1996.
Eastern Shore estimates the total cost of the additional pipeline and
compressor facilities proposed in its application to be $6.8 million. In
the second quarter of 1996, Eastern Shore plans to file for a rate increase
with the FERC to recover the cost to construct and operate the Delaware
City Compressor Station.
OPEN ACCESS PLAN 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 in addition to its
initial restructuring filing (Open Access Restructuring Plan).
Eastern Shore requests that the authorizations sought herein become
effective no earlier than the in-service date of the proposed compressor
station and related facilities.
In accordance with Order No. 636, Eastern Shore proposes to unbundle the
sales and storage services it currently provides. Customers receiving firm
bundled sales and storage services on Eastern Shore (the "Converting
Customers") will receive entitlements to firm transportation service on
Eastern Shore's pipeline service in a quantity equivalent to their current
bundled service rights. Eastern Shore will assign to the 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. Consistent with Order No. 636,
Converting Customers who previously received bundled sales service having
no-notice characteristics (no prior notification required to receive
service) will have the right to elect no-notice firm transportation
service.
With respect to cost classification, allocation and rate design, Eastern
Shore proposes to implement straight fixed variable ("SFV") cost
classification and proforma postage stamp rates. In order to accomplish a
change from its current modified fixed variable ("MFV") rate design,
Eastern Shore will make a Section 4 rate filing which should also be
coordinated with the in-service date of its new open access transportation
rates.
Currently, representatives from Eastern Shore are formally meeting with
customers to discuss comments and issues associated with the filing.
(I) (B) NATURAL GAS DISTRIBUTION
Chesapeake distributes natural gas to approximately 33,500 residential,
commercial and industrial customers in southern Delaware, the Salisbury and
Cambridge, Maryland areas on Maryland's Eastern
5
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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 25,300 customers, of which approximately 25,200 are
residential and commercial customers purchasing gas primarily for heating
purposes. Residential and commercial customers account for approximately
66% 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
8,120 residential and commercial and 86 industrial customers in Polk,
Osceola and Hillsborough Counties. Currently 34 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 88% of the
volume delivered by the Florida division, and 64% of the division's natural
gas sales and transportation revenues, on an annual basis. In November
1993, the Company's Florida division began providing natural gas supply
services to compete in the open access environment. Currently, eighteen
customers receive management service which generated operating income of
$95,000 in 1995.
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 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 November 1, 1993, the
storage capacity under contract with Eastern Shore totaled 829,527 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 lower priced "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
6
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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 cancelled 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.
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 FGT, gas marketers or other
suppliers. These conditions have increased competition between Chesapeake's
Florida division, FGT, gas marketers and other natural gas providers for
industrial customers in Central Florida. Starting in early 1993, in
recognition of the opportunity created by FERC Order 636, Chesapeake's
Florida division began contacting all of the Florida division's large
industrial customers and other large users of natural gas throughout the
state of Florida about changes in the natural gas industry. As a result,
the Company has entered into agreements with a number of these large users
of natural gas to supply them with gas supply management and regulatory
support services. The Company plans on offering similar services to large
industrial customers of the Delaware and Maryland divisions.
RATES AND REGULATION
General. Chesapeake's natural gas distribution operations are subject to
regulation by the Delaware, Maryland and Florida Public Service Commissions
with respect to various aspects of the Company's business, including the
rates for sales to all of their customers in each jurisdiction. All of
Chesapeake's firm distribution rates are subject to purchased gas
adjustment clauses, which match revenues with gas costs and normally allow
eventual full recovery of gas costs. Adjustments under these clauses
require periodic filings and hearings with the relevant regulatory
authority, but do not require a general rate proceeding. Rates on
interruptible sales by the Florida division are also subject to purchased
gas adjustment clauses.
Management monitors the rate of return in each jurisdiction in order to
ensure the timely filing of rate adjustment applications.
RATE PROCEEDINGS.
Maryland--On July 31, 1995 Chesapeake Utilities filed an application with
the Maryland Public Service Commission requesting a rate increase of
$1,426,711 or 17.09%. The two largest components of the increase are
attributable to environmental costs and the new customer information
system. The request included a return on equity of 13%.
7
<PAGE>
On December 15, 1995 the Maryland Public Service Commission issued an
order approving a $975,000 increase in annual base rates effective for gas
provided on or after December 1, 1995.
Delaware--On April 4, 1995, Chesapeake Utilities 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 third of the total requested increase, is attributable to
projected costs associated with the cleanup 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.
On December 20, 1995, the DPSC approved an order authorizing a $900,000
increase to base rates effective January 1, 1996. The Company did have
interim rates subject to refund in effective 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 on 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.
Florida--On December 10, 1993, the Florida Public Service Commission
issued an order reducing the Florida division's allowed return on equity
from a midpoint of 12% to 11%, in response to lower interest rates. On
August 5, 1994, the Florida division filed Modified Minimum Filing
Requirements ("MMFR") as required every four years by Florida Public
Service Commission regulations. As of December 31, 1994, no decision had
been rendered by the Florida Public Service Commission. During 1995, the
Florida State legislature repealed the requirement, and as such,
Chesapeake's MMFR filing was abandoned.
On September 28, 1995, the Florida Public Service Commission issued an
order finalizing the Florida division's 1994 amount of overearnings. The
division was found to have exceeded its allowed rate of return on equity
ceiling of 12% by $62,000. As a result of an agreement reached February 6,
1995, the excess earnings were deferred until 1995. The same agreement caps
the Florida Division's 1995 return on equity at 12% plus or minus the
result of subtracting the average yield of 30-year U.S. Treasury bonds for
the period of October, November 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. After reviewing bond market
conditions, it appears likely that the division's return on equity for 1995
will be lowered to a midpoint of 10.5% for determining any level of
overearnings. Final determination of 1995 overearnings on the disposition
of such will most likely occur in the second quarter of 1996.
(I) (C) PROPANE DISTRIBUTION
Chesapeake's propane distribution group consists of Sharp Energy, Inc.
("Sharp Energy"), a wholly owned subsidiary of Chesapeake, and its wholly
owned subsidiary, Sharpgas, Inc. ("Sharpgas").
Sharpgas purchases, stores and distributes propane to approximately
22,600 customers on the Delmarva Peninsula. 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-burning
fuel, gaining increased recognition for its environmental superiority,
safety, efficiency, transportability and ease of use relative to
alternative forms of energy.
8
<PAGE>
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 purchases propane primarily from five suppliers, including
major domestic oil companies and independent producers of gas liquids and
oil. Supplies of propane from these and other sources are readily available
for purchase by the Company. Supply contracts generally include minimum
(not subject to a take-or-pay premiums) and maximum purchase provisions.
The Company uses trucks and railroad cars to transport propane from
refineries, natural gas processing plants or pipeline terminals to the
Company's bulk storage facilities. From these facilities, propane is
delivered in portable cylinders or by "bobtail" trucks, owned and operated
by the Company, to tanks located at the customer's premises. Most of the
tanks and cylinders are owned by the Company and are utilized by the
customer free of charge.
Sharpgas competes with several other propane distributors in its service
territories, primarily on the basis of service and price, emphasizing
reliability of service and responsiveness. Competition is generally local
because distributors located in close proximity to customers incur lower
costs of providing service.
Propane competes with electricity and fuel oil as an energy source.
Propane is typically comparable in price to fuel oil and generally less
expensive than electricity based on equivalent BTU value. Because natural
gas historically has been less expensive than propane, propane is generally
not distributed in geographic areas serviced by natural gas pipeline or
distribution systems.
The Company's 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's propane operations are subject to all operating hazards
normally incident to 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) INFORMATION TECHNOLOGY SERVICES
Chesapeake's information technology services segment is comprised of two
wholly owned subsidiaries of the Company: United Systems, Inc. ("USI") and
Capital Data Systems, Inc. ("CDS").
USI is an Atlanta-based company that primarily provides support for users
of PROGRESS(R), 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.
CDS is an information technology provider offering services primarily to
telecommunications companies and Chesapeake's subsidiaries. These services
are programming support for application software solutions including
customer information, management information, billing and financial
systems.
The information technology 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 information
technology business are occurring rapidly, which could adversely impact the
markets for the Company's products and services.
(I) (E) OTHER LINES OF BUSINESS
In addition to the four business segments previously mentioned, the
Company is involved in other businesses under the umbrella of Chesapeake
Service Company ("Chesapeake Service"), a wholly owned
9
<PAGE>
subsidiary of the Company. The group contains Skipjack, Inc. ("Skipjack"),
and Chesapeake Investment Company ("Chesapeake Investment"), both wholly
owned subsidiaries of Chesapeake Service. Skipjack owns and leases to
affiliates an office building in Dover, Delaware. Chesapeake Investment is
a Delaware affiliated investment company.
(II) SEASONAL NATURE OF BUSINESS
Revenues from the Company's residential and commercial natural gas sales
and from its propane distribution activities are affected by seasonal
variations, since the majority of these sales are to customers using the
fuels for heating purposes. Revenues from these customers are accordingly
affected by the mildness or severity of the heating season.
(III) CAPITAL BUDGET
The Company's current capital budget for 1996 contemplates expenditures
totalling approximately $16.8 million. The total includes approximately
$8.8 million for Chesapeake's natural gas distribution divisions,
consisting mainly of extensions to and replacements of the distribution
facilities and related equipment; $6.1 million for natural gas transmission
operations, providing principally for improvements to the pipeline system
by adding a compressor station in Delaware City, $1.6 million for propane
distribution, principally for the purchase of storage facilities,
additional tanks and the construction of a new operation center in
Salisbury, Maryland; $175,000 for computer hardware, furniture and fixtures
for the Company's information technology services group; along with
$119,000 for general plant. These capital requirements are expected to be
financed by cash flow provided by the Company's operating activities and
short-term borrowing.
(IV) EMPLOYEES
The Company has 335 employees including 143 natural gas distribution
employees, 19 natural gas transmission employees, 94 propane distribution
employees and 55 information technology services employees. The remaining
24 employees are considered general and administrative and include officers
of the Company and treasury, accounting, data processing, planning, human
resources and other administrative personnel.
ITEM 2. PROPERTIES
(A) GENERAL
The Company owns office and operations buildings in 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; Cary, North Carolina;
Easton and Pocomoke, Maryland; and Atlanta, Georgia. In general, the
properties of the Company are adequate for the uses for which they are
employed. Capacity and utilization of the Company's facilities can vary
significantly due to the seasonal nature of the natural gas and propane
distribution businesses.
(B) NATURAL GAS DISTRIBUTION
Chesapeake owns over 514 miles of natural gas distribution mains (together
with related service lines, meters and regulators) located in its Delaware and
Maryland service areas, and 459 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's distribution system
are encumbered pursuant to Chesapeake's 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
two compressor stations located in Daleville,
10
<PAGE>
Pennsylvania and Bridgeville, Delaware. The Daleville station is utilized to
increase Columbia supply pressures to match Transco supply pressures, and to
increase Eastern Shore's pressures in order to serve growing demands from
Chesapeake's Delaware division. The Bridgeville station is being used to
provide increased pressures required to meet the demands on the system.
(D) PROPANE DISTRIBUTION
Sharpgas owns bulk propane storage facilities with an aggregate capacity of
1,440,000 gallons at 27 plant facilities in Delaware, Maryland and Virginia,
located on real estate it either owns or leases.
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.
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,
contains 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 this time under CERCLA, both the State of Delaware and the
Company were named as potentially responsible parties ("PRP") 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 addresses the ground-water
contamination with a combination of hydraulic containment and natural
attenuation. Remediation selected for the soil at the site is to meet
stringent cleanup standards for the first two feet of soil and less stringent
standards for the soil below two feet. The ROD estimates 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 (currently 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 requires 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
11
<PAGE>
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 has informed EPA that it does not intend to comply with the
Order. The Company has commenced the design phase of the ROD.
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 support the Company's 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 within the next
two years. 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.
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 accrued liability
recorded with respect to the Dover Site to $6.0 million. This amount reflects
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's rates.
As of December 31, 1995, the Company has incurred approximately $3.7 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. In December 1995,
the Delaware Public Service Commission, authorized recovery of all unrecovered
environmental cost incurred through September 30, 1995. This amount totaled
$564,514. The recovery was authorized 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 be calculated to become effective December 1. The rider rate will be
based on the amortization of actual 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, 1995, the unamortized balance
and amount of environment cost not included in the rider, effective January 1,
1996 was $1,011,000 and $229,000, respectively. With the rider mechanism
established, it is management's opinion that these costs and any future cost,
net of the deferred income tax benefit, will be recoverable in rates.
(B) SALISBURY TOWN GAS LIGHT SITE
In cooperation with the Maryland Department of the Environment ("MDE"), the
Company has completed an assessment 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
12
<PAGE>
MDE, the remedial action workplan 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. The Company hopes to have the
remediation facilities for ground-water designed and constructed by mid-year
1996.
The cost of remediation is estimated to be approximately $380,000 in capital
costs with yearly operating expenses ranging from $136,000 to $195,000 per
year. Based on these estimated costs, the Company recorded both a liability
and a deferred regulatory asset of $1,113,572 on December 31, 1995, to cover
the Company's projected remediation costs for this site. The liability payout
for this site is expected to be over a five-year period. As of 1994, the
Company has incurred approximately $1.8 million for remedial actions and
environmental studies and has charged such costs to accumulated depreciation.
In January 1990, the Company entered into settlement agreements with a number
of insurance companies resulting in proceeds to fund actual environmental
costs incurred over a three to five-year period beginning in 1990. The final
insurance proceeds were requested and received in 1992. In December 1995, the
Maryland Public Service Commission approved recovery of all environmental cost
incurred through September 30, 1995 less amounts previously amortized and
insurance proceeds. The amount approved for a 10-year amortization was
$964,251. Of the $1.8 million in costs reported above, approximately $35,000
has not been recovered through insurance proceeds or received ratemaking
treatment. It is management's opinion that these costs incurred and future
costs incurred, if any, will be recoverable in rates.
(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 directed 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. It is not possible to determine whether remedial action
will be required by FDEP and, if so, the cost of such remediation.
The Company has spent approximately $629,000, as of December 31, 1995, 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 from
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.
Of the $629,000 in costs reported above, all costs have received ratemaking
treatment. The FPSC has allowed the Company to continue
13
<PAGE>
to accrue for future environmental costs. At December 31, 1995, the Company
has $64,000 accrued. It is management's 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. All soil and debris
were removed in the third quarter, restoration is complete and DNREC has
initiated site closure procedures. 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 53) (present term expires May 21, 1996). Mr. Adkins
is President and Chief Executive Officer of Chesapeake. He has served as
President and Chief Executive Officer since November 8, 1990. Prior to
holding his present position, Mr. Adkins served as President and Chief
Operating Officer, Executive Vice President, Senior Vice President, Vice
President and Treasurer of Chesapeake. Mr. Adkins is also Chairman,
President and Chief Executive Officer of Chesapeake Service Company, and
Chairman and Chief Executive Officer of Sharp Energy, Inc. and Eastern
Shore Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He
has been a director of Chesapeake since 1989.
John R. Schimkaitis (age 48) (present term expires May 21, 1996). Mr.
Schimkaitis is Executive Vice President and Assistant Treasurer. As
Executive Vice President, he will serve as Chief Financial Officer and
Chief Operating Officer of Chesapeake. He has 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 a director of Chesapeake in February 1996.
Jeremy D. West (age 46) (present term expires May 21, 1996). Mr. West is
the President of Sharp Energy, Inc. and Vice President of Chesapeake. He
joined Sharp Energy in 1990 as President and in May 1992 was elected Vice
President of Chesapeake. Mr. West was Vice President of Marketing from
March 1987 to March 1989, and President from March 1989 to June 1990, of
Columbia Propane Corporation, a subsidiary of Columbia Gas System.
Previously, Mr. West was with Suburban Propane Gas Corp. as Regional
Manager from September 1985 to March 1987.
Philip S. Barefoot (age 49) (present term expires May 21, 1996). 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 President of Eastern Shore Natural Gas Company.
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.
14
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S 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, 1995 and 1994:
<TABLE>
<CAPTION>
DIVIDENDS
DECLARED
QUARTER ENDED HIGH LOW CLOSE PER SHARE
------------- ------- ------- ------- ---------
<S> <C> <C> <C> <C>
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
1994
March 31................................ $15.250 $13.625 $13.875 $0.2200
June 30................................. 14.500 13.250 14.000 0.2200
September 30............................ 14.750 13.000 13.625 0.2200
December 31............................. 13.750 12.375 12.750 0.2200
</TABLE>
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, 1995:
<TABLE>
<CAPTION>
NUMBER OF SHAREHOLDERS
TITLE OF CLASS OF RECORD
-------------- ----------------------
<S> <C>
Common stock, par value $.4867.................... 2,098
</TABLE>
(C) DIVIDENDS:
During the years ended December 31, 1995 and 1994, cash dividends have been
declared each quarter, in the amounts set forth in the table above.
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, 1995, the amounts available for future dividends
permitted by the Series I covenant are $9,608,000.
15
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS EXCEPT STOCK DATA)
<S> <C> <C> <C> <C> <C>
OPERATING
Operating revenues...... $ 104,020 $ 98,572 $ 85,873 $ 75,935 $ 69,828
Operating income........ $ 9,562 $ 7,227 $ 6,311 $ 5,770 $ 5,865
Income before cumulative
effect of change in
accounting principle
and discontinued
operations............. $ 7,237 $ 4,460 $ 3,914 $ 3,475 $ 3,095
Cumulative effect of
change in accounting
principle.............. $ 58
Income (loss) from
discontinued
operations............. $ 74 $ (594)
Net Income.............. $ 7,237 $ 4,460 $ 3,972 $ 3,549 $ 2,501
---------- ---------- ---------- ---------- ----------
BALANCE SHEET
Gross plant............. $ 115,283 $ 110,023 $ 100,330 $ 91,039 $ 85,038
Net plant............... $ 81,716 $ 75,313 $ 69,794 $ 64,596 $ 61,970
Total assets............ $ 118,794 $ 108,271 $ 100,988 $ 89,557 $ 86,716
Long-term debt.......... $ 29,795 $ 24,329 $ 25,682 $ 25,668 $ 22,901
Common stockholders'
equity................. $ 42,301 $ 37,063 $ 34,878 $ 33,126 $ 32,207
Capital expenditures.... $ 12,100 $ 10,653 $ 10,064 $ 6,720 $ 5,923
---------- ---------- ---------- ---------- ----------
COMMON STOCK
Primary earnings per
share:
Income before
cumulative effect of
change in accounting
principle and
discontinued
operations........... $ 1.95 $ 1.23 $ 1.10 $ 1.00 $ 0.90
Cumulative effect of
change in accounting
principle............ $ 0.02
Income (loss) from
discontinued
operations........... $ 0.02 $(0.17)
Net income............ $ 1.95 $ 1.23 $ 1.12 $ 1.02 $ 0.73
Average shares
outstanding............ 3,701,981 3,632,413 3,556,037 3,477,244 3,434,008
Fully diluted earnings
per share:
Income before
cumulative effect of
change in accounting
principle and
discontinued
operations........... $ 1.89 $ 1.20 $ 1.08 $ 0.99 $ 0.91
Cumulative effect of
change in accounting
principle............ $ 0.02
Income (loss) from
discontinued
operations........... $ 0.02 $(0.17)
Net income............ $ 1.89 $ 1.20 $ 1.10 $ 1.01 $ 0.74
Average shares
outstanding............ 3,950,724 3,888,190 3,816,295 3,749,130 3,717,858
Cash dividends per
share.................. $ .90 $ 0.88 $ 0.86 $ 0.86 $ 0.86
Book value per share.... $11.37 $10.15 $ 9.76 $ 9.50 $ 9.37
Common equity/Total
capitalization......... 58.67% 60.37% 57.59% 56.34% 58.44%
Return on equity........ 17.11% 12.03% 11.39% 10.71% 7.77%
---------- ---------- ---------- ---------- ----------
NUMBER OF EMPLOYEES..... 335 320 326 317 311
NUMBER OF REGISTERED
STOCKHOLDERS........... 2,098 1,721 1,743 1,674 1,723
HEATING DEGREE DAYS..... 4,593 4,398 4,705 4,645 4,140
HEATING DEGREE DAYS (10
YEAR AVERAGE).......... 4,586 4,564 4,588 4,598 4,601
========== ========== ========== ========== ==========
</TABLE>
16
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Liquidity and Capital Resources
The Company's capital requirements reflect the capital intensive nature of
its business and are attributable principally to its construction program and
the retirement of its outstanding debt. The Company relies on cash generated
from operations and short-term borrowings to meet normal working capital
requirements and to temporarily finance capital expenditures. During 1995, the
Company's net cash provided by operating activities, net cash used by
investing activities and net cash used by financing activities were
$12,998,000, $11,665,000 and $754,000, respectively.
The Board of Directors has authorized the Company to borrow up to
$14,000,000 from various banks and trust companies. As of December 31, 1995,
the Company had four unsecured bank lines of credit each in the amount of
$8,000,000. Funds provided from these lines of credit are used for short-term
cash needs to meet seasonal working capital requirements and to fund portions
of its capital expenditures. The outstanding balances of short-term borrowings
at December 31, 1995 and 1994 were $4,800,000 and $8,000,000, respectively.
Based upon anticipated cash requirements in 1996, the Company may refinance
the short-term debt through the issuance of common equity, long-term debt or a
combination thereof. The timing of such an issuance is dependent upon the
nature of the securities involved as well as current market and economic
conditions.
In 1995 and 1994, the Company's capital additions were funded by operating
activities, unlike 1993 when funding was from operations and financing
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 1995, 1994 and 1993, capital expenditures were approximately
$12,100,000, $10,653,000 and $10,064,000, respectively. For 1996, the Company
has budgeted $16,769,000 for capital expenditures. The breakdown of this
amount is $8,778,000 for natural gas distribution, $6,065,000 for natural gas
transmission, $1,632,000 for propane distribution, $175,000 for information
technology services and $119,000 for general plant. The natural gas and
propane distribution expenditures are for expansion and improvement of their
existing service territories. Natural gas transmission expenditures are to
improve the pipeline system by adding a compressor station in Delaware City.
The information technology services expenditures are for computer hardware,
software and related equipment. Financing for the 1996 construction program
will be provided primarily using short-term borrowings and cash from
operations. The construction program is subject to continuous review and
modification. Actual construction expenditures may vary from the above
estimates due to a number of factors including inflation, changing economic
conditions, regulation, load growth, and the cost and availability of capital.
The Company expects to incur environmental related expenditures in the
future (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, 1995, common equity represented 58.7% of permanent
capitalization, compared to 60.4% in 1994 and 57.6% in 1993. The Company
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 commitment, along with adequate and timely
rate relief for the Company's regulated operations, helps to ensure that the
Company will be able to attract capital from outside sources at a reasonable
cost. The achievement of these objectives will provide benefits to customers
and creditors, as well as to the Company's investors.
Financing Activities
On 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 of the 10.85% Senior Notes of Eastern Shore
17
<PAGE>
Natural Gas Company, originally due October 1, 2003. The remaining proceeds of
$5,909,000 were used to repay short-term borrowing under the Company's lines
of credit. The Company issued no long-term debt in 1994. During the first
quarter of 1993, the Company issued $10,000,000 of 7.97% Senior Notes due on
February 1, 2008. The Company used a portion of the funds to repay the short-
term borrowing balance outstanding. In April 1993, the Company used the
remaining funds, along with available short-term borrowings, to repay
$3,600,000 of the Company's 10.45% Series H First Mortgage Bonds. These Bonds
were originally due April 1, 2001. During the year, the Company repaid a total
of approximately $5,018,000 of long-term debt, compared to $1,291,000 and
$5,026,000 in 1994 and 1993, respectively.
The Company issued 38,660, 30,928 and 27,942 shares of common stock in
connection with its Automatic Dividend Reinvestment and Stock Purchase Plan
during the years of 1995, 1994 and 1993, respectively. In 1993, the Company
realized an increase in the number of shares issued from the Plan due to an
increase in the level of optional cash payments from existing stockholders, as
well as the option made available in the fourth quarter of 1992 which allows
employee stock purchases through payroll deductions.
The Company began using treasury stock during the second half of 1993 to
fund the monthly Company matching contribution to the Retirement Savings Plan.
In 1995, 1994 and 1993, 15,609, 14,475 and 4,808 shares, respectively, were
used.
Results of Operations
Net income for 1995 was $7,236,695, an increase of $2,776,773 from 1994's
net income of $4,459,922. The 1995 net income reflects the settlement between
Eastern Shore and the Federal Energy Regulatory Commission ("FERC") regarding
Eastern Shore's purchased gas adjustment ("PGA") computation. This settlement,
which is a non-recurring event, contributed $833,000 to 1995 net income due 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 $198,000 after tax in 1995. Exclusive of matters
relating to the settlement and associated accruals, earnings increased by
$1,380,000. Net income for 1994 was $4,459,922 compared to $3,971,671 for
1993. Earnings before interest and taxes ("EBIT") for the years 1995, 1994 and
1993 were $13.6 million, $9.8 million and $8.3 million, respectively.
Natural Gas Distribution
The natural gas distribution segment contributed EBIT of $4.7 million in
each of 1995 and 1994 and $4.2 million in 1993. The increase in EBIT in 1994
from 1993 was due to a higher gross margin, offset by slightly higher
operating expenses.
Operating revenues increased by $4.5 million in 1995, after increasing by
$5.3 million in 1994. The cost of gas increased by $2.8 million in 1995,
compared to a $4.2 million increase in 1994. Revenues for 1995 were higher by
$3.2 million due to the increased brokering of natural gas to large industrial
customers, co-generation facilities and local distribution companies located
in the state of Florida. Correspondingly, the cost of gas increased by $3.1
million in connection with these activities. Overall, natural gas brokering
and supply management services provided a minimal increase in gross margin in
1995 and 1994. Also contributing to the higher revenue for 1995 was a $1.9
million revenue increase from the Florida distribution operations, slightly
offset by a $465,000 reduction in revenues for the Maryland distribution
operations. Correspondingly, the cost of gas for 1995 increased by $1.2
million for the Florida distribution operations, somewhat offset by a $700,000
reduction in the cost of gas for the Maryland distribution operations.
The gross margin for the Florida distribution operations rose $740,000 in
1995, primarily the result of 88% and 23% increases in transportation and
delivery volumes, respectively. These increases represented higher sales to
phosphate producing and citrus processing customers and to three co-generation
plants. Gross margin also was higher in 1995 for distribution operations in
the Company's northern service territory due to increased deliveries resulting
from temperatures being 4% colder than 1994. The 1994 increases in revenues
and the cost
18
<PAGE>
of gas are primarily due to the first full year of natural gas brokering
operations, coupled with increased deliveries in the northern service
territory to residential and commercial customers, resulting primarily from
the timing and magnitude of colder weather in the first quarter of 1994.
Operating expenses for 1995 increased by $1.2 million due to higher payroll,
customer billing system conversion and operating costs, consulting fees, legal
fees and regulatory expense. Maintenance expenses decreased slightly in 1995
after higher maintenance of meter and regulating stations in 1994.
Depreciation and amortization expense and other taxes increased due to plant
additions placed in service in 1995 and 1994. Operating expenses slightly
decreased in 1994 due to a reduction in employee benefits, legal fees and
regulatory expenses, somewhat offset by higher payroll and customer accounting
expenses.
Natural Gas Transmission
The natural gas transmission operations contributed EBIT of $6.1 million for
1995, compared to $3.0 million in 1994 and $3.1 million in 1993. Included in
the $3.1 million increase in EBIT for 1995 was the effect of the settlement
between Eastern Shore and the FERC regarding Eastern Shore's PGA computation
(see Note K to the Consolidated Financial Statements). The settlement, which
is a non-recurring event, contributed $1.3 million to EBIT for 1995 due to the
reversal of excess liability for a potential refund previously recorded, and
resulted in a reduction in the required level of accruals from $1.2 million in
1994 to $289,000 in 1995. Exclusive of matters relating to the settlement and
associated accruals, EBIT increased $890,000 in 1995, as compared to $1.1
million in 1994. 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.
Operating revenues increased to $41.7 million, from $39.5 million in 1994
and $37.4 million in 1993, while the cost of gas decreased in 1995 to $31.5
million, from $32.7 million in 1994 after increasing to $30.7 million in 1993.
The increases in operating revenues in 1995 and 1994 of $2.2 million and $2.1
million, respectively, were primarily due to 29% and 33% increases in
industrial sales volumes for the respective years. Revenues for 1994 were also
higher due to an increase in contract demand levels effective November 1,
1993. The cost of gas decreased in 1995 due to the reversal of excess
liability previously recorded and a reduction in the level of accruals
recorded in 1995 as compared to 1994. For 1994, the cost of gas increased due
to the recording of the liability for the potential PGA refund.
The majority of the increase in industrial sales volumes was due to a
municipal power plant, and methanol plant, which chose to purchase natural gas
from the Company on an interruptible basis instead of alternative fuels. The
higher sales to those two customers contributed approximately $2.4 million to
gross margin in 1995, an increase of $1 million in gross margin over 1994. In
1994, these same customers contributed approximately $1.4 million to gross
margin, an increase of $421,000 over the amount contributed to gross margin in
1993. These two customers are industrial interruptible customers and have no
ongoing commitment, contractual or otherwise, to purchase natural gas from the
Company (see Note A to the Consolidated Financial Statements).
Operating expenses increased by $314,000 in 1995 after increasing only
$24,000 in 1994. The majority of the increases were in payroll, telemetering
and legal fees. Maintenance expenses decreased in 1995 by $47,000 after
increasing in 1994 by $125,000 due to the painting of a pipeline bridge
structure and a higher level of natural gas main maintenance in 1994.
In connection with the FERC Order, 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 the second half of 1996, 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. After the implementation of open access, it is expected the Eastern
Shore's earnings, which this year and in the past have been driven to a
substantial
19
<PAGE>
extent by widely varying levels of unregulated sales, will tend to resemble
more of a fully regulated return. The Company believes that the impact on
earnings can be partially offset by anticipated improvements to the pipeline
system and, to a lesser extent, additional earnings from providing gas supply
management services.
Propane Distribution
The propane segment contributed EBIT of $1.9 million for 1995, compared to
EBIT of $2.3 million and $1.6 million for 1994 and 1993, respectively. The 19%
decrease in 1995 EBIT, or $435,000, was the combined impact of a decrease in
gross margin coupled with an increase in operating expenses. The increase in
1994 EBIT of $699,000, or 44%, resulted from an increased gross margin,
partially offset by higher operating expenses.
The decrease in gross margin for 1995 was 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 addition, the average margin per gallon rose 1% as the average
selling price per gallon more than compensated for higher gas costs passed on
by suppliers. 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.
In 1994, gross margin rose as a result of a 7% increase in volumes and a 3%
increase in the average margin per gallon. The timing and severity of the 1994
winter weather contributed to the volume growth, despite warmer overall
temperatures for the year. The increase in the average margin per gallon was
the net effect of a lower average cost per gallon, partially offset by a lower
average selling price per gallon.
Operating expenses increased 2% for both 1995 and 1994, respectively.
Comprising this increase for 1995 were higher payroll costs, employee benefit
costs and outside services. Generating the increase in expenses for 1994 were
higher costs in the following areas: service and delivery salaries, vehicle
fuel and maintenance costs directly related to the higher salaries and the
severe 1994 winter, consulting costs and insurance claims. Partially
offsetting these higher costs in 1994 were lower employee benefit costs.
Information Technology
The information technology segment contributed EBIT of $1,171,000 for 1995,
compared to EBIT of $174,000 and $157,000 for 1994 and 1993, respectively. The
substantial increase in 1995 EBIT was due to higher earnings for both United
Systems, Inc. ("USI") and Capital Data Systems, Inc. ("CDS"). The $17,000
increase in 1994 EBIT was attributable to higher EBIT for USI, partially
offset by decreases in EBIT for CDS and Currin & Associates, Inc. ("C&A").
Contributing to the increase in 1995 EBIT were higher revenues and lower
operating expenses. USI revenues increased by $1.4 million resulting from
higher consulting and programming revenues, as well as the success of USI's
new referral and placement service for PROGRESS technicians. CDS's revenues
increased in 1995 due to non-recurring revenue earned by providing services to
its largest facilities management customer during a period of system
conversion by this customer in connection with the termination of its
contract. Lower operating expenses were the net result of reduced operating
costs of $1,257,000 for CDS, partially offset by higher operating costs of
$1,037,000 for USI. Reductions in payroll, employee benefits, outside
programming and maintenance costs comprised the majority of the overall
decline in CDS' operating expenses. The reductions resulted from downsizing
efforts to transform CDS from a product development and facilities management
company, primarily billing on a fixed-price basis, to a contract programming
service company, billing on a time and materials basis, which is similar to
USI. Starting in 1996, the Company will be reporting future results of CDS and
USI on a consolidated basis since CDS is now directed by USI management.
These downsizing measures commenced at the same time CDS' contract with its
largest facilities management customer was terminated, in connection with a
change in control of that customer. In conjunction with this termination, CDS
will no longer provide facilities management services for Page-it(TM), the
billing
20
<PAGE>
software product that it designed for the telecommunications industry. In
response to demand, revenues increased; therefore, associated payroll and
employee benefit costs rose accordingly.
The increase in 1994 EBIT of $17,000, or 11%, was the net result of
increased revenues and increased operating expenses. As in 1995, USI
experienced higher consulting and programming revenues in 1994. In response to
higher revenues of $742,000, USI's payroll and employee benefit costs also
increased. Although CDS recognized increased revenues of $997,000 in 1994, its
increase in operating expenses surpassed the higher revenues. The increase in
CDS' operating expenses of $1,127,000 resulted from the increased revenues and
the completion of a major software development program.
Included in the results for the years ended December 31, 1995, 1994 and 1993
were intersegment revenues of $1,722,000, $2,277,000 and $2,311,000,
respectively, which were eliminated in consolidations. The intercompany LBIT
(Loss Before Interest and Taxes) connected with the development of
UtiliCIS(TM) totaled $165,000, $468,000 and $703,000 for the years 1995, 1994
and 1993, respectively. Finally, in 1994, the Company disposed of its
investment in C&A due to declining revenues and business prospects. C&A's
results reduced the segment's EBIT by $124,000 and $84,000 for 1994 and 1993,
respectively.
Other
Non-operating income was approximately $357,000 in 1995, compared to $16,000
in 1994. The 1995 increase was primarily due to a one-time termination fee
paid to CDS by its largest facilities management customer in connection with a
change in control of that customer, somewhat offset by costs to downsize CDS
to no longer provide facilities management service in connection with its
Page-it software.
The 1994 decrease as compared to 1993 was due primarily to interest from
upstream supplier refunds received in 1993 and the 1994 disposition of the
Company's investment in C&A.
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.
Competition
Historically, the Company's natural gas operations have successfully
competed with other forms of energy such as electric, oil and propane. The
principal considerations have been price and, to a lesser extent,
accessibility. Since Eastern Shore has only recently elected to be an open
access pipeline and this election will not be implemented until late 1996, the
Company was not subject to the competitive pressures on the Delmarva peninsula
of FERC Order No. 636 during 1995. Starting in late 1996, in connection with
its open access status, Eastern Shore will shift from providing merchant
services to providing storage and transportation services.
The Company's distribution companies located in Delaware and Maryland will
then face the possibility of the unbundling of their services to certain
industrial customers, thus increasing competition. The Company has already
addressed these issues in 1994 and 1993 in its Florida distribution operation,
when the Company was required to unbundle its services to large industrial
customers. The Company established a natural gas brokering and supply
operation to compete for the services of these customers.
Both the propane distribution and the information technology businesses face
significant competition from a number of larger competitors with substantially
greater resources available to them than the Company. In addition, in the
information technology business, changes are occurring rapidly which could
adversely impact the markets for the Company's services.
21
<PAGE>
Inflation
Inflation impacts the prices the Company must pay for labor and other goods
and services required for operation, maintenance and capital improvements. In
recent years, however, the impact of inflation has lessened. Purchased gas
costs, which have been relatively stable, are passed on to customers through
the purchased gas adjustment clause in the Company's tariffs. To help cope
with the effects of inflation on its capital investments and returns, the
Company seeks rate relief from its regulatory commissions for its regulated
segments and constantly monitors the returns of its unregulated business
segments.
Cautionary Statement
Statements made herein and elsewhere in this annual report which are not
historical fact, are forward looking statements. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995,
the Company is providing the following cautionary statement to identify
important factors that could cause its actual results to differ materially
from those anticipated in forward 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, relative to historical results, of Eastern
Shore becoming an open access pipeline. First, while open access is likely to
diminish industrial interruptible sales margins, such sales have varied widely
from year to year and, in future years, might make a less significant
contribution to earnings even in the absence of open access. Second, the level
of regulated transportation rates that will be in effect under open access has
not yet been determined. Third, Eastern Shore has significant capital
improvements scheduled in 1996 which will increase required revenue in a fully
regulated environment. Fourth, there are a number of uncertainties, including
the outcome of open access proceedings and the effects of competition, which
will effect whether the Company will be able to provide economical gas
marketing services.
In addition, a number of factors and uncertainties affecting other aspects
of the Company's business could have a material impact on earnings. These
include seasonality and temperature sensitivity of our natural gas and propane
businesses, the relative price of alternative energy sources and the effects
of competition both on our unregulated businesses and on natural gas sales
once the Company operates in an open access environment.
22
<PAGE>
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 sheets of Chesapeake
Utilities Corporation and Subsidiaries as of December 31, 1995 and 1994, 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, 1995, 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 schedule are the responsibility of the Company's
Management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits.
We conducted our audits 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, 1995 and 1994, and
the consolidated results of their operations and their cash flows for each of
the three years in the period ended December 31, 1995 in conformity with
generally accepted accounting principles. In addition, the consolidated
financial statement schedule 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, 1993, 1992, and 1991, and the related consolidated statements
of income, cash flows, common stockholders' equity, and income taxes for each
of the two years in the period ended December 31, 1992 (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, 1995, appearing on page 16 is
fairly stated in all material respects in relation to the financial statements
from which it has been derived.
Coopers & Lybrand L.L.P.
Baltimore, Maryland
February 9, 1996
23
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
AT DECEMBER 31,
--------------------------
1995 1994
------------ ------------
ASSETS
<S> <C> <C>
PROPERTY, PLANT AND EQUIPMENT
Natural gas distribution......................... $ 64,785,616 $ 57,773,632
Natural gas transmission......................... 25,651,558 24,546,916
Propane distribution............................. 19,645,973 18,289,571
Information technology services.................. 841,661 6,670,229
Gas plant acquisition adjustments................ 795,004 795,004
Other plant...................................... 3,563,247 1,947,785
------------ ------------
Total property, plant and equipment............ 115,283,059 110,023,137
Less: Accumulated depreciation and amortization.. (33,567,446) (34,710,478)
------------ ------------
Net property, plant and equipment.............. 81,715,613 75,312,659
------------ ------------
INVESTMENTS........................................ 1,957,218 1,641,851
------------ ------------
CURRENT ASSETS
Cash and cash equivalents........................ 977,407 398,751
Accounts Receivable (less allowance for
uncollectibles of $309,955 and $202,152 in 1995
and 1994, respectively)......................... 12,701,256 8,416,293
Materials and supplies, at average cost.......... 844,786 797,147
Propane inventory, at average cost............... 1,442,633 1,411,384
Storage gas prepayments.......................... 2,663,721 3,467,281
Underrecovered purchased gas costs............... 109,025
Income taxes receivable.......................... 193,916 836,813
Prepaid expenses................................. 842,460 855,107
Deferred income taxes............................ 1,362,289 1,290,680
------------ ------------
Total current assets........................... 21,028,468 17,582,481
------------ ------------
DEFERRED CHARGES AND OTHER ASSETS
Environmental regulatory assets.................. 7,113,572 6,642,092
Environmental expenditures, net.................. 1,505,140 820,555
Order 636 transition cost........................ 1,463,157 2,020,732
Other deferred charges and intangible assets..... 4,010,812 4,250,247
------------ ------------
Total deferred charges and other assets........ 14,092,681 13,733,626
------------ ------------
TOTAL ASSETS....................................... $118,793,980 $108,270,617
============ ============
</TABLE>
See accompanying notes
24
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
AT DECEMBER 31,
--------------------------
1995 1994
------------ ------------
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION
Stockholders' equity
Common stock.................................... $ 1,811,211 $ 1,785,514
Additional paid-in capital...................... 17,592,242 16,834,823
Retained earnings............................... 23,385,097 19,480,374
Less: Treasury stock, at cost................... (99,842)
Unearned compensation related to restricted
stock awarded................................ (415,107) (696,679)
Unrealized loss on marketable equity
securities, net.............................. (72,839) (241,609)
------------ ------------
Total stockholders' equity...................... 42,300,604 37,062,581
Long-term debt, net of current portion............ 29,794,639 24,328,988
------------ ------------
Total capitalization............................ 72,095,243 61,391,569
------------ ------------
CURRENT LIABILITIES
Current portion of long-term debt................. 864,849 1,348,080
Short-term borrowings............................. 4,800,000 8,000,000
Accounts payable.................................. 11,162,775 7,385,590
Refunds payable to customers...................... 966,940 567,817
Accrued interest.................................. 742,701 691,949
Dividends payable................................. 837,358 803,700
Overrecovered purchased gas costs................. 53,374
Other accrued expenses............................ 3,123,191 2,225,097
------------ ------------
Total current liabilities....................... 22,551,188 21,022,233
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes............................. 9,136,808 8,700,472
Deferred investment tax credits................... 931,247 986,062
Environmental liability........................... 7,113,572 6,642,092
Order 636 transition liability.................... 1,463,157 2,020,732
Accrued pension costs............................. 2,118,545 2,530,904
Other liabilities................................. 3,384,220 4,976,553
------------ ------------
Total deferred credits and other liabilities.... 24,147,549 25,856,815
------------ ------------
COMMITMENTS AND CONTINGENCIES
(Notes J and K)
TOTAL CAPITALIZATION AND LIABILITIES................ $118,793,980 $108,270,617
============ ============
</TABLE>
See accompanying notes
25
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------
1995 1994 1993
------------ ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES..................... $104,020,416 $98,572,297 $85,872,632
------------ ----------- -----------
OPERATING EXPENSES
Purchased gas costs ................. 58,454,410 59,013,165 49,838,349
Operations........................... 21,387,989 19,681,435 18,178,500
Maintenance.......................... 2,079,121 2,181,404 1,833,244
Depreciation and amortization........ 5,461,752 5,140,679 5,087,087
Other taxes.......................... 3,050,351 2,798,905 2,635,072
Income taxes......................... 4,025,274 2,529,635 1,989,287
------------ ----------- -----------
Total operating expenses........... 94,458,897 91,345,223 79,561,539
------------ ----------- -----------
OPERATING INCOME....................... 9,561,519 7,227,074 6,311,093
------------ ----------- -----------
OTHER INCOME AND (DEDUCTIONS)
Interest Income...................... 141,161 123,271 351,426
Other income and (deductions), net... 256,237 (144,038) (49,185)
Income taxes......................... (105,280) (12,733) (37,002)
Allowance for equity funds used
during construction................. 65,198 49,154
------------ ----------- -----------
Total other income and (deductions)
.................................. 357,316 15,654 265,239
------------ ----------- -----------
INCOME BEFORE INTEREST CHARGES......... 9,918,835 7,242,728 6,576,332
------------ ----------- -----------
INTEREST CHARGES
Interest on long-term debt........... 2,282,247 2,322,942 2,443,035
Amortization of debt expense......... 109,399 103,859 100,797
Other................................ 383,976 426,242 258,978
Allowance for borrowed funds used
during construction................. (93,482) (70,237) (140,682)
------------ ----------- -----------
Total interest charges............. 2,682,140 2,782,806 2,662,128
------------ ----------- -----------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE ....... 7,236,695 4,459,922 3,914,204
------------ ----------- -----------
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.................. 57,467
------------ ----------- -----------
NET INCOME............................. $ 7,236,695 $ 4,459,922 $ 3,971,671
============ =========== ===========
EARNINGS PER SHARE OF COMMON STOCK:
Primary:
Income before cumulative effect of
change in accounting principle...... $ 1.95 $ 1.23 $ 1.10
Cumulative effect of change in
accounting principle................ 0.02
------------ ----------- -----------
Earnings per share................... $ 1.95 $ 1.23 $ 1.12
------------ ----------- -----------
Average Shares Outstanding........... 3,701,891 3,632,413 3,556,037
Fully diluted:
Income before cumulative effect of
change in accounting principle...... $ 1.89 $ 1.20 $ 1.08
Cumulative effect of change in
accounting principle................ 0.02
------------ ----------- -----------
Earnings per share................... $ 1.89 $ 1.20 $ 1.10
------------ ----------- -----------
Average Shares Outstanding........... 3,950,724 3,888,190 3,816,295
</TABLE>
See accompanying notes
26
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income.......................... $ 7,236,695 $ 4,459,922 $ 3,971,671
Adjustments to reconcile net income
to net operating cash:
Cumulative effect of change in
method of accounting for income
taxes............................. (57,467)
Depreciation and amortization...... 5,905,090 5,786,013 5,494,731
Allowance for equity funds used
during construction............... (65,198) (49,154)
Investment tax credit adjustments.. (54,815) (54,815) (54,815)
Deferred income taxes, net......... 252,727 (669,404) 778,896
Employee benefits.................. 178,803 492,082 1,117,017
Employee compensation resulting
from lapsing of stock
restrictions...................... 431,694 374,121 367,085
Allowance for refund............... (1,356,705) 1,238,705
Other, net......................... (339,080) 424,832 1,952
Changes in assets and liabilities:
Accounts receivable, net........... (4,284,963) 1,303,517 (1,332,217)
Other current assets............... 1,380,216 (979,125) 1,066,583
Other deferred charges............. (946,450) (271,937) (590,325)
Accounts payable................... 3,149,573 382,913 (1,659,248)
Refunds payable to customers....... 399,123 59,999 (177,915)
Overrecovered (Underrecovered)
purchased gas costs............... 162,399 1,723,432 (861,006)
Other current liabilities.......... 948,846 159,910 (204,856)
------------ ------------ ------------
Net cash provided by operating
activities.......................... 12,997,955 14,381,011 7,860,086
------------ ------------ ------------
INVESTING ACTIVITIES
Property, plant and equipment
expenditures........................ (11,691,192) (10,473,565) (10,023,702)
Allowance for equity funds used
during construction................. 65,198 49,154
Purchase of investments.............. (38,836)
------------ ------------ ------------
Net cash used by investing
activities.......................... (11,664,830) (10,424,411) (10,023,702)
------------ ------------ ------------
FINANCING ACTIVITIES
Common stock dividends net of amounts
reinvested of $506,941, $427,190 and
$409,248 in 1995, 1994 and 1993,
respectively........................ (2,791,373) (2,736,388) (2,634,479)
Sale of treasury stock............... 254,484 201,704 79,017
Net (repayments) borrowings under
line of credit agreements........... (3,200,000) (900,000) 200,000
Proceeds from issuance of long-term
debt................................ 10,000,000 10,000,000
Repayments of long-term debt......... (5,017,580) (1,285,962) (5,025,934)
Payments under capital lease
obligations......................... (102,761)
------------ ------------ ------------
Net cash (used) provided by financing
activities.......................... (754,469) (4,720,646) 2,515,843
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS.................... 578,656 (764,046) 352,227
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR................... 398,751 1,162,797 810,570
------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF
YEAR................................ $ 977,407 $ 398,751 $ 1,162,797
============ ============ ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash paid for interest............... $ 2,657,972 $ 2,652,323 $ 2,421,764
Cash paid for income tax............. $ 3,288,895 $ 3,509,034 $ 1,099,422
Non cash financing and investing
activities:
Environmental costs................ $ 684,585 $ 4,987,092 $ 1,675,000
</TABLE>
See accompanying notes
27
<PAGE>
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
COMMON STOCK
Balance--beginning of year.............. $ 1,785,514 $ 1,754,547 $ 1,714,404
Dividend Reinvestment Plan............ 18,816 15,046 13,599
USI restricted stock award agreements. 6,881 15,778 26,544
Conversion of debentures.............. 143
----------- ----------- -----------
Balance--end of year.................... 1,811,211 1,785,514 1,754,547
----------- ----------- -----------
ADDITIONAL PAID-IN CAPITAL
Balance--beginning of year.............. 16,834,823 15,850,319 14,628,476
Dividend Reinvestment Plan............ 488,125 412,144 395,649
USI restricted stock award agreements. 176,029 458,335 777,920
Sale of treasury stock to Company's
Retirement
Savings Plan......................... 93,265 109,184 48,274
Conversion of debentures.............. 4,841
----------- ----------- -----------
Balance--end of year.................... 17,592,242 16,834,823 15,850,319
----------- ----------- -----------
RETAINED EARNINGS
Balance--beginning of year.............. 19,480,374 18,219,083 17,309,905
Net income............................ 7,236,695 4,459,922 3,971,671
Cash dividends(1)..................... (3,331,972) (3,198,631) (3,062,493)
----------- ----------- -----------
Balance--end of year.................... 23,385,097 19,480,374 18,219,083
----------- ----------- -----------
TREASURY STOCK
Balance--beginning of year.............. (99,842) (192,362) (223,105)
Sale of treasury stock to Company's
Retirement
Savings Plan......................... 99,842 92,520 30,743
----------- ----------- -----------
Balance--end of year.................... (99,842) (192,362)
----------- ----------- -----------
UNEARNED COMPENSATION
Balance--beginning of year.............. (696,679) (663,557) (271,332)
Issuance of award..................... (121,343) (474,113) (804,465)
Amortization of prior years' awards... 402,915 440,991 412,240
----------- ----------- -----------
Balance--end of year.................... (415,107) (696,679) (663,557)
----------- ----------- -----------
UNREALIZED LOSS ON MARKETABLE
SECURITIES(2).......................... (72,839) (241,609) (90,517)
----------- ----------- -----------
TOTAL STOCKHOLDERS' EQUITY.............. $42,300,604 $37,062,581 $34,877,513
=========== =========== ===========
</TABLE>
- --------
(1) Dividends per share of common stock were $.90, $.88 and $.86 for the years
1995, 1994 and 1993, respectively.
(2) Net of income taxes of approximately $48,000, $160,000 and $60,000 for the
years 1995, 1994 and 1993, respectively.
See accompanying notes
28
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME TAXES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------
1995 1994 1993
----------- ----------- ----------
<S> <C> <C> <C>
CURRENT INCOME TAX EXPENSE
Federal.................................. $ 3,182,346 $ 2,375,332 $ 950,259
State.................................... 621,238 707,190 332,834
Investment tax credit adjustments, net... (54,815) (54,815) (54,815)
----------- ----------- ----------
Total current income tax expense....... 3,748,769 3,027,707 1,228,278
----------- ----------- ----------
DEFERRED INCOME TAX EXPENSE
Accelerated depreciation................. 202,404 270,213 692,393
Deferred gas costs....................... (56,915) (656,772) 319,794
Pensions and other employee benefits..... 57,508 (169,731) (394,161)
Alternative minimum tax.................. 230,575 320,000
Unbilled revenue......................... (260,922) 188,356 (274,256)
Contribution in aid of construction...... (283,033) (32,345) (9,881)
Environmental expenditure................ 427,020 (32,597) (42,004)
Allowance for refund..................... 442,064 (580,361) 53,973
Other.................................... (146,341) 297,323 132,153
----------- ----------- ----------
Total deferred income tax expense (1).. 381,785 (485,339) 798,011
----------- ----------- ----------
CUMULATIVE EFFECT OF CHANGE IN METHOD OF
ACCOUNTING FOR INCOME TAXES
Decrease in deferred income tax assets... 297,973
Amount recorded on the balance sheet..... (355,440)
----------
Amount recognized in income.............. (57,467)
----------
TOTAL INCOME TAX EXPENSE $ 4,130,554 $ 2,542,368 $1,968,822
=========== =========== ==========
RECONCILIATION OF EFFECTIVE INCOME TAX
RATES
Federal income tax expense at 34%........ $ 3,806,560 $ 2,458,354 $2,019,766
State income taxes, net of Federal
benefit................................. 527,563 443,716 244,860
Cumulative effect of change in method of
accounting for income taxes............. (57,467)
Other.................................... (203,569) (359,702) (238,337)
----------- ----------- ----------
Total income tax expense............... $ 4,130,554 $ 2,542,368 $1,968,822
=========== =========== ==========
Effective income tax rate................ 36.3% 35.6% 33.1%
DEFERRED INCOME TAXES
Deferred income tax liabilities:
Accelerated depreciation............... $10,717,217 $10,709,693
Other.................................. 1,203,365 998,490
----------- -----------
Total deferred income tax
liabilities......................... 11,920,582 11,708,183
----------- -----------
Deferred income tax assets:
State operating loss carryforwards, net
(2)................................... 126,073 242,821
Deferred investment tax credit......... 454,590 477,365
Allowance for refund................... 183,485 625,549
Unbilled revenue....................... 918,001 657,098
Pension and other employee benefits.... 1,039,681 1,093,163
Self insurance......................... 529,559 514,509
Other.................................. 894,674 687,886
----------- -----------
Total deferred income tax assets..... 4,146,063 4,298,391
----------- -----------
DEFERRED INCOME TAXES PER CONSOLIDATED
BALANCE SHEET........................... $ 7,774,519 $ 7,409,792
=========== ===========
</TABLE>
- --------
(1) Total deferred income tax expense includes $108,000, $66,000 and $38,000
of deferred state income taxes for the years 1995, 1994 and 1993,
respectively.
(2) Less valuation allowances of approximately $160,000 and $341,000 for
December 31, 1995 and 1994, respectively.
See accompanying notes
29
<PAGE>
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
33,500 customers located in southern Delaware, Maryland's Eastern Shore and
Central Florida. The Company owns a natural gas transmission subsidiary which
operates a pipeline from various points in Pennsylvania to the Company's
Delaware and Maryland distribution divisions, as well as other utility and
industrial customers in Delaware and the Eastern Shore of Maryland. The
Company's propane distribution segment serves approximately 22,600 customers
in southern Delaware, the Eastern Shore of Maryland and Virginia. The
information technology 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. and Chesapeake Service Company. Sharp Energy,
Inc.'s accounts include those of its wholly owned subsidiary, Sharpgas, Inc.
Chesapeake Service Company's accounts include its wholly owned subsidiaries,
United Systems, Inc. ("USI"), Capital Data Systems, Inc. and Skipjack, Inc.
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's financial
statements are prepared on the basis of generally accepted accounting
principles which give appropriate recognition to the ratemaking and accounting
practices and policies of the various commissions. The propane and information
technology services subsidiaries are not subject to regulation with respect to
rates or maintenance of accounting records.
Cash and Cash Equivalents
The Company's policy is to invest cash in excess of operating requirements
in overnight income producing accounts. Such amounts are stated at cost which
approximates market. 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 averaging 4.37% for natural
gas distribution, 2.77% for natural gas transmission, 4.91% for propane
distribution, 5.66% for gas plant acquisition adjustments, 18.53% for
information technology services and 1.52% for other plant.
30
<PAGE>
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 cost
of borrowed and equity funds is segregated between interest expense and other
income, respectively. The Company used rates of 5.36% in 1995, 4.23% in 1994
and 3.52% in 1993 for calculating AFUDC on borrowed funds. AFUDC for equity
funds was calculated using average rates of 1.95% and 2.92% for 1995 and 1994,
respectively.
Environmental Regulatory Assets
Environmental regulatory assets represent amounts related to environmental
liabilities for which expenditures have not been made. As expenditures are
incurred, these amounts are recorded to environmental expenditures or
accumulated depreciation as cost of removal. Subsequently, the environmental
liability can be reduced along with the environmental regulatory asset. All
amounts incurred are amortized into income 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 and amortized over the original lives of their respective
debt issues. Gains and losses on the reacquisition of debt are amortized over
the remaining lives of the original issuances. Rate case expenses are deferred
and 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
eight to 40 years. The gross intangible assets were $5,020,851 for both
December 31, 1995 and 1994. Accumulated amortization related to intangible
assets was $3,587,090 and $3,079,612 at December 31, 1995 and 1994,
respectively.
Income Taxes and Investment Tax Credit Adjustments
The Company files a consolidated federal income tax return. Income tax
expense allocated to the Company's subsidiaries is based upon their respective
taxable incomes and tax credits.
Deferred tax assets and liabilities are recorded for the tax effect of
temporary differences between the financial statements and tax bases of assets
and liabilities, and are measured using current effective income tax rates.
The portion of the Company's deferred tax liabilities applicable to utility
operations which 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.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 109 "Accounting for Income Taxes." The
adoption of SFAS No. 109 changed the method of accounting for income taxes
from the deferred method to the asset and liability approach. The principal
effect on the Company's financial statements of adopting SFAS No. 109 is the
recording of deferred regulatory assets and liabilities primarily for income
taxes on temporary depreciation differences, which were previously flowed
through to ratepayers. Deferred regulatory assets were approximately $612,000
and $885,000 at December 31, 1995 and 1994, respectively. The deferred
regulatory liabilities primarily represent excess deferred income tax credits
resulting from the reduction in the federal income tax rate and also deferred
tax credits provided on investment tax credits which were previously flowed
through to ratepayers. Deferred regulatory liabilities were approximately
$1,308,000 and $1,233,000 at December 31, 1995 and 1994, respectively.
Changes in accumulated deferred income taxes related to the Company's non-
regulated operations were recorded in 1993 as a cumulative effect of change in
accounting principle on the income statement and a deferred tax asset on the
balance sheet. The result was a one-time increase to net income of $57,467.
The increase to net
31
<PAGE>
income resulted from a reduction in the deferred income taxes associated with
depreciation, coupled with the recording of net state tax loss carryforwards.
The Company had state tax loss carryforwards of $3,832,000 and $5,529,000 at
December 31, 1995 and 1994, respectively. The Company anticipates not using
$1,828,000 of the loss carryforwards at December 31, 1995. The Company has
recorded a full valuation allowance on the $1,828,000 at December 31, 1995.
The loss carryforwards expire in various years beginning in 1996 through 2007.
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 approximate their fair value (see Note B to the
Consolidated Financial Statements for disclosure of fair value of
investments). The fair value of the Company's long-term debt is estimated
using a discounted cash flow methodology. 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
(including current maturities) at December 31, 1995 is approximately $32.8
million as compared to the carrying value of $30.7 million. At December 31,
1994, the estimated fair value was approximately $24.6 million as compared to
a carrying value of $25.7 million.
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 base rates may not be changed without formal approval
by these commissions. The Company, except for its Florida division, 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-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 Company had sales to one customer, an industrial interruptible customer
of the natural gas transmission segment, which exceeded 10% of total revenue.
Total sales were approximately $10,600,000 or 10.2% and $9,600,000 or 11.2% of
total revenue during 1995 and 1993, respectively. During 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.
These customers, based on competitive pricing, can choose natural gas or
alternative types of supply. Neither the customer nor the Company is obligated
by contract to receive or deliver natural gas.
Earnings Per Share
Primary earnings per common share are based on the weighted average number
of shares of common stock outstanding, adjusted for stock options for each
year presented. On a fully diluted basis, both earnings and shares outstanding
are adjusted to assume the conversion of convertible debentures.
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
32
<PAGE>
judgements with respect to, among other things, various future economic
factors which are difficult to predict and are beyond the control of the
Company. Therefore, actual results could differ from those estimates.
The Company records certain assets and liabilities in accordance with
Statement of Accounting Standards ("SFAS") No.71. If the Company were required
to terminate application of SFAS No. 71 for all of its regulated operations,
all such 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.
Accounting Standards Issued
The Financial Accounting Standards Board issued SFAS No. 121 regarding
accounting for asset impairments. This statement, which must be adopted by the
Company for fiscal years beginning January 1,1996, requires that long-lived
assets be reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable.
Additionally, the standard requires rate-regulated companies 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,
"Accounting for the Effects of Certain Types of Regulation." Adoption of SFAS
No. 121 is not expected to have a material impact on the Company's financial
statements.
The Financial Accounting Standards Board issued SFAS No. 123 regarding
accounting for stock compensation. The Company plans to adopt the proforma
note disclosure requirements as prescribed in SFAS No. 123 in 1996.
Reclassification of Prior Years' Amounts
Certain prior years' amounts have been reclassified to conform with the 1995
presentation.
B. INVESTMENTS
The investment balance at December 31, 1995 and 1994 consists primarily of
the common stock of Florida Public Utilities Company ("FPU"). The Company's
ownership at December 31, 1995 and 1994 represents a 7.04% and 6.84% 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' equity. The aggregate cost basis of the
Company's portfolio at December 31, 1995 and 1994 exceeded its market value by
$120,839 and $401,609, respectively. In management's opinion, the decline in
the value of the stock is a temporary decline. At December 31, 1995 and 1994,
the investment was stated at the lower of cost or market, and the unrealized
loss was reported net of tax as a separate component of stockholders' equity.
C. WRITE-OFF OF INVESTMENT
During 1994, based on declining revenue and business projections, the
Company disposed of its investment in Currin & Associates, Inc., a rate and
regulatory consulting subsidiary acquired in 1988. Revenue declined from a
high of $593,000 in 1992 to a low of $51,000 in 1994. The disposition resulted
in a $260,000 after-tax loss recorded to Other Income and Deductions in 1994
on the income statement. The loss resulted from the write-off of good-will and
the disposition of other assets.
D. LEASE OBLIGATIONS
The Company has entered into several operating leases for office space at
various locations. Rent expense related to these leases was $407,314,
$418,043, and $439,445 for 1995, 1994 and 1993, respectively. Future minimum
payments under the Company's lease agreements are $383,207 in 1996; $197,396
in 1997; $121,229 in 1998; $124,754 in 1999; $128,836 in 2000; and $270,125
thereafter.
33
<PAGE>
E. SEGMENT INFORMATION
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING REVENUES, UNAFFILIATED
CUSTOMERS
Natural gas distribution............. $ 54,120,280 $ 49,523,743 $ 44,286,243
Natural gas transmission............. 24,984,767 22,191,896 20,094,343
Propane distribution................. 17,607,956 20,684,150 16,908,289
Information technology services and
other............................... 7,307,413 6,172,508 4,583,757
------------ ------------ ------------
Total operating revenues,
unaffiliated customers............ $104,020,416 $ 98,572,297 $ 85,872,632
============ ============ ============
INTERSEGMENT REVENUES*
Natural gas distribution............. $ 42,037 $ 55,888 $ 52,577
Natural gas transmission............. 16,663,043 17,303,529 17,345,800
Propane distribution................. 139,052 85,552 48,248
Information technology services...... 1,722,135 2,277,361 2,311,498
------------ ------------ ------------
Total intersegment revenues........ $ 18,566,267 $ 19,722,330 $ 19,758,123
============ ============ ============
OPERATING INCOME BEFORE INCOME TAXES
Natural gas distribution............. $ 4,728,348 $ 4,696,659 $ 4,114,683
Natural gas transmission............. 6,083,440 3,018,212 3,091,843
Propane distribution................. 1,852,630 2,287,688 1,588,383
Information technology services...... 1,170,970 174,033 156,910
------------ ------------ ------------
Total.............................. 13,835,388 10,176,592 8,951,819
Less: Eliminations................... (248,595) (419,883) (651,439)
------------ ------------ ------------
Total operating income before
income taxes...................... $ 13,586,793 $ 9,756,709 $ 8,300,380
============ ============ ============
DEPRECIATION AND AMORTIZATION
Natural gas distribution............. $ 2,502,531 $ 2,136,979 $ 1,938,344
Natural gas transmission............. 638,099 641,485 628,927
Propane distribution................. 1,312,048 1,323,698 1,370,590
Information technology services...... 969,588 1,021,944 1,131,914
Other plant.......................... 39,486 16,573 17,312
------------ ------------ ------------
Total depreciation and
amortization...................... $ 5,461,752 $ 5,140,679 $ 5,087,087
============ ============ ============
CAPITAL EXPENDITURES
Natural gas distribution............. $ 7,236,848 $ 8,160,874 $ 6,580,075
Natural gas transmission............. 1,335,793 619,852 1,497,910
Propane distribution................. 1,640,203 828,519 724,677
Information technology services...... 114,461 411,957 1,167,369
Other plant.......................... 1,772,454 632,137 93,756
------------ ------------ ------------
Total capital expenditures......... $ 12,099,759 $ 10,653,339 $ 10,063,787
============ ============ ============
IDENTIFIABLE ASSETS, AT DECEMBER 31,
Natural gas distribution............. $ 75,630,741 $ 68,528,774 $ 59,404,795
Natural gas transmission............. 19,292,524 17,792,415 18,212,489
Propane distribution................. 18,855,507 16,949,431 18,244,020
Information technology services...... 3,380,108 3,196,064 3,896,201
Other................................ 1,635,100 1,803,933 1,230,596
------------ ------------ ------------
Total identifiable assets.......... $118,793,980 $108,270,617 $100,988,101
============ ============ ============
</TABLE>
- --------
* All significant intersegment revenues have been eliminated from consolidated
revenues.
34
<PAGE>
F. LONG-TERM DEBT
The outstanding long-term debt, net of current maturities is as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
-----------------------
1995 1994
----------- -----------
<S> <C> <C>
First mortgage sinking fund bonds:
Adjustable rate Series G*, due January 1, 1998....... $ 312,500 $ 562,500
9.37% Series I, due December 15, 2004................ 5,340,000 5,860,000
12.00% Mortgage, due February 1, 1998................ 28,139 39,988
10.85% Senior uncollateralized note, due October 1,
2003................................................ 3,636,500
8.25% Convertible debentures, due March 1, 2014...... 4,114,000 4,230,000
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
----------- -----------
Total long-term debt................................... $29,794,639 $24,328,988
=========== ===========
</TABLE>
- --------
* The Series G bonds are subject to an interest rate equal to seventy-three
(73%) of the prime rate (8.5% at both December 31, 1995 and 1994).
The convertible debentures may be converted, at the option of the holder,
into shares of the Company's common stock at a conversion price of $17.01 per
share. 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, 1995, approximately $83,000 of the debentures have been
accepted for redemption. At the Company's 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, 1995, the amounts available for
future dividends permitted by the Series I covenant approximated $9.6 million.
A portion of the natural gas distribution plant assets owned by the Company
are subject to a lien under the mortgage pursuant to which the Company's first
mortgage sinking fund bonds are issued.
Annual maturities of consolidated long-term debt for the years 1996 through
2000 are $864,849, $783,271, $597,368, $1,520,000 and $2,665,091,
respectively.
G. SHORT-TERM BORROWINGS
The Board of Directors has authorized the Company to borrow up to
$14,000,000 from various bank and trust companies. As of December 31, 1995,
the Company had four $8,000,000 unsecured bank lines of credit, none of which
required compensating balances. Under these lines of credit at December 31,
1995 and 1994, the Company had short-term debt outstanding of $4,800,000 and
$8,000,000, respectively, with a weighted average interest rate of 6.00% and
6.04%, respectively.
35
<PAGE>
H. COMMON STOCK, ADDITIONAL PAID-IN CAPITAL AND TREASURY STOCK
The following is a schedule of changes in the Company's shares of common
stock:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER
31,
-------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
COMMON STOCK: SHARES ISSUED AND
OUTSTANDING*
Balance--beginning of year................ 3,668,791 3,605,152 3,522,670
Dividend Reinvestment Plan............... 38,660 30,928 27,942
USI restricted stock award agreements.... 14,138 32,418 54,540
Conversion of debentures................. 293
--------- --------- ---------
Balance--end of year...................... 3,721,589 3,668,791 3,605,152
========= ========= =========
SHARES OF COMMON STOCK HELD IN TREASURY
Balance--beginning of year................ 15,609 30,084 34,892
Sale of stock to Company's Retirement
Savings Plan............................ (15,609) (14,475) (4,808)
--------- --------- ---------
Balance--end of year...................... 15,609 30,084
========= ========= =========
</TABLE>
- --------
* $2,000,000 shares are authorized at a par value of $.4867 per share.
Certain key USI employees entered into restricted stock award agreements
under which shares of Chesapeake common stock can be issued. Shares are
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. Based on USI's 1995 earnings, 21,859 shares
of Chesapeake common stock will be issued in 1996. Of these shares, 4,372 will
have no restrictions, other than those that may be imposed by federal or state
securities laws. At December 31, 1995 and 1994, respectively, 29,598 and
48,716 shares valued at $415,107 and $696,679 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 the option to purchase shares of the
Company's common stock, exercisable in cumulative installments of one-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's achievement of the performance goals set forth in the Agreements.
When 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. In 1995, the Company recorded $211,000 to recognize the
compensation expense associated with the performance shares. Changes in
outstanding options were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
----------------------- ---------------------- ----------------------
NUMBER NUMBER NUMBER
OF OPTION OF OPTION OF OPTION
SHARES PRICE SHARES PRICE SHARES PRICE
------- -------------- ------- -------------- ------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance--beginning of
year................... 136,186 $12.625-$12.75 80,280 $12.75 92,525 $12.75-$16.33
Options granted......... 55,906 $12.625
Options expired......... (12,245) $16.33
Options forfeited....... (11,000) $12.625
------- ------- -------
Balance--end of year.... 125,186 $12.625-$12.75 136,186 $12.625-$12.75 80,280 $12.75
======= ======= =======
Exercisable............. 80,280 $12.75 53,520 $12.75 26,760 $12.75
</TABLE>
36
<PAGE>
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's
years of service and highest average compensation. The Company's funding
policy provides that payments to the trustee shall be equal to the minimum
funding requirements of the Employee Retirement Income Security Act of 1974.
Pension expense decreased in 1995, primarily due to an increase in the
discount rate to 8.5% from 7% in 1994. Pension expense decreased in 1994
because of a combination of factors, including (1) an increase in the discount
rate to 7% from 6.5%, (2) a decrease in the rate used for the average increase
in future compensation levels to 5.5% from 6% and (3) an increase in the
expected long-term rate of return on assets to 8.5% from 7.5%.
Total Net Pension Cost
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Service cost............................ $ 474,000 $ 592,294 $ 719,417
Interest cost........................... 562,003 518,184 511,536
Less: Actual (return) loss on assets.... (1,546,325) 742,949 (1,521,228)
Net amortization and deferral........... 689,947 (1,465,744) 1,031,618
----------- ----------- -----------
Total net pension cost.................. 179,625 387,683 741,343
Amounts capitalized as construction
cost................................... (30,740) (52,549) (108,827)
----------- ----------- -----------
Amount charged to expense............... $ 148,885 $ 335,134 $ 632,516
=========== =========== ===========
Discount rate used in calculating net
pension cost........................... 8.50% 7.00% 6.50%
</TABLE>
The following schedule sets forth the funding status of the pension plan at
December 31, 1995 and 1994:
Accrued Pension Cost
<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------
1995 1994
----------- -----------
<S> <C> <C>
Vested................................................ $ 5,730,239 $ 4,454,627
Nonvested............................................. 100,878 104,402
----------- -----------
Total accumulated benefit obligation.................. $ 5,831,117 $ 4,559,029
----------- -----------
Plan assets at fair value............................. $ 9,173,094 $ 7,799,483
Projected benefit obligation.......................... (9,331,890) (6,492,622)
----------- -----------
Plan assets less projected benefit obligation......... (158,796) 1,306,861
Unrecognized net gain................................. (2,319,138) (3,590,066)
Unamortized net assets from adoption of SFAS No. 87... (156,683) (171,787)
----------- -----------
Accrued pension cost.................................. $(2,634,617) $(2,454,992)
=========== ===========
ASSUMPTIONS:
Discount rate......................................... 7.25% 8.50%
Average increase in future compensation levels........ 5.50% 5.50%
Expected long-term rate of return on assets........... 8.50% 8.50%
</TABLE>
37
<PAGE>
Other Postretirement Benefits
The Company sponsors a defined benefit postretirement health care and life
insurance plan that covers substantially all natural gas and corporate
employees. In 1993, the Company adopted the provisions of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other than Pensions," which
requires that the expected cost of these future benefits be included in the
financial statements during the years employees render service. The
implementation resulted in an accumulated postretirement benefit obligation
(transition obligation) related to past employee service of $2,215,000. As
permitted, the Company elected to amortize this cost over 20 years. The
Company's 1993 cost under SFAS No. 106, including the amortization of the
transition obligation, was $400,000. 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 has deferred approximately $126,000, which
represents the difference between the Maryland divisions's SFAS No. 106
expense and its actual pay-as-you-go cost. The amount will be amortized over
five years starting in 1996.
Net Periodic Postretirement Benefit Cost
<TABLE>
<CAPTION>
AT DECEMBER 31,
----------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Service cost.................................. $ 1,827 $ 3,553 $119,000
Interest cost on APBO......................... 59,706 44,118 176,000
Amortization of transition obligation over 20
years........................................ 27,859 22,148 105,000
Curtailment loss.............................. 63,821
-------- -------- --------
NET PERIODIC POSTRETIREMENT BENEFIT COST...... 89,392 133,640 400,000
Amount capitalized as construction cost....... (14,010) (20,134) (52,112)
Amount deferred............................... (20,561) (13,212) (92,499)
-------- -------- --------
Amount charged to expense..................... $ 54,821 $100,294 $255,389
======== ======== ========
ASSUMPTION:
Discount rate................................. 8.50% 7.00% 6.50%
</TABLE>
Accrued Postretirement Benefit Liability
<TABLE>
<CAPTION>
AT DECEMBER 31,
--------------------
1995 1994
--------- ---------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees............................................. $ 616,664 $4426,624
Fully eligible active employees...................... 135,297 108,444
Other active......................................... 90,724 70,098
--------- ---------
Total accumulated postretirement benefit obligation.... 842,685 605,166
Unrecognized transition obligation..................... (300,872) (328,731)
Unrecognized net (loss) gain........................... (70,873) 139,637
--------- ---------
ACCRUED POSTRETIREMENT LIABILITY....................... $ 470,940 $ 416,072
========= =========
ASSUMPTION:
Discount rate.......................................... 7.25% 8.50%
</TABLE>
The health care inflation rate for 1995 is assumed to be 12%. 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
38
<PAGE>
the assumed rate would increase the accumulated postretirement benefit
obligation by approximately $81,000 as of January 1, 1996, and would increase
the aggregate of the service cost and interest cost components of net periodic
postretirement benefit cost for 1996 by approximately $7,000.
Retirement Savings Plan
The Company sponsors a Retirement Savings Plan, a 401(k) plan, which
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 to 60% or 100% of each
participant's pre-tax contributions not to exceed 6% of the participant's
eligible compensation for the plan year. The Company's contributions totaled
$301,794, $240,103 and $227,577 for the years ended December 31, 1995, 1994
and 1993, respectively.
Other Post Employment Benefits
During 1994, the Company adopted SFAS No. 112, "Employers' Accounting for
Postemployment Benefits," as required. SFAS No. 112 establishes standards of
financial accounting and reporting for the estimated cost of benefits provided
by an employer to former or inactive employees after employment but before
retirement. The adoption of SFAS No. 112 did not have a material effect on the
Company's results of operations.
J. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES
The Company currently is participating in the investigation, assessment or
remediation of four 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 issued the Record of Decision ("ROD") for the site, which
selected a remedial plan and estimated the costs of the selected remedy at
$2.7 million for groundwater 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 and the Company believe is liable under CERCLA.
Other potential responsible parties ("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 has informed EPA that it does not intend to comply with the Order.
The Company has commenced the design phase of the ROD.
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 support the Company's 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 within the next
two years. 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.
39
<PAGE>
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's rates.
The Company has accrued a liability with respect to the Salisbury site of
$1,113,572 as of December 31, 1995. This amount is based on the estimated
capital and operating costs as set forth in the Company's remedial action plan
submitted to the Maryland Department of the Environment ("MDE"). A
corresponding regulatory asset has been recorded, reflecting the Company's
belief that costs incurred will be recoverable in rates. The Company has begun
preliminary remediation procedures at the site and continues discussions with
MDE to finalize the remedial plan.
Portions of the liability payouts for the Dover and Salisbury sites are
expected to be over a 30 and five year period, respectively. In addition, the
Company has two other sites. One site is currently being evaluated for which
no estimate of liability can be made at this time. The other site has been
remediated and the Company is awaiting the site closure certificate. It is
management's opinion that any unrecovered current costs and any other future
costs incurred will be recoverable through future rates or sharing
arrangements with other responsible parties.
Environmental Costs Incurred
<TABLE>
<CAPTION>
AT DECEMBER 31,
---------------------
1995 1994
---------- ----------
<S> <C> <C>
Delaware.............................................. $3,929,417 $3,144,366
Maryland.............................................. 1,805,572 1,722,757
Florida............................................... 629,153 594,844
---------- ----------
6,364,142 5,461,967
Less: Amounts approved for ratemaking treatment,
net of insurance proceeds....................... 6,066,096 3,262,590
---------- ----------
Amounts pending ratemaking recovery................... $ 298,046 $2,199,377
========== ==========
</TABLE>
K. COMMITMENTS AND CONTINGENCIES
FERC PGA
On May 19, 1994, the FERC issued an Order directing 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
the 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 for. 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
40
<PAGE>
$234,000 per year. The reserves the Company had been accruing for the
potential refund were significantly greater than the rate reduction ordered.
Accordingly, Eastern Shore has reversed a large portion of the estimated
liability that it had been accruing. 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. The implementation of open
access transportation service, expected to occur during the second half of
1996, 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.
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 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.
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's
business, there are substantial variations in operations reported on a
quarterly basis.
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
1995
Operating Revenue............ $30,896,798 $22,074,663 $20,564,994 $30,483,961
Operating Income............. $ 4,330,962 $ 1,369,342 $ 1,492,200 $ 2,369,015
Net Income................... $ 3,658,431 $ 764,085 $ 988,122 $ 1,826,057
Primary Earnings Per Share... $ 1.00 $ 0.21 $ 0.27 $ 0.49
Fully Diluted Earnings Per
Share....................... $ 0.95 $ 0.21 $ 0.26 $ 0.47
1994
Operating Revenue............ $36,009,510 $19,868,566 $18,789,776 $23,904,445
Operating Income............. $ 4,322,605 $ 588,550 $ 296,110 $ 2,019,809
Net Income (Loss)............ $ 3,746,087 $ (116,584) $ (264,773) $ 1,095,192
Primary Earnings (Loss) Per
Share....................... $ 1.04 $ (0.03) $ (0.07) $ 0.30
Fully Diluted Earnings (Loss)
Per Share................... $ 0.98 $ (0.02) $ (0.05) $ 0.29
</TABLE>
Results for the third quarter 1995 reflect a non-recurring increase in net
income of $833,000, (see Note K to the Consolidated Financial Statements).
41
<PAGE>
OPERATING STATISTICS
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------------
1995 1994 1993 1992 1991
-------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
REVENUES (IN THOUSANDS)
Natural gas
Residential..................... $ 14,857 $15,228 $14,007 $12,935 $11,167
Commercial...................... 11,383 11,594 10,837 9,857 8,606
Industrial...................... 36,898 32,718 31,622 26,977 26,660
Sale for resale................. 12,459 9,586 5,242 3,843 3,437
Transportation.................. 2,993 2,639 2,480 2,400 1,555
Other........................... 515 (50) 193 (134) 44
-------- ------- ------- ------- -------
Total natural gas revenues........ 79,105 71,715 64,381 55,878 51,469
Propane........................... 17,608 17,789* 16,908 16,489 14,961
Other............................. 7,307 6,173 4,584 3,568 3,398
-------- ------- ------- ------- -------
Total revenues...................... $104,020 $95,677 $85,873 $75,935 $69,828
======== ======= ======= ======= =======
VOLUMES
Natural gas deliveries (in MMCF)
Residential..................... 1,686 1,665 1,596 1,561 1,337
Commercial...................... 1,792 1,771 1,676 1,633 1,445
Industrial...................... 13,639 10,752 9,308 8,014 8,396
Sale for resale................. 990 998 984 997 922
Transportation.................. 11,131 7,542 5,880 5,139 4,237
-------- ------- ------- ------- -------
Total natural gas deliveries...... 29,238 22,728 19,444 17,344 16,337
======== ======= ======= ======= =======
Propane (in thousands of gallons). 17,748 18,395* 17,250 17,125 14,837
======== ======= ======= ======= =======
CUSTOMERS
Natural gas
Residential..................... 29,285 28,260 27,312 26,523 25,710
Commercial...................... 4,030 3,879 3,759 3,683 3,560
Industrial**.................... 212 204 196 198 191
Sale for resale**............... 3 3 3 3 3
-------- ------- ------- ------- -------
Total natural gas customers....... 33,530 32,346 31,270 30,407 29,464
Propane......................... 22,609 22,180 21,622 21,132 22,145
-------- ------- ------- ------- -------
Total customers................... 56,139 54,526 52,892 51,539 51,609
======== ======= ======= ======= =======
</TABLE>
- --------
* 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.
42
<PAGE>
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 8,
1996 in connection with the Company's Annual Meeting to be held on May 21,
1996.
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 8, 1996 in connection with the Company's Annual Meeting to be held on
May 21, 1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company's Securities", dated and to be
filed on or before April 8, 1996 in connection with the Company's Annual
Meeting to be held on May 21, 1996.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company's Securities", dated and to be
filed on or before April 8, 1996 in connection with the Company's Annual
Meeting to be held on May 21, 1996.
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' Report dated February 9, 1996 of Coopers & Lybrand
L.L.P., Independent Accountants
--Consolidated Statements of Income for each of the three years
ended December 31, 1995, 1994 and 1993
--Consolidated Balance Sheets at December 31, 1995 and December 31,
1994
--Consolidated Statements of Cash Flows for each of the three years
ended December 31, 1995
--Consolidated Statements of Common Stockholders' Equity for each of
the three years ended December 31, 1995
--Consolidated Statements of Income Taxes for each of the three
years ended December 31, 1995
--Notes to Consolidated Financial Statements
2. The following additional information for the years 1995, 1994 and
1993 is submitted herewith:
--Schedule II--Valuation and Qualifying Accounts
43
<PAGE>
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
On August 23, 1995, the Company filed a report on Form 8-K, reporting under
Item 5 Eastern Shore's settlement with the FERC, described in Note K to the
Consolidated Financial Statements.
On October 20, 1995, the Company filed a report on Form 8-K, reporting under
Item 5 that the Company changed transfer agent to Bank of Boston.
(c) Exhibits
Exhibit 3.(a) --Certificate of Incorporation
Amended Certificate of Incorporation of Chesapeake Utilities
Corporation, is incorporated herein by reference to
Exhibit 3.(b) to the Form 10Q for the quarterly period ended
June 30, 1995, of Chesapeake Utilities Corporation.
Exhibit 3.(b) --Bylaws
Amended Bylaws of Chesapeake Utilities Corporation, are
incorporated herein by reference to Exhibit 3.(b) to the Annual
Report on Form 10K for the year ended December 31, 1994 of
Chesapeake Utilities Corporation.
Exhibit 4.(a) --The Form of Indenture between the Company and Boatmen's Trust
Company, Trustee, with respect to the 8 1/4% Convertible
Debentures is incorporated herein by reference to Exhibit 4.2
of the Company's Registration Statement on Form S-2, Reg.
No. 33-26582, filed on January 13, 1989.
Exhibit 4.(b) --Note Agreement dated February 9, 1993, by and between the
Company and Massachusetts Mutual Life Insurance Company and MML
Pension Insurance Company, with respect to $10,000,000 7.97%
Unsecured Senior Notes due February 1, 2008, is incorporated
herein by reference to Exhibit 4.(b) to the Annual Report on
Form 10-K for the year ended December 31, 1992, of Chesapeake
Utilities Corporation.*
Exhibit 4.(c) --The Directors Stock Compensation Plan adopted by Chesapeake
Utilities Corporation in 1995, is incorporated herein by
reference to the Company's Proxy Statement dated April 17,
1995, in connection with the Company's annual meeting held in
May, 1995.
Exhibit 4.(d) --The 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) --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) to the Annual Report on Form 10-K for the year
ended December 31, 1989, of Chesapeake Utilities Corporation.*
Exhibit 10.(b) --Service Agreement dated November 1, 1989, by and between
Columbia Gas Transmission Corporation and Eastern Shore Natural
Gas Company, is incorporated herein by reference to Exhibit
10.(b) to the Annual Report on Form 10-K for the year ended
December 31, 1989, of Chesapeake Utilities Corporation.*
Exhibit 10.(c) --Service Agreement for General Service dated November 1, 1989,
by and between Florida Gas Transmission Company and Chesapeake
Utilities Corporation, is incorporated herein by reference to
Exhibit 10.(c) to the Annual Report on Form 10-K for the year
ended December 31, 1990, of Chesapeake Utilities Corporation.*
44
<PAGE>
Exhibit 10.(d) --Service Agreement for Preferred Service dated November 1, 1989,
by and between Florida Gas Transmission Company and Chesapeake
Utilities Corporation, is incorporated herein by reference to
Exhibit 10.(d) to the Annual Report on Form 10-K for the year
ended December 31, 1990, of Chesapeake Utilities Corporation.*
Exhibit 10.(e) --Service Agreement for Firm Transportation Service dated
November 1, 1989, by and between Florida Gas Transmission
Company and Chesapeake Utilities Corporation, is incorporated
herein by reference to Exhibit 10.(e) to the Annual Report on
Form 10-K for the year ended December 31, 1990, of Chesapeake
Utilities Corporation.*
Exhibit 10.(f) --Form of Service Agreement for Interruptible Sales Services
dated May 11, 1990, by and between Florida Gas Transmission
Company and Chesapeake Utilities Corporation, is incorporated
herein by reference to Exhibit 10.(f) to the Annual Report on
Form 10-K for the year ended December 31, 1990, of Chesapeake
Utilities Corporation.*
Exhibit 10.(g) --Interruptible Transportation Service Agreement dated February
23, 1990, by and between Florida Gas Transmission Company and
Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10.(g) to the Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake Utilities
Corporation.*
Exhibit 10.(h) --Interruptible Transportation Service Agreement dated November
30, 1990, by and between Florida Gas Transmission Company and
Chesapeake Utilities Corporation, is incorporated herein by
reference to Exhibit 10.(h) to the Annual Report on Form 10-K
for the year ended December 31, 1990, of Chesapeake Utilities
Corporation.*
Exhibit 10.(i) --Executive Employment Agreement dated March 26, 1992, by and
between Chesapeake Utilities Corporation and 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) to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 1992, of Chesapeake Utilities Corporation.*
Exhibit 10.(k) --Chesapeake Utilities Corporation Cash Bonus Incentive Plan
dated January 1, 1992, is incorporated herein by reference to
Exhibit 10.(o) to the Annual Report on Form 10-K for the year
ended December 31, 1991, of Chesapeake Utilities Corporation.*
Exhibit 10.(l) --Chesapeake Utilities Corporation Performance Incentive Plan
dated January 1, 1992, is incorporated herein by reference
to the Company's Proxy Statement dated April 20, 1992, in
connection with the Company's Annual Meeting held on May 19,
1992.
Exhibit 10.(m) --Form of Tandem Stock Option and Performance Share Agreement
dated November 18, 1994, pursuant to Chesapeake Utilities
Corporation Performance Incentive Plan by and between
Chesapeake Utilities Corporation and Ralph J. Adkins, John R.
Schimkaitis, Philip S. Barefoot and Jerry D. West, filed is
incorporated herein by reference to exhibit 3.(b) to the Annual
Report on Form 10K for the year ended December 31, 1994 for
Chesapeake Utilities Corporation.*
Exhibit 11. --Computation of Primary and Fully Diluted Earnings Per Share,
filed herewith.
Exhibit 12. --Computation of Ratio of Earning to Fixed Charges, filed
herewith.
Exhibit 21. --Subsidiaries of the Registrant, filed herewith.
Exhibit 23. --Consent of Independent Accountants, filed herewith.
- --------
* Filed under commission file #0-593.
45
<PAGE>
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
/s/ Ralph J. Adkins
By __________________________________
RALPH J. ADKINS PRESIDENT AND
CHIEF EXECUTIVE OFFICER
March 25, 1996
Date: _______________________________
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.
SIGNATURES TITLE DATE
/s/ John W. Jardine, Jr. Chairman of the March 25, 1996
- ------------------------------------- Board and Director
JOHN W. JARDINE, JR.
/s/ Ralph J. Adkins President, Chief March 25, 1996
- ------------------------------------- Executive Officer
RALPH J. ADKINS and Director
/s/ John R. Schimkaitis Executive Vice March 25, 1996
- ------------------------------------- President,
JOHN R. SCHIMKAITIS Assistant Treasurer
and Director
(Principal
Financial Officer
and Principal
Accounting Officer)
/s/ Richard Bernstein Director March 25, 1996
- -------------------------------------
RICHARD BERNSTEIN
/s/ Walter J. Coleman Director March 25, 1996
- -------------------------------------
WALTER J. COLEMAN
/s/ Rudolph M. Peins, Jr. Director March 25, 1996
- -------------------------------------
RUDOLPH M. PEINS, JR.
/s/ Robert F. Rider Director March 25, 1996
- -------------------------------------
ROBERT F. RIDER
/s/ Jeremiah P. Shea Director March 25, 1996
- -------------------------------------
JEREMIAH P. SHEA
/s/ William G. Warden, III Director March 25, 1996
- -------------------------------------
WILLIAM G. WARDEN, III
46
<PAGE>
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------- -------- -------------------- ---------- --------
ADDITIONS
--------------------
BALANCE AT CHARGED TO CHARGED BALANCE AT
BEGINING COSTS AND TO OTHER END
DESCRIPTION OF PERIOD EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD
- ------------------------ ---------- ---------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserves deducted in the Balance Sheet
from the assets to which they apply:
Accumulated Provision for
Uncollectibles
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
1993.................................. $239,019 $ 82,672 $ 66,246(B) $(201,919)(A,C) $186,018
Valuation Allowance
Net unrealized (gain) loss on
available for sale securities
1995.................................. $241,609 -- $(168,770)(C) -- $ 72,839
1994.................................. $ 90,517 -- $ 151,092(C) -- $241,609
1993.................................. $ 32,151 -- $ 58,366(C) -- $ 90,517
Valuation Allowance
State income tax
loss carryforwards
1995.................................. $341,056 -- $(181,193)(D) -- $159,863
1994.................................. $354,928 -- $ (13,872)(D) -- $341,056
1993.................................. -- -- $ 354,928(D) -- $354,928
</TABLE>
- --------
Notes:
(A) Uncollectible accounts charged off.
(B) Recoveries.
(C) Represents net unrealized (gains)/losses (credited)/charged to common
stockholders' equity.
(D) Represents adjustments to current income tax expense.
47
<PAGE>
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
EXHIBIT 11
COMPUTATION OF PRIMARY AND FULLY DILUTED EARNINGS PER SHARE
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
ITEM 1995 1994 1993
---- ---------- ---------- ----------
<S> <C> <C> <C>
Shares issued at beginning of year......... 3,668,791 3,605,152 3,522,670
Treasury stock at beginning of year........ (15,609) (30,084) (34,892)
Sale of treasury stock..................... 15,609 14,475 4,808
Issuance of common stock for dividend
reinvestment plan......................... 38,660 30,928 27,942
Issuance of common stock pursuant to USI
restricted stock award agreement.......... 14,138 32,418 54,540
Issuance of common stock for conversion of
debentures................................ 293
---------- ---------- ----------
Shares outstanding at end of year.......... 3,721,589 3,653,182 3,575,068
========== ========== ==========
Primary earnings per share calculation:
Weighted average number of shares
assuming primary dilution............... 3,701,891 3,632,413 3,556,037
---------- ---------- ----------
Consolidated net income.................. $7,236,695 $4,459,922 $3,971,671
---------- ---------- ----------
Primary earnings per share............... $ 1.95 $ 1.23 $ 1.12
---------- ---------- ----------
Fully diluted earnings per share
calculation:
Weighted average number of shares
assuming primary dilution............... 3,701,891 3,632,413 3,556,037
Contingent shares related to assumed
conversion of convertible debt.......... 248,833 255,777 260,258
---------- ---------- ----------
Weighted average number of shares
assuming full dilution.................. 3,950,724 3,888,190 3,816,295
---------- ---------- ----------
Adjusted income
Net income............................... $7,236,695 $4,459,922 $3,971,671
Interest on convertible debt............. 349,251 358,998 365,284
Less: Applicable income taxes............ (136,208) (140,009) (142,461)
---------- ---------- ----------
Adjusted net income........................ $7,449,738 $4,678,911 $4,194,494
---------- ---------- ----------
Fully diluted earnings per share........... $ 1.89 $ 1.20* $ 1.10*
========== ========== ==========
</TABLE>
- --------
NOTES:
* This calculation is submitted in accordance with Regulation S-K item
601(b)(11) although not required by footnote 2 to paragraph 14 of APB
Opinion No. 15 because it results in dilution of less than 3%.
48
<PAGE>
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1995 1994 1993
----------- ---------- ----------
<S> <C> <C> <C>
Income from continuing operations............ $ 7,236,695 $4,459,922 $3,971,671
Add:
Income taxes............................... 4,131,177 2,542,368 1,968,822
Portion of rents representative of interest
factor.................................... 182,211 187,012 199,021
Interest on indebtedness................... 2,666,223 2,637,654 2,702,013
Amortization of debt discount and expense.. 109,399 103,859 100,797
----------- ---------- ----------
Earnings as adjusted....................... $14,325,705 $9,930,815 $8,942,324
=========== ========== ==========
Fixed Charges
Portion of rents representative of interest
factor.................................... $ 182,211 $ 187,012 $ 199,021
Interest on indebtedness................... 2,666,223 2,637,654 2,702,013
Amortization of debt discount and expense.. 109,399 103,859 100,797
----------- ---------- ----------
Fixed Charges.............................. $ 2,957,833 $2,928,525 $3,001,831
=========== ========== ==========
Ratio of Earnings to Fixed Charges........... 4.84 3.39 2.98
=========== ========== ==========
</TABLE>
49
<PAGE>
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
SUBSIDIARIES STATE INCORPORATED
Eastern Shore Natural Gas Company Delaware
Sharp Energy, Inc. Delaware
Chesapeake Services Company Delaware
United Systems, Inc. Georgia
SUBSIDIARY OF EASTERN SHORE NATURAL GAS COMPANY STATE INCORPORATED
Dover Exploration Company Delaware
SUBSIDIARIES OF SHARP ENERGY, INC. STATE INCORPORATED
Sharpgas, Inc. Delaware
Sharpoil, Inc. Delaware
SUBSIDIARIES OF CHESAPEAKE SERVICE COMPANY STATE INCORPORATED
Skipjack, Inc. Delaware
Capital Data Systems, Inc. North Carolina
Currin and Associates, Inc. North Carolina
Chesapeake Investment Company Delaware
50
<PAGE>
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
----------------
We consent to the incorporation by reference in the Prospectuses prepared in
accordance with the requirements of Forms S-2 (File No. 33-26582), Forms S-3
(File Nos. 33-28391, and 33-64671) and Form S-8 (File No. 33-301175) of our
report dated February 9, 1996 accompanying the consolidated financial
statements and the consolidated financial statement schedule of Chesapeake
Utilities Corporation as of December 31, 1995 and 1994 and for each of the
three years in the period ended December 31, 1995, included in this Annual
Report on Form 10-K of Chesapeake Utilities Corporation.
Coopers & Lybrand L.L.P.
Baltimore, Maryland
March 27, 1996
51
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 65,419,372
<OTHER-PROPERTY-AND-INVEST> 18,253,459
<TOTAL-CURRENT-ASSETS> 21,028,468
<TOTAL-DEFERRED-CHARGES> 14,092,681
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 118,793,980
<COMMON> 1,811,211
<CAPITAL-SURPLUS-PAID-IN> 17,592,242
<RETAINED-EARNINGS> 23,385,097
<TOTAL-COMMON-STOCKHOLDERS-EQ> 42,300,604
0
0
<LONG-TERM-DEBT-NET> 29,794,639
<SHORT-TERM-NOTES> 4,800,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 864,849
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 40,545,942
<TOT-CAPITALIZATION-AND-LIAB> 118,793,980
<GROSS-OPERATING-REVENUE> 104,020,416
<INCOME-TAX-EXPENSE> 4,025,274
<OTHER-OPERATING-EXPENSES> 90,433,623
<TOTAL-OPERATING-EXPENSES> 94,458,897
<OPERATING-INCOME-LOSS> 9,561,519
<OTHER-INCOME-NET> 357,316
<INCOME-BEFORE-INTEREST-EXPEN> 9,918,835
<TOTAL-INTEREST-EXPENSE> 2,682,140
<NET-INCOME> 7,236,695
0
<EARNINGS-AVAILABLE-FOR-COMM> 7,236,695
<COMMON-STOCK-DIVIDENDS> 3,331,972
<TOTAL-INTEREST-ON-BONDS> 2,276,179
<CASH-FLOW-OPERATIONS> 12,997,955
<EPS-PRIMARY> 1.95
<EPS-DILUTED> 1.89
</TABLE>
