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As filed with the Securities and Exchange Commission on March 19, 1997
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1996 Commission File Number 0-593
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Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)
State of Delaware 51-0064146
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices) (Zip Code)
Registrant'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
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Common Stock - par value per share $.4867 New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
8.25% Convertible Debentures Due 2014
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant'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 14, 1997, 4,452,704 shares of common stock were outstanding. The
aggregate market value of the common shares held by non-affiliates of Chesapeake
Utilities Corporation, based on the last trade price on March 14, 1997, as
reported by the New York Stock Exchange, was approximately $78,478,908.
DOCUMENTS INCORPORATED BY REFERENCE
Documents Part of Form 10-K
Definitive Proxy Statement dated April 4, 1997 Part III
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CHESAPEAKE UTILITIES CORPORATION
FORM 10-K
Year Ended December 31, 1996
TABLE OF CONTENTS
PART I
Page
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Item 1. Business.............................................. 1
Item 2. Properties............................................ 13
Item 3. Legal Proceedings..................................... 13
Item 4. Submission of Matters to a Vote of Security Holders... 17
Item 10. Executive Officers of the Registrant.................. 17
PART II
Item 5. Market for Registrant's Common Stock and Related
Security Holder Matters............................... 18
Item 6. Selected Financial Data............................... 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 21
Item 8. Financial Statements and Supplementary Data........... 27
Item 9. Changes In and Disagreements with Accountants
on Accounting and Financial Disclosure................ 47
PART III
Item 10. Directors and Executive Officers of the Registrant.... 47
Item 11. Executive Compensation................................ 47
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................. 47
Item 13. Certain Relationships and Related Transactions........ 47
PART IV
Item 14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K...................... 47
Signatures ...................................................... 51
PART I
Item 1. Business
(a) General Development of Business
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a
diversified utility company engaged in natural gas distribution and
transmission, propane distribution and advanced information services.
Chesapeake's three natural gas distribution divisions serve approximately 34,700
residential, commercial and industrial customers in southern Delaware,
Maryland's Eastern Shore and Central Florida. The Company's natural gas
transmission subsidiary Eastern Shore Natural Gas Company ("Eastern Shore"),
operates a 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 23,100 customers in southern Delaware and the Eastern Shore of
Maryland and Virginia. The advanced information services segment provides
software services and products to a wide variety of customers and clients.
(b) Financial Information About Industry Segments
Portions of Segment data from Annual Report. (Note E)
For the Years Ended December 31,
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1996 1995 1994
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Operating Revenues, Unaffiliated Customers
Natural gas distribution $74,904,076 $54,120,280 $49,523,743
Natural gas transmission 15,188,777 24,984,767 22,191,896
Propane distribution 22,333,969 17,607,956 20,684,150
Advanced information services and other 6,903,246 7,307,413 6,172,508
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Total operating revenues, unaffiliated customers $119,330,068 $104,020,416 $98,572,297
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Intersegment Revenues *
Natural gas distribution $8,711 $42,037 $55,888
Natural gas transmission 21,543,327 16,663,043 17,303,529
Propane distribution 2,059 139,052 85,552
Advanced information services and other 710,949 1,722,135 2,277,361
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Total intersegment revenues $22,265,046 $18,566,267 $19,722,330
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Operating Income Before Income Taxes
Natural gas distribution $7,167,236 $4,728,348 $4,696,659
Natural gas transmission 2,458,442 6,083,440 3,018,212
Propane distribution 2,053,299 1,852,630 2,287,688
Advanced information services and other 1,305,203 1,170,970 174,033
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Total 12,984,180 13,835,388 10,176,592
Add (Less): Eliminations 206,580 (248,595) (419,883)
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Total operating income before income taxes $13,190,760 $13,586,793 $9,756,709
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Identifiable Assets, at December 31,
Natural gas distribution $81,250,030 $75,630,741 $68,528,774
Natural gas transmission 23,981,989 19,292,524 17,792,415
Propane distribution 20,791,588 18,855,507 16,949,431
Advanced information services 1,496,418 1,635,100 3,196,064
Other 3,617,885 3,380,108 1,803,933
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Total identifiable assets $131,137,910 $118,793,980 $108,270,617
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* All significant intersegment revenues have been eliminated from
consolidated revenues.
(c) Narrative Description of Business
The Company is engaged in four primary business activities: natural gas
transmission; natural gas distribution; propane distribution; and advanced
information services. In addition to the four primary groups, Chesapeake has
three subsidiaries engaged in other service related businesses. During 1996 and
1994, no individual customer accounted for 10% or more of operating revenues.
In 1995, the Company had sales to one customer, Texaco Refining and Marketing,
an industrial interruptible customer of Eastern Shore, which exceeded 10% of
total revenue. Total sales to this customer were approximately $10.6 million or
10.2% of total revenue during 1995.
(i) (a) Natural Gas Transmission
Eastern Shore, the Company'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 1996 and previously,
Eastern Shore was not an open access pipeline (see competition within natural
gas industry) 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.
Natural Gas Supply
General. Eastern Shore has firm contracts with three major interstate
pipelines, Transcontinental Gas 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 bundled storage services providing a peak day entitlement
of 7,046 Mcf and a total capacity of 278,264 Mcf; and (d) two unbundled
storage services with a total capacity of 432,663 Mcf.
Eastern Shore's contracts with Columbia include: (a) firm transportation
capacity of 1,481 Mcf per day, which expires in 2004; (b) firm transportation
capacity of 1,971 Mcf per day, which commences in 1997 and expires in 2017;
(c) firm transportation capacity of 869 Mcf per day, which commences in 1998
and expires in 2018; (d) firm transportation capacity of 869 Mcf per day,
which commences in 1999 and expires 2019; and (e) firm transportation capacity
of 192 Mcf per day for April through August, which expires in 2003. Eastern
Shore's contracts with Columbia also include: (a) firm storage service
providing a peak day entitlement of 10,525 Mcf and a total capacity of 509,954
Mcf, which expires in 2004; (b) firm storage service providing a peak day
entitlement of 1,150 Mcf and a total capacity of 103,459 Mcf, which commences
in 1997 and expires in 2017; (c) firm storage service providing a peak day
entitlement of 563 Mcf and a total capacity of 50,686 Mcf, which commences in
1998 and expires in 2018; and (d) firm storage service providing a peak day
entitlement of 563 Mcf and a total capacity of 50,686 Mcf, which commences in
1999 and expires in 2019.
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 supply contracts provide a
maximum firm daily entitlement of 20,469 Mcf, which is transported by both
Transco and Columbia under Eastern Shore's firm transportation contracts. The
gas purchase contracts have various expiration dates.
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Adequacy of Gas Supply. Eastern Shore's firm natural gas obligations to its
customers, including Chesapeake's Delaware and Maryland utility divisions, are
40,237 Mcf for peak days and 9,180,203 Mcf on an annual basis. Eastern Shore'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
38,540 Mcf and its total annual firm supply is 6,032,665 Mcf. This is
equivalent to 96% of Eastern Shore's firm daily demand and approximately 66%
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 and/or Columbia and sold to Eastern Shore's customers as needed.
The Company believes that Eastern Shore's available firm 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 1996, nor does
Eastern Shore anticipate any such curtailment during 1997.
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 cost of conversion is a
dis-incentive for individuals and businesses to change their energy source.
Competition within the Natural Gas Industry. FERC Order 636 enables all
natural gas suppliers to compete for customers on an equal footing. Under this
open access environment, interstate pipeline companies have unbundled the
traditional components of their service -- gas gathering, transportation and
storage from the sale of the commodity. If they choose to be a merchant of
gas, they must form a separate marketing operation independent of their
pipeline operations. Hence, gas marketers have developed as a viable option
for many companies because they are providing expertise in gas purchasing
along with collective purchasing capabilities which, when combined, may reduce
end-user cost.
Currently, Eastern Shore is 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
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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 1997, 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 "Open Access Plan Filing" and Management Discussion
and Analysis of financial condition and results of operations.
Rates and Regulation
General. Eastern Shore is subject to regulation by the FERC as an interstate
pipeline and the Delaware Public Service Commission ("Commission") as a
supplier of gas to industrial customers in the state of Delaware. The FERC
regulates the provision of service, terms and conditions of service, and the
rates and fees Eastern Shore can charge its transportation and sale for resale
customers. In addition, the FERC regulates the rates Eastern Shore is charged
for transportation and transmission line capacity or services provided by
Transco and Columbia. Eastern Shore's direct sales rates to industrial
customers are currently not regulated. The rates for such sales are
established by contracts negotiated between Eastern Shore and each industrial
customer.
After Eastern Shore becomes an open access pipeline, the FERC will have sole
regulatory authority over Eastern Shore. Accordingly, the Delaware Public
Service Commission will cease having any regulatory authority over Eastern
Shore.
The rates for Eastern Shore's "sale for resale" customers (i.e., sales to its
utility customers) are subject to a purchased gas adjustment clause. Eastern
Shore's firm industrial contracts generally include tracking provisions that
permit automatic adjustment for the full amount of increases or decreases in
Eastern Shore's suppliers' firm rates.
Regulatory Proceedings
FERC PGA. On May 19, 1994, the FERC issued an Order directing Eastern Shore
to refund, with interest, what the FERC characterized as overcharges from
November 1, 1992 to the current billing month. The May 19, 1994 Order also
directed Eastern Shore to file a report showing how the refund was calculated,
and revised tariff language clarifying the purchased gas adjustment provisions
in its tariff.
On August 17, 1995, the FERC issued an Order approving an Offer of Settlement
submitted by Eastern Shore. The Order approved a change in Eastern Shore's PGA
methodology retroactive to June 1, 1994, which will result in a rate reduction
of approximately $234,000 per year. The estimated liability that the Company
had accrued for the potential refund was significantly greater than the rate
reduction ordered. Accordingly, Eastern Shore reversed a large portion of the
liability that it had accrued. This reversal contributed $1,385,000 to pre-tax
earnings or $833,000 to after-tax earnings during the third quarter of 1995.
In connection with the FERC Order, Eastern Shore applied in December 1995, to
the FERC for a blanket certificate authorizing open access transportation
service on its pipeline system. For further discussion see "Open Access Plan
Filing" below.
Delaware City Compressor Station Filing. On December 5, 1995, Eastern Shore
filed an application before the FERC pursuant to Sections 7(b) and (c) of the
Natural Gas Act for a certificate of public convenience and necessity
authorizing Eastern Shore to: (1) construct and operate a 2,170 horsepower
compressor station in Delaware City, New Castle County, Delaware on a portion
of its existing pipeline system known as the "Hockessin Line", such new
station to be known as the "Delaware City Compressor Station"; (2) construct
and operate slightly less than one mile of 16-inch pipeline in Delaware City,
New Castle County, Delaware to tie the suction side of the proposed Delaware
City Compressor Station into the Hockessin Line; and (3) increase
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the maximum allowable operating pressure ("MAOP") from 500 PSIG to 590 PSIG on
28.7 miles of Eastern Shore's pipeline from Eastern Shore's existing
Bridgeville Compressor Station in Bridgeville, Sussex County, Delaware to its
terminus in Salisbury, Wicomico County, Maryland.
The compressor facility and associated piping are needed to stabilize capacity
on Eastern Shore's system as a result of steadily declining inlet pressures at
the Hockessin interconnect with Transcontinental Gas Pipe Line Corporation.
Construction of the facilities started during the second half of 1996. The
proposed in-service date of the facilities is March 19, 1997. Eastern Shore
estimates the total cost of the compressor facilities to be $6.9 million.
The proposed facilities would also enable Eastern Shore to provide additional
firm services to several of its customers who have executed agreements for the
additional firm service for terms of 10 and 20 years. Eastern Shore also
requested authorization to abandon 100 Mcf per day of firm sales service to
one of its direct sales customers.
On September 28, 1996 the FERC issued its Final Order, which:
. authorized Eastern Shore to construct and operate the facilities
requested in its application;
. authorized Eastern Shore to roll-in the cost of the facilities into its
existing rates if the revenues from the increase in services exceed the
cost associated with the expansion portion of the project;
. denied Eastern Shore the authority to increase the level of sales and
storage service it provides its customers until it completes its
restructuring in its open access proceeding; and
. authorized Eastern Shore to abandon the 100 Mcf per day of firm sale
service, to one of its direct sale customers.
Rate Case Filing. On October 15, 1996 Eastern Shore filed for a general rate
increase with the FERC. The filing proposed an increase in Eastern Shore's
jurisdictional rates that would generate additional annual operating revenue
of approximately $1,445,000. Eastern Shore also stated in the filing that it
intended to use the cost-of-service submitted in the general rate increase
filing to develop rates in the pending Open Access Docket. The Commission, by
letter order dated November 14, 1995, suspended the tariff sheets for the
maximum five-month period as allowed by Commission regulation.
On March 4, 1997, a pre-hearing conference was conducted at FERC's office to
establish a procedural schedule to establish a preliminary list of contested
issues and to advise the Presiding Judge of any matters which need to be
resolved. Hearings are tentatively scheduled to start in 1997.
Open Access Filing. On December 29, 1995, Eastern Shore filed its abbreviated
application for a blanket certificate of public convenience and necessity
authorizing the transportation of natural gas on behalf of others.
Eastern Shore proposed to unbundle the sales and storage services it currently
provides. Customers receiving firm sales and storage services on Eastern Shore
(the "Converting Customers") would receive entitlements to firm transportation
service on Eastern Shore's pipeline in a quantity equivalent to their current
service rights. Eastern Shore proposed to retain some of its pipeline
entitlements and storage capacity for operational issues and to facilitate
"no-notice" (no prior notification required to receive service) transportation
service on its pipeline system. Eastern Shore will release or assign to the
remaining Converting Customers the firm transportation capacity, including
contract storage, it holds on its upstream pipelines so that the Converting
Customers can become direct customers of such upstream pipelines. Converting
Customers who previously received bundled sales service having no-notice
characteristics will have the right to elect no-notice firm transportation
service.
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With respect to cost classification, allocation and rate design, Eastern Shore
proposes to implement straight fixed variable ("SFV") cost classification. In
order to accomplish a change from its current modified fixed variable ("MFV")
rate design, Eastern Shore made a Section 4 rate filing with the FERC on
January 17, 1997.
During 1996, numerous technical conferences were held at the FERC's office in
Washington, D.C. to review the proposed Open Access tariff. On December 2,
1996, Eastern Shore filed a revised Pro-forma Open Access tariff. A technical
conference was conducted on December 12, 1996 to discuss Eastern Shore's
filing. As a result of the technical conference, Eastern Shore formally filed
a revised Open Access tariff including rate schedules on January 17, 1997. The
filing included a proposed effective date, the latter of May 1, 1997 or the
effective date of the Open Access blanket certificate. Since January 17, 1997,
several parties have filed comments. Eastern Shore filed reply comments and a
technical was convened on March 4, 1997. As a result of the March 4 technical
conference, Eastern Shore will be submitting a revised proposal to the parties
in an effort to gain consensus on the major issues. While at this time it is
impossible to predict the exact timing of the implementation of Open Access on
Eastern Shore's system, significant progress has been made, and management
expects that implementation will occur sometime during the second or third
quarter.
(i) (b) Natural Gas Distribution
Chesapeake distributes natural gas to approximately 34,700 residential,
commercial and industrial customers in southern Delaware, the Salisbury and
Cambridge, Maryland areas on Maryland's Eastern Shore, and Central Florida.
These activities are conducted through three utility divisions, consisting of
one division in Delaware, one division in Maryland and one division in
Florida. In 1993, the Company started natural gas supply management services
in the state of Florida under the name of Peninsula Energy Services Company
("PESCO").
Delaware and Maryland. The Delaware and Maryland divisions serve
approximately 26,160 customers, of which approximately 26,050 are residential
and commercial customers purchasing gas primarily for heating purposes.
Residential and commercial customers account for approximately 69% of the
volume delivered by the divisions, and 78% of the divisions' revenue, on an
annual basis. The divisions' industrial customers purchase gas, primarily on
an interruptible basis, for a variety of manufacturing, agricultural and other
uses. Most of Chesapeake's customer growth in these divisions comes from new
residential construction utilizing gas heating equipment.
Florida. The Florida division distributes natural gas to approximately 8,450
residential and commercial and 87 industrial customers in Polk, Osceola and
Hillsborough Counties. Currently 42 of the division's industrial customers,
which are engaged primarily in the citrus and phosphate industries and
electric cogeneration, and purchase and transport gas on a firm and
interruptible basis, account for approximately 90% of the volume delivered by
the Florida division, and 62% of the division's natural gas sales and
transportation revenues, on an annual basis. The Company's Florida division
also provides natural gas supply services to compete in the open access
environment. Currently, nineteen customers receive such management service
which generated operating income of $209,000 in 1996.
Natural Gas Supply
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions
receive all of their gas supply requirements from Eastern Shore. The divisions
purchase most of this gas under contracts with Eastern Shore which extend
through November 1, 2000. The contracts provide for the purchase of 15,629
firm Mcf daily (up to a maximum of 5,704,585 Mcf annually). The divisions have
additional firm supplies available under contract with Eastern Shore for peak
demand periods occurring during the winter heating season. These
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contracts, which are renewable on a year-to-year basis, provide for the
purchase of up to 450 Mcf daily (up to a maximum of 13,500 Mcf annually) of
peaking service. In addition, the divisions have contracted with Eastern Shore
for firm and interruptible storage capacity. On days when gas volumes
available to the divisions from Eastern Shore are greater than their
requirements, gas is injected into storage and is then available for
withdrawal to meet heavier winter loads. These storage contracts also permit
the utility divisions to purchase lower cost gas during the off-peak summer
season. Effective July 1, 1996, the storage capacity under contract with
Eastern Shore totaled 820,220 Mcf, with a firm peak daily withdrawal
entitlement of 14,606 Mcf. On those days when requirements exceed these
contract pipeline supplies, the divisions have propane-air injection
facilities for peak shaving.
Eastern Shore has no authority to transport natural gas purchased from a third
party for the Delaware and Maryland divisions currently; however, while
Chesapeake's divisions have no direct access to "spot market" gas, they
benefit from Eastern Shore's ability to obtain "spot market" gas and the
resulting reductions in Eastern Shore's rates. After Eastern Shore becomes an
open access pipeline the Delaware and Maryland divisions will assume the
responsibility of purchasing their natural gas requirements. The two divisions
could contract with a natural gas supply management company or handle the
process internally.
Florida. The Florida division receives transportation service from Florida
Gas Transmission Company ("FGT"), a major interstate pipeline. Chesapeake has
contracts with FGT for: (a) daily firm transportation capacity of 20,523
dekatherms in May through September , 27,105 dekatherms in October, and 26,919
dekatherms in November through April under FGT's firm transportation service
(FTS-1) rate schedule; (b) daily firm transportation capacity of 5,100
dekatherms in May through October, and 8,100 dekatherms in November through
April under FGT's firm transportation service (FTS-2) rate schedule; (c)
preferred interruptible transportation service up to 2,300,000 dekatherms
annually under FGT's preferred transportation service (PTS-1) rate schedule;
and (d) daily interruptible transportation capacity of 20,000 dekatherms under
FGT's interruptible transportation services (ITS-1) rate schedule. The firm
transportation contract (FTS-1) expires on August 1, 2000 with the Company
retaining a unilateral right to extend the term for an additional ten years.
After the expiration of the primary or secondary term, Chesapeake has the
right to first refuse to match the terms of any competing bids for the
capacity. The firm transportation contract (FTS-2) expires on March 1, 2015.
The preferred interruptible contract expires on the earlier of: (a) the
effective date of FGT's first rate case which includes costs for phase III
expansion or (b) August 1, 1995, and/or (c) August 1 of any subsequent year,
provided that FGT or Chesapeake gives to the other at least one hundred eighty
(180) days written notice prior to such August 1. The interruptible
transportation contract is effective until August 1, 2010 and month to month
thereafter unless canceled by either party with thirty days notice.
The Florida division currently receives its gas supply from various suppliers.
Some supply is bought on the spot market and some is bought under the terms of
two firm supply contacts with MG National Gas Corp. and Hadson Gas Systems,
Inc.
Having restructured its arrangements with FGT, Chesapeake believes it is well
positioned to meet the continuing needs of its customers with secure and cost
effective gas supplies.
Adequacy of Gas Supply. The Company believes that Eastern Shore's available
firm and interruptible supply is ample to meet the anticipated needs of the
Company's Delaware and Maryland natural gas distribution divisions.
Availability of gas supply to the Florida division is also expected to be
adequate under existing arrangements. Moreover, additional supply sources have
become available as a result of FGT becoming an open access pipeline.
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Competition within the Natural Gas Industry. Historically, Chesapeake's
Florida division has been supplied solely by FGT. In 1990, FGT became an open
access pipeline. The Florida division's large industrial customers now have
the option of remaining with the Florida division for gas supply or obtaining
alternative supplies from gas marketers or other suppliers. These conditions
have increased competition between Chesapeake's Florida division, gas
marketers and other natural gas providers for industrial customers in Central
Florida.
Eastern Shore has an open access filing and associated rate filing pending
before the FERC. When Eastern Shore becomes an open access pipeline, certain
customers in Chesapeake's Delaware and Maryland distribution divisions will be
able to purchase gas from third party gas suppliers in accordance with
regulations established through the respective state commissions.
Rates and Regulation
General. Chesapeake's natural gas distribution divisions are subject to
regulation by the Delaware, Maryland and Florida Public Service Commissions
with respect to various aspects of the Company's business, including the rates
for sales to all of their customers in each jurisdiction. All of Chesapeake's
firm distribution rates are subject to purchased gas adjustment clauses, which
match revenues with gas costs and normally allow eventual full recovery of gas
costs. Adjustments under these clauses require periodic filings and hearings
with the relevant regulatory authority, but do not require a general rate
proceeding. Rates on interruptible sales by the Florida division are also
subject to purchased gas adjustment clauses.
Management monitors the rate of return in each jurisdiction in order to ensure
the timely filing of rate adjustment applications.
Regulatory Proceedings
Maryland. On July 31, 1995, Chesapeake's Maryland division filed an
application with the Maryland Public Service Commission ("MPSC") requesting a
rate increase of $1,426,711 or 17.09%. The two largest components of the
increase were attributable to environmental costs and a new customer
information system, implemented in 1995. The request included a return on
equity of 13%.
On November 30, 1995, the MPSC issued an order approving a settlement proposal
of a $975,000 increase in annual base rates effective for gas provided on or
after December 1, 1995. As required in the settlement of the rate case, the
Company filed a cost of service study with the MPSC on June 28, 1996. The
purpose of a cost of service study is to allocate revenue among customer or
rate classifications. The filing also included proposals for: restructuring
sales services that more closely reflect the cost of serving commercial and
industrial customers, the unbundling of gas costs from distribution system
costs, revisions to sharing of interruptible margins between firm ratepayers
and the Company and new services that would allow customers using more than
30,000 Ccf of gas per year to purchase gas from suppliers other than the
Company.
After negotiations with MPSC staff and other interested parties, a settlement
was reached on most sales service issues and a proposed order was issued by
the Hearing Examiner on March 7, 1997. Commission action on the proposed order
is still pending. The settlement includes:
1. Class revenue requirements and restructured sales services which
provide for separate firm commercial and industrial rate schedules for
general service, medium volume, large volume and high load factor
customer groups;
2. Unbundling of gas costs from distribution charges;
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3. A new gas cost recovery mechanism, which utilizes a projected period
under which the fixed cost portion of the gas rate will be forecasted
on an annual basis and the commodity cost portion of the gas rate will
be estimated quarterly, based on projected market prices; and
4. Interruptible margins will continue to be shared, 90% to customers and
10% to the Company, but distribution costs incurred for incremental
load additions can be recovered with carrying charges utilizing 100% of
the incremental margin if the payback period is within three years.
At the request of MPSC staff, consideration of the new transportation services
has been postponed because Eastern Shore's open access filing is still pending
before the FERC. It is expected that these services will be addressed in the
spring of 1997.
Delaware. On April 4, 1995, Chesapeake's Delaware division filed an
application with the Delaware Public Service Commission ("DPSC") requesting a
rate increase of $2,751,000 or 14% over current rates. The largest component,
representing a third of the total requested increase, is attributable to
projected costs associated with the remediation proposed by the Environmental
Protection Agency ("EPA") of the site of a former coal gas manufacturing plant
operated in Dover, Delaware. The Company and the DPSC agreed to separate the
environmental recovery from the rate increase so each could be addressed
individually.
On December 20, 1995, the DPSC approved an order authorizing a $900,000
increase to base rates effective January 1,1996. The Company had interim rates
subject to refund in effect starting June 3, 1995 to collect $1.0 million on
an annualized basis. A refund of $42,000 was calculated and used to offset
environmental costs incurred.
Also 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.
On December 15, 1995, Chesapeake's Delaware division filed its rate design
proposal with the DPSC to initiate Phase II of this proceeding. The principal
objective of the filing was to prepare the Company for an increasingly
competitive environment anticipated in the near future when Eastern Shore
becomes an open access pipeline. This initial filing proposed new rate
schedules for commercial and industrial sales service, individual pricing for
interruptible negotiated contract rates, a modified purchased gas cost
recovery mechanism and a natural gas vehicle tariff.
On May 15, 1996, the Delaware division filed its proposal relating to
transportation and balancing services with the DPSC which proposed that
transportation of customer owned gas be available to all commercial and
industrial customers with annual consumption over 30,000 Ccf per year.
A tentative settlement proposal which was submitted to the DPSC Hearing
Examiner on November 22, 1996. On January 23, 1997 the DPSC Hearing Examiner
issued his proposed findings and recommendations supporting the parties
settlement proposal for final DPSC approval. On February 4, 1997 the DPSC
approved an order authorizing new service offerings and rate design for
services rendered on and after March 1, 1997.
9
The approved changes include:
1. Restructured sales services which provide commercial and industrial
customers with various service classifications such as general service,
medium volume, large volume and high load factor services;
2. A modified purchased gas cost recovery mechanism which takes into
consideration the unbundling of gas costs from distribution charges as
well as charging certain firm service classifications different gas cost
rates based on a customers' load factor;
3. The implementation of a mechanism for sharing interruptible, capacity
release and off-system sales margins between firm sales customers and
the Company, with changing margin sharing percentages based on the level
of total margin; and
4. Provision for transportation and balancing services for commercial and
industrial customers with annual consumption over 30,000 Ccf per year to
transport customer-owned gas on the Company's distribution system.
Florida. 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 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 capped 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. As a result, the Florida Division's return on equity for 1995
was lowered to a midpoint of 10.5% for determining the level of overearnings.
For 1995, the Florida Division was found to have exceeded its allowed rate of
return equity ceiling of 11.5% by $230,000. On January 21, 1997 the Florida
Public Service Commission voted to allow the division to apply the total
overearnings for 1994 and 1995 in the amount of $292,000 to its environmental
reserve. The Commission Order affirming this decision was issued in February,
1997.
(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").
On March 6, 1997, Chesapeake acquired all of the outstanding shares of Tri-
County Gas Company, Inc. ("Tri-County"), a family-owned and operated propane
distribution business located in Salisbury and Pocomoke, Maryland. The combined
operations of the Company and Tri-County served approximately 32,000 propane
customers on the Delmarva Peninsula and delivered approximately 30-million
retail and wholesale gallons of propane during 1996.
Sharpgas stores and distributes propane to approximately 23,100 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.
10
Propane is sold primarily in suburban and rural areas which are not served by
natural gas pipelines. Demand is typically much higher in the winter months and
is significantly affected by seasonal variations, particularly the relative
severity of winter temperatures, because of its use in residential and
commercial heating.
The Company purchases propane primarily from suppliers, including major domestic
oil companies and independent producers of gas liquids and oil. Supplies of
propane from these and other sources are readily available for purchase by the
Company. Supply contracts generally include minimum (not subject to a take-or-
pay premiums) and maximum purchase provisions.
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.
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 both fuel oil and electricity as an energy source.
Propane competes against fuel oil based upon cleanliness and its environmental
advantages. Propane is also typically less expensive than both fuel oil and
electricity based on equivalent BTU value. Because natural gas has historically
been less expensive than propane, propane is generally not distributed in
geographic areas serviced by natural gas pipeline or distribution systems.
The Company'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) Advanced Information Services
Chesapeake's advanced information services segment is comprised of United
Systems, Inc. ("USI") and Capital Data Systems, Inc. ("CDS"), both wholly owned
subsidiaries of the Company. CDS provided programming support for application
software, until the first quarter of 1997, at which time they disposed of
substantially all of their assets.
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.
11
The advanced information services businesses face significant competition from a
number of larger competitors having substantially greater resources available to
them than the Company. In addition, changes in the advanced information services
businesses are occurring rapidly, which could adversely impact the markets for
the Company's products and services.
(i) (e) Other Subsidiaries
Skipjack, Inc. ("Skipjack") and Chesapeake Investment Company ("Chesapeake
Investment"), are wholly owned subsidiaries of Chesapeake Service Company.
Skipjack owns and leases to affiliates, two office buildings in Dover, Delaware.
Chesapeake Investment is a Delaware affiliated investment company.
On March 6, 1997, in connection with the acquisition of Tri-County, the Company
acquired Eastern Shore Real Estate, Inc. ("ESR"), which will become a wholly
owned subsidiary of Chesapeake Service Company. ESR owns and leases office
buildings to affiliates and external companies.
(ii) Seasonal Nature of Business
Revenues from the Company's residential and commercial natural gas sales and
from its propane distribution activities are affected by seasonal variations,
since the majority of these sales are to customers using the fuels for heating
purposes. Revenues from these customers are accordingly affected by the
mildness or severity of the heating season.
(iii) Capital Budget
The Company's current capital budget for 1997 contemplates expenditures totaling
approximately $18.9 million. The total includes approximately $8.5 million for
Chesapeake's natural gas distribution divisions, consisting mainly of extensions
to and replacements of the distribution facilities and related equipment; $4.5
million for natural gas transmission operations, providing principally for
improvements to the pipeline system and for finishing construction of a
compressor station in Delaware City, $3.8 million for environmental related
expenditures, $1.8 million for propane distribution, principally for the
purchase of storage facilities, additional tanks and the construction of a new
operation center in Pocomoke, Maryland; $150,000 for computer hardware,
furniture and fixtures for the Company's advanced information services group;
along with $150,000 for general plant. These capital requirements are expected
to be financed by cash flow provided by the Company's operating activities
short-term borrowing, and the issuance of long-term debt, common equity or a
combination thereof.
(iv) Employees
The Company has 338 employees including 131 natural gas distribution employees,
18 natural gas transmission employees, 97 propane distribution employees and 49
advanced information services employees. The remaining 43 employees are
considered general and administrative and include officers of the Company and
treasury, accounting, data processing, planning, human resources and other
administrative personnel. The acquisition of Tri-County will add approximately
43 employees to the total number of employees of the Company.
12
Item 2. Properties
(a) General
The Company owns offices and operates 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; 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 three
compressor stations located in Delaware City, Delaware, Daleville, Pennsylvania
and Bridgeville, Delaware. The Delaware City compressor station is currently
under construction with a proposed in-service date of March 19,1997. The
Delaware City compressor facility and associated piping are needed to stabilize
capacity on Eastern Shore's system as a result of steadily declining inlet
pressures at the Hockessin interconnect with Transcontinental Gas Pipe Line
Corporation. 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 Eastern Shore's firm customers' demands, including
demands from Chesapeake's Delaware and Maryland divisions. The Bridgeville
station is being used to provide increased pressures required to meet the
demands on the system.
(d) Propane Distribution
Sharpgas owns bulk propane storage facilities with an aggregate capacity of
1,482,000 gallons at 26 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.
13
Environmental
(a) Dover Gas Light Site
In 1984, the State of Delaware notified the Company that a parcel of land it
purchased in 1949 from Dover Gas Light Company, a predecessor gas company,
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 that 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 (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 of its Order, as well as significant financial penalties
for failure to comply. Although notifying EPA of objections to the Order, the
Company agreed to comply. GPU informed EPA that it does not intend to comply
with the Order.
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
14
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.
On June 25, 1996, the Company initiated litigation against GPU for contribution
to the remedial costs incurred by Chesapeake in connection with complying with
the ROD. At this time, management cannot predict the outcome of the litigation
or the amount, if any, of proceeds to be received.
In July 1996, the Company commenced the design phase of the ROD, on-site pre-
design and investigation. A pre-design investigation report ("the report") was
filed in October 1996 with the EPA. The report, which requires EPA approval,
will provide up to date status on the site, which the EPA will use to determine
if the remedial design selected in the ROD is still the appropriate remedy.
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, 1996, the Company has incurred approximately $4.2 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 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 expenditures through September of the filing years plus
amortization of expenses from previous years. The advantage of the rider is
that it is not necessary to file a rate case every year to recover expenses
incurred. As of December 31, 1996, the unamortized balance and amount of
environment cost not included in the rider, effective January 1, 1997 was
$1,206,000 and $191,000, 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.
15
(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 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.
During 1996, the Company completed construction and began remediation procedures
at the Salisbury site and will be reporting on an ongoing basis the remediation
and monitoring results to the Maryland Department of the Environment.
The cost of remediation is estimated to range from $140,000 to $190,000 per year
for operating expenses. Based on these estimated costs, the Company recorded
both a liability and a deferred regulatory asset of $650,088 on December 31,
1996, 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
December 31, 1996, the Company has incurred approximately $2.2 million for
remedial actions and environmental studies and has charged such costs to
accumulated depreciation. In January 1990, the Company entered into settlement
agreements with a number of insurance companies resulting in proceeds to fund
actual environmental costs incurred over a three to five-year period beginning
in 1990. The final insurance proceeds were requested and received in 1992. In
December 1995, the Maryland Public Service Commission approved recovery of all
environmental cost incurred through September 30, 1995 less amounts previously
amortized and insurance proceeds. The amount approved for a 10-year
amortization was $964,251. Of the $2.2 million in costs reported above,
approximately $417,000 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. On May 10, 1996, CFGC transmitted to FDEP an Air Sparging
and Soil Vapor Extraction Pilot Study Work Plan for FDEP's review and approval.
The Work Plan described CFCG's proposal to undertake an Air Sparging and Soil
Vapor Extraction pilot study to evaluate the effectiveness of air sparging as a
groundwater remedy combined with soil vapor extraction at the Property. CFGC is
currently awaiting FDEP's comments to the Work Plan. It is not possible to
determine whether remedial action will be required by FDEP and, if so, the cost
of such remediation.
16
The Company has spent approximately $660,000, as of December 31, 1996, on these
investigations, and expects to recover these expenses, as well as any future
expenses, through base rates. These costs have been accounted for as charges to
accumulated depreciation. The Company requested and received 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. The FPSC issued an order in January 1997,
applying a refund of $292,000, pertaining to 1994 and 1995 overearnings, toward
the balance of unamortized environmental charges. Of the $660,000 in costs
reported above, all costs have received ratemaking treatment. The FPSC has
allowed the Company to continue to accrue for future environmental costs. At
December 31, 1996, the Company has $396,000 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. In June 1996, the Company received the
certificate of completion from DNREC. It is management's opinion that these
costs will be recoverable in rates.
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 10. Executive Officers of the Registrant
Information pertaining to the Executive Officers of the Company is as follows:
Ralph J. Adkins (age 54) (present term expires May 20, 1997).
---------------
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 and
Chief Executive Officer of Chesapeake Service Company, and Chairman and
Chief Executive Officer of Sharp Energy, Inc., Tri-County Gas Company, Inc.,
Chesapeake Service Company and Eastern Shore Natural Gas Company, all wholly
owned subsidiaries of Chesapeake. He has been a director of Chesapeake since
1989.
17
John R. Schimkaitis (age 49) (present term expires May 20, 1997).
- -------------------
Mr. Schimkaitis is Executive Vice President, Chief Operating Officer and
Assistant Treasurer. 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.
Philip S. Barefoot (age 50) (present term expires May 20, 1997).
- ------------------
Mr. Barefoot joined Chesapeake as Division Manager of Florida Operations in July
1988. In May 1994 he was elected Senior Vice President of Natural Gas
Operations, as well as Vice President of Chesapeake Utilities Corporation. Prior
to joining Chesapeake, he was employed with Peoples Natural Gas Company where he
held the positions of Division Sales Manager, Division Manager and Vice
President of Florence Operations.
Michael P. McMasters (age 38) (present term expires May 20, 1997).
- --------------------
Mr. McMasters is Vice President, Chief Financial Officer and Treasurer of
Chesapeake Utilities Corporation. He has served as Vice President, Chief
Financial Officer and Treasurer since December, 1996. He previously served as
Vice President of Eastern Shore, Director of Accounting and Rates and
Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of
Operations Planning for Equitable Gas Company.
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, 1996 and 1995:
- ---------------------------------------------------------
Dividends
Declared
Quarter Ended High Low Close Per Share
- ---------------------------------------------------------
1996
- ---------------------------------------------------------
March 31 $17.000 $14.500 $16.750 $0.2325
June 30 17.875 15.875 16.000 0.2325
September 30 17.750 15.125 17.500 0.2325
December 31 18.000 16.375 16.875 0.2325
- ---------------------------------------------------------
1995
- ---------------------------------------------------------
March 31 $13.625 $12.125 $13.250 $0.2250
June 30 13.375 12.250 13.125 0.2250
September 30 14.375 12.250 14.000 0.2250
December 31 15.500 14.000 14.625 0.2250
- ---------------------------------------------------------
The common stock of the Company trades on the New York Stock Exchange under the
symbol "CPK".
(b) Approximate number of holders of common stock as of December 31, 1996:
Number of Shareholders
Title of Class of Record
-------------- --------
Common stock, par value $.4867 2,213
18
(c) Dividends:
During the years ended December 31, 1996 and 1995, 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, 1996, the amounts available for future dividends permitted by the
Series I covenant are $13.0 million.
(d) On March 6, 1997, in conjunction with the acquisition of Tri-County Gas
Company, Inc., the Company issued 639,000 shares of Company stock to William P.
Schneider and James R. Schneider in reliance on the private placement exemption
provided by Section 4(2) of the Securities Act of 1933 and Regulation D,
thereunder.
19
Item 6. Selected Financial Data
Finacial Highlights page from Annual Report, followed by Annual Report MD&A
FINANCIAL HIGHLIGHTS
- ----------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands Except Stock Data)
For the Years Ended December 31, 1996 1995 1994 1993 1992
- ----------------------------------------------------------------------------------------------------------------------------
Operating
Operating revenues $119,330 $104,020 $98,572 $85,873 $75,935
Operating income $9,244 $9,562 $7,227 $6,311 $5,770
Income before cumulative effect of
change in accounting principle
and discontinued operations $6,910 $7,237 $4,460 $3,914 $3,475
Cumulative effect of change in
accounting principle $58
Income from discontinued operations $74
Net income $6,910 $7,237 $4,460 $3,972 $3,549
- ----------------------------------------------------------------------------------------------------------------------------
Balance Sheet
Gross plant $127,961 $115,283 $110,023 $100,330 $91,039
Net plant $90,564 $81,716 $75,313 $69,794 $64,596
Total assets $131,138 $118,794 $108,271 $100,988 $89,557
Long-term debt, net $28,984 $29,795 $24,329 $25,682 $25,668
Common stockholders' equity $47,153 $42,301 $37,063 $34,878 $33,126
Capital expenditures $14,302 $12,100 $10,653 $10,064 $6,720
- ----------------------------------------------------------------------------------------------------------------------------
Common Stock
Primary earnings per share:
Income before cumulative effect of
change in accounting principle
and discontinued operations $1.82 $1.95 $1.23 $1.10 $1.00
Cumulative effect of change in
accounting principle $0.02
Income from discontinued operations $0.02
Net income $1.82 $1.95 $1.23 $1.12 $1.02
Average shares outstanding 3,793,467 3,701,981 3,632,413 3,556,037 3,477,244
Fully diluted earnings per share:
Income before cumulative effect of
change in accounting principle
and discontinued operations $1.76 $1.89 $1.20 $1.08 $0.99
Cumulative effect of change in
accounting principle $0.02
Income from discontinued operations $0.02
Net income $1.76 $1.89 $1.20 $1.10 $1.01
Average shares outstanding 4,037,048 3,950,724 3,888,190 3,816,295 3,749,130
Cash dividends per share $0.93 $0.90 $0.88 $0.86 $0.86
Book value per share $12.41 $11.37 $10.15 $9.76 $9.50
Common equity/Total capitalization 61.93% 58.67% 60.37% 57.59% 56.34%
Return on equity 14.66% 17.11% 12.03% 11.39% 10.71%
- -------------------------------------------------------------------------------------------------------------------------------
Number of Employees 338 335 320 326 317
Number of Registered Stockholders 2,213 2,098 1,721 1,743 1,674
Heating Degree Days 4,717 4,593 4,398 4,705 4,645
Heating Degree Days (10-year average) 4,596 4,586 4,564 4,588 4,598
- -------------------------------------------------------------------------------------------------------------------------------
20
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 1996, the Company's net
cash provided by operating activities, net cash used by investing activities and
net cash provided by financing activities were $11.3 million, $14.1 million and
$3.7 million, respectively.
On January 23, 1997, the Board of Directors increased the amount the Company was
authorized to borrow from various banks and trust companies from $14.0 million
to a ceiling of $20.0 million. As of December 31, 1996, 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,
1996 and 1995 were $12.0 million and $4.8 million, respectively. Based upon
anticipated cash requirements in 1997, the Company may refinance the short-term
debt and provide 1997 capital requirements through the issuance of long-term
debt. The timing of such an issuance is dependent upon the nature of the
securities involved as well as current market and economic conditions.
In 1996, the Company used cash provided by operating activities coupled with
short-term borrowings to fund the capital expenditures and increases in working
capital requirements. The increase in working capital was primarily due to the
significant increase in natural gas and propane prices during the fourth quarter
of 1996. In 1995, the Company's capital additions were funded by operating
activities. In 1994, cash provided by operations increased due to the
collection of a large amount of underrecovered purchased gas costs present at
the end of 1993.
During 1996, 1995 and 1994, capital expenditures were approximately $14,302,000,
$12,100,000 and $10,653,000, respectively. For 1997, the Company has budgeted
$18.9 million for capital expenditures. This amount includes $8.5 million for
natural gas distribution, $4.5 million for natural gas transmission, $3.8
million for environmental related expenditures, $1.8 million for propane
distribution, $150,000 for advanced information services and $150,000 for
general plant. The natural gas and propane distribution expenditures are for
expansion and improvement of facilities in existing service territories.
Natural gas transmission expenditures are for improvement of the pipeline system
and completion of the Delaware City compressor station. The advanced
information services expenditures are for computer hardware, software and
related equipment. Financing for the 1997 construction program is expected to
be provided from short-term borrowings, cash from operations and from an
issuance of long-term debt. 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 during 1997 and
in future years (see Note J to the Consolidated Financial Statements), a portion
of which may need to be financed through external sources. Management does not
expect such financing to have a material adverse effect on the financial
position or capital resources of the Company.
Capital Structure
As of December 31, 1996, common equity represented 61.9% of permanent
capitalization, compared to 58.7% in 1995 and 60.4% in 1994. 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
21
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 Natural Gas Company, the
Company's natural gas transmission subsidiary ("Eastern Shore"), originally due
October 1, 2003. The remaining proceeds of $5,909,000 were used to repay short-
term borrowings under the Company's lines of credit. The Company issued no
long-term debt in 1996 and 1994. During 1996, the Company repaid a total of
approximately $869,000 of long-term debt, compared to $5,018,000 and $1,291,000
in 1995 and 1994, respectively.
The Company issued 33,926, 38,660 and 30,928 shares of common stock in
connection with its Automatic Dividend Reinvestment and Stock Purchase Plan
during the years of 1996, 1995 and 1994, respectively.
Results of Operations
Net income for 1996 was $6,910,428, as compared to $7,236,695 for 1995.
Exclusive of matters relating to the settlement and associated accruals
described below, earnings in 1996 increased by $320,969. The 1995 net income
reflected the settlement between Eastern Shore and the Federal Energy Regulatory
Commission ("FERC") regarding Eastern Shore's purchased gas adjustment ("PGA")
computation. This settlement, which was a non-recurring event, contributed
$833,000 to 1995 net income due to the reversal of the excess liability for a
potential refund previously recorded, and resulted in a reduction in the
required level of accruals from $750,000 after tax in 1994 to $186,000 after tax
in 1995. Earnings before interest and taxes ("EBIT") for the years 1996, 1995
and 1994 were $13.2 million, $13.6 million and $9.8 million.
Natural Gas Distribution
The natural gas distribution segment contributed EBIT of $7.2 million in 1996
compared to $4.7 million in both 1995 and 1994. The increase in EBIT in 1996
was due to higher gross margin partially offset by higher operating expenses.
Gross margin in 1996 increased $4.0 million due to a full year of rate
increases, which went into effect in 1995, coupled with a 20% increase in
deliveries to residential and commercial customers located in the Company's
northern service territory. The rate increase became effective during December,
1995 for Maryland operations and interim rates were in effect during June, 1995
for Delaware operations. The rate increases were designed to increase revenues
$975,000 and $900,000 annually for the Maryland and Delaware operations,
respectively. The increase in deliveries to residential and commercial
customers located in the Company's northern service territory was related to
temperatures which were colder than the previous year.
Gross margin in 1995 increased $1.7 million due to the partial year of rate
increases for the Maryland and Delaware operations in 1995 and an increase of
88% and 23% in transportation and delivery volumes, respectively, by the Florida
distribution operations. These increases in Florida's volumes reflected sales
to phosphate producing and citrus processing customers and to three co-
generation plants.
Operations expenses for 1996 increased by $583,000 or 7% after increasing by
$1.2 million or 16% in 1995 over 1994. The 1996 increases related to
compensation, benefits, data processing costs, uncollectibles and regulatory
expenses. The increases in 1995 related to compensation, data processing
conversion costs, consulting, legal and regulatory expenses.
22
Maintenance expenses were slightly less in 1996 compared to 1995, when expenses
were $66,000 or 7% higher than 1994 expenses due to a greater level of
maintenance on meter and regulating stations. Depreciation and amortization
expense increased due to plant additions placed in service during the past two
years. Other taxes increased by $460,000 or 23% in 1996, partially due to the
inclusion of certain state revenue related taxes in 1996.
Natural Gas Transmission
The natural gas transmission segment contributed EBIT of $2.5 million, $6.1
million and $3.0 million during 1996, 1995 and 1994, respectively. The large
increase in 1995 EBIT includes 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 was a non-recurring
event, contributed $1.3 million to EBIT for 1995 due to the reversal of excess
liability for the 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 decreased $2.6 million in 1996, increased $890,000 in
1995 and increased $1.1 million in 1994.
The reduction in 1996 EBIT of $2.6 million was primarily the result of a
decrease in gross margin on sales to industrial customers. Contributing to the
increases in 1995 and 1994 EBIT were increased gross margins, primarily
attributable to increased deliveries of industrial sales volumes, offset
slightly by higher operating expenses.
The decline in 1996 gross margin resulted from a 67% decrease in volumes
delivered, primarily reflecting decreased deliveries to two industrial
interruptible customers, a municipal power plant and a methanol plant. The
methanol plant shut down operations on April 1, 1996. The management of the
methanol plant has indicated that they would monitor methanol prices and would
re-evaluate their position as to reopening or permanently closing on or about
April 1, 1997. To our knowledge, no decision has been made regarding reopening
or permanently closing the methanol plant. During 1996, 1995 and 1994,
deliveries to methanol and power plants contributed to gross margin
approximately $284,000, $2.4 million and $1.4 million, respectively. These two
customers are 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).
Operations expense increased 4% in 1996, primarily reflecting increased
compensation and benefit related expenses. Operations expense increased by
$314,000 or 14% in 1995 compared to 1994. The majority of the increases were in
payroll, telemetering and legal fees.
Maintenance expense declined slightly in 1996 after declining by $47,000 or 8%
in 1995. Maintenance expenses in 1994 increased by $125,000 due to the painting
of a pipeline bridge structure and a higher level of natural gas main
maintenance. Depreciation expense increased in 1996 due to plant placed in
service during the past two years.
On October 15, 1996, Eastern Shore filed with the FERC for a rate increase of
approximately $1,445,000. This increase would be effective for only revenues
earned on sales to regulated customers.
In connection with the FERC Order relating to the settlement, Eastern Shore
applied in December of 1995 to the FERC for a blanket certificate authorizing
open access transportation service on its pipeline system. The implementation
of open access transportation service, expected to occur during 1997, will
provide all of Eastern Shore'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 that Eastern
Shore's earnings, which in the past have been driven to a substantial extent by
widely varying levels of unregulated sales, will tend to be more stable and
closer to a regulated return.
23
Propane Distribution
The propane distribution segment contributed EBIT of $2.1 million, $1.9 million
and $2.3 million for 1996, 1995 and 1994, respectively. The 1996 increase in
EBIT was primarily the result of an increase in gross margin mostly offset by
greater operating expenses. The 1995 decrease in EBIT was a combined impact of
a decrease in gross margin coupled with greater operating expenses.
The increase in gross margin of $1.1 million or 12% for 1996 was primarily the
result of a 12% increase in sales volumes due to temperatures being colder than
the previous year. The decrease in gross margin of $281,000 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 1995, the segment did not secure a
contract with one wholesale customer under which it had supplied large
quantities of propane, contributing $64,000 to gross margin, in 1994.
Operations expense for 1996 increased by $766,000 or 14% after increasing by
$225,000 or 4% in 1995. The increase in expenses for 1996 and 1995 occurred
primarily in compensation, benefits and outside services. Maintenance expenses
increased by $84,000 or 28% in 1996 after reducing by $42,000 or 12% in 1995.
The maintenance expense increases occurred primarily on vehicles.
Starting in 1997, the Company will be integrating the operations of Tri-County
Gas Company, Inc. ("Tri-County"), acquired on March 6, 1997, and the Company's
current propane distribution operations.
Advanced Information Services
The advanced information services segment contributed EBIT of $1.3 million, $1.2
million and $174,000 for the years 1996, 1995 and 1994. During 1996, revenue
and operating expenses decreased by $1.4 million and $1.5 million, respectively.
These declines resulted from the segment no longer providing facilities
management services during 1996. These 1996 declines were partially offset by
increases in consulting and programming revenues along with associated operating
expenses, such as compensation, benefits and reimbursed costs.
In 1995 revenues increased due to higher consulting and programming revenues,
placement services and non-recurring revenue earned by providing services to a
large facilities management customer. These services were provided during a
period of system conversion by this customer in connection with the termination
of its contract. Operating expenses declined in 1995 due to downsizing efforts
at the Company's North Carolina operation to change the focus from a product
development and facilities management company to a fixed price contract
programming services company.
Included in the results of the advanced information services segment for the
years ended December 31, 1996, 1995 and 1994 were intersegment revenues of
$711,000, $1,722,000 and $2,277,000, respectively, which were eliminated in
consolidation. The intercompany LBIT (Loss Before Interest and Taxes) connected
with the development of the Company's natural gas distribution billing system,
which was finalized during 1995, totaled $165,000 and $468,000 for the years
1995 and 1994, respectively.
Other
Non-operating income was $379,000, $357,000 and $16,000 for 1996, 1995 and 1994,
respectively. The 1995 increase was primarily due to a one-time termination fee
paid to the advanced information services segment by its largest facilities
management customer in connection with a change in control of that customer.
This was somewhat
24
offset by costs to downsize the operation to no longer provide facilities
management service in connection with its Page-IT/(TM)/ software.
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 electricity, 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, with
implementation during 1997, the Company has not previously been subject to the
competitive pressures from other sellers of natural gas. Upon implementation of
open access transportation services on Eastern Shore's system, third party
suppliers will compete with the Company to sell gas to the local distribution
companies and the end users on Eastern Shore's system. Eastern Shore will shift
from providing sales service to providing contract storage and transportation
services.
The Company's distribution operations located in Delaware and Maryland will then
face the possibility of the unbundling of their services to certain industrial
customers, thus increasing the competition for sales services. 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 these customers' business.
Both the propane distribution and the advanced information services businesses
face significant competition from a number of larger competitors with
substantially greater resources available to them than the Company. In
addition, in the advanced information services business, changes are occurring
rapidly which could adversely impact the markets for the Company's services.
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, except for its
effect on purchased gas costs. Although historically stable, these costs were
higher in 1996. These costs are passed on to customers through the purchased
gas adjustment clause in the Company'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 operations and
constantly monitors the returns of its unregulated business operations.
Cautionary Statement
Statements made herein and elsewhere in this Form 10-K which are not historical
fact are forward 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
25
transportation rates that will be in effect under open access has not yet been
determined. Third, the outcome of Eastern Shore's rate increase filing with
FERC for an increase in revenue earned on sales to regulated customers has not
yet been determined. Fourth, there are a number of uncertainties, including the
outcome of open access proceedings and the effects of competition, which will
affect 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. With respect
to the acquisition of Tri-County, these include: actual performance for the
future periods, the actual costs of the acquisition and the ability of the
combined company to execute the integration and realize the expected synergies.
With respect to the Company's business in general, these include: the
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.
26
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, 1996 and
1995, and the related consolidated statements of income, cash flows,
stockholders' equity, and income taxes for each of the three years in the period
ended December 31, 1996, and the consolidated financial statement schedule
listed in Item 14(a)(1) and (2) of this Form 10-K. These financial statements
and the financial statement schedule are the responsibility of the Company's
Management. Our responsibility is to express an opinion on these financial
statements and the 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, 1996 and
1995, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 1996 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, 1994, 1993 and 1992, 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, 1993 (none of which are presented
herein) and we expressed unqualified opinions on those consolidated financial
statements. In our opinion, the information set forth in the Financial
Highlights included in the Selected Financial Data for each of the five years in
the period ended December 31, 1996, appearing on page 20 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 13, 1997
27
CONSOLIDATED BALANCE SHEETS
Assets
- -----------------------------------------------------------------------------------------------------------------------------
At December 31, 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Natural gas distribution $70,497,872 $64,785,616
Natural gas transmission 30,655,492 25,651,558
Propane distribution 21,101,579 19,645,973
Advanced information services 1,003,850 841,661
Gas plant acquisition adjustment 795,004 795,004
Other plant 3,907,657 3,563,247
-----------------------------------------
Total property, plant and equipment 127,961,454 115,283,059
Less: Accumulated depreciation and amortization (37,397,752) (33,567,446)
-----------------------------------------
Net property, plant and equipment 90,563,702 81,715,613
-----------------------------------------
Investments 2,263,068 1,957,218
-----------------------------------------
Current Assets
Cash and cash equivalents 1,952,998 977,407
Accounts receivable (less allowance for uncollectibles 13,328,333 12,701,256
of $392,412 and $309,955 in 1996 and 1995, respectively)
Materials and supplies, at average cost 1,160,522 844,786
Propane inventory, at average cost 2,129,914 1,442,633
Storage gas prepayments 3,731,680 2,663,721
Underrecovered purchased gas costs 2,192,170
Income taxes receivable 112,902 193,916
Prepaid expenses 801,939 842,460
Deferred income taxes 158,010 1,362,289
-----------------------------------------
Total current assets 25,568,468 21,028,468
-----------------------------------------
Deferred Charges and Other Assets
Environmental regulatory assets 6,650,088 7,113,572
Environmental expenditures, net 1,778,348 1,505,140
Order 636 transition cost 943,209 1,463,157
Other deferred charges and intangible assets 3,371,027 4,010,812
-----------------------------------------
Total deferred charges and other assets 12,742,672 14,092,681
-----------------------------------------
Total Assets $131,137,910 $118,793,980
=========================================
See accompanying notes
Capitalization and Liabilities
- -------------------------------------------------------------------------------------------------------------------------
At December 31, 1996 1995
- -------------------------------------------------------------------------------------------------------------------------
Capitalization
Stockholders' equity
Common stock $1,849,626 $1,811,211
Additional paid-in capital 18,848,851 17,592,242
Retained earnings 26,780,831 23,385,097
Less: Unearned compensation related to restricted stock awarded (364,529) (415,107)
Unrealized gain (loss) on marketable securities, net 38,598 (72,839)
---------------------------------------------
Total stockholders' equity 47,153,377 42,300,604
Long-term debt, net of current portion 28,984,368 29,794,639
---------------------------------------------
Total capitalization 76,137,745 72,095,243
---------------------------------------------
Current Liabilities
Current portion of long-term debt 791,271 864,849
Short-term borrowings 12,000,000 4,800,000
Accounts payable 13,176,126 11,162,775
Refunds payable to customers 353,734 966,940
Accrued interest 741,768 742,701
Dividends payable 883,621 837,358
Overrecovered purchased gas costs 53,374
Other accrued expenses 3,447,397 3,123,191
---------------------------------------------
Total current liabilities 31,393,917 22,551,188
---------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 9,798,676 9,136,808
Deferred investment tax credits 876,432 931,247
Environmental liability 6,650,088 7,113,572
Order 636 transition liability 943,209 1,463,157
Accrued pension costs 1,866,660 2,118,545
Other liabilities 3,471,183 3,384,220
---------------------------------------------
Total deferred credits and other liabilities 23,606,248 24,147,549
---------------------------------------------
Commitments and Contingencies
(Notes J and K)
Total Capitalization and Liabilities $131,137,910 $118,793,980
=============================================
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME
- ----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
Operating Revenues $119,330,068 $104,020,416 $98,572,297
----------------------------------------------------------
Operating Expenses
Purchased gas costs 72,530,507 58,454,410 59,013,165
Operations 22,954,470 21,387,989 19,681,435
Maintenance 2,014,106 2,079,121 2,181,404
Depreciation and amortization 5,101,823 5,461,752 5,140,679
Other taxes 3,538,402 3,050,351 2,798,905
Income taxes 3,946,986 4,025,274 2,529,635
----------------------------------------------------------
Total operating expenses 110,086,294 94,458,897 91,345,223
----------------------------------------------------------
Operating Income 9,243,774 9,561,519 7,227,074
Other Income
Interest income 174,359 141,161 123,271
Other income and (deductions), net 173,231 256,237 (144,038)
Income taxes (83,739) (105,280) (12,733)
Allowance for equity funds used during construction 115,434 65,198 49,154
----------------------------------------------------------
Total other income 379,285 357,316 15,654
----------------------------------------------------------
Income Before Interest Charges 9,623,059 9,918,835 7,242,728
----------------------------------------------------------
Interest Charges
Interest on long-term debt 2,392,458 2,282,247 2,322,942
Amortization of debt expense 120,345 109,399 103,859
Other 264,148 383,976 426,242
Allowance for borrowed funds used during construction (64,320) (93,482) (70,237)
----------------------------------------------------------
Total interest charges 2,712,631 2,682,140 2,782,806
----------------------------------------------------------
Net Income $6,910,428 $7,236,695 $4,459,922
==========================================================
Earnings Per Share of Common Stock (1):
Primary:
Earnings per share $1.82 $1.95 $1.23
Average shares outstanding 3,793,467 3,701,891 3,632,413
Fully diluted:
Earnings per share $1.76 $1.89 $1.20
Average shares outstanding 4,037,048 3,950,724 3,888,190
See accompanying notes
30
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -----------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income $6,910,428 $7,236,695 $4,459,922
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization 5,782,759 5,905,090 5,786,013
Allowance for equity funds used during construction (115,434) (65,198) (49,154)
Investment tax credit adjustments (54,815) (54,815) (54,815)
Deferred income taxes, net 1,794,147 252,727 (669,404)
Employee benefits 471,869 178,803 492,082
Employee compensation from lapsing of stock restrictions 334,745 431,694 374,121
Allowance for refund (1,356,705) 1,238,705
Other, net 438,510 (339,080) 424,832
Changes in assets and liabilities:
Accounts receivable, net (627,077) (4,284,963) 1,303,517
Other current assets (1,949,441) 1,380,216 (979,125)
Other deferred charges (502,491) (946,450) (271,937)
Accounts payable, net 1,300,252 3,149,573 382,913
Refunds payable to customers (613,206) 399,123 59,999
(Underrecovered) Overrecovered purchased gas costs (2,245,544) 162,399 1,723,432
Other current liabilities 369,536 948,846 159,910
----------------------------------------------------------
Net cash provided by operating activities 11,294,238 12,997,955 14,381,011
----------------------------------------------------------
Investing Activities
Property, plant and equipment expenditures, net (14,045,947) (11,691,192) (10,473,565)
Allowance for equity funds used during construction 115,434 65,198 49,154
Purchases of investments (129,406) (38,836)
----------------------------------------------------------
Net cash used by investing activities (14,059,919) (11,664,830) (10,424,411)
----------------------------------------------------------
Financing Activities
Common stock dividends, net of amounts reinvested of
$555,121, $506,941 and $427,190 in 1996,
1995 and 1994, respectively (2,959,573) (2,791,373) (2,736,388)
Sale of stock 369,709 254,484 201,704
Net borrowings (repayments) under line of credit agreements 7,200,000 (3,200,000) (900,000)
Proceeds from issuance of long-term debt 10,000,000
Repayments of long-term debt (868,864) (5,017,580) (1,285,962)
----------------------------------------------------------
Net cash used by financing activities 3,741,272 (754,469) (4,720,646)
----------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 975,591 578,656 (764,046)
Cash and Cash Equivalents at Beginning of Year 977,407 398,751 1,162,797
----------------------------------------------------------
Cash and Cash Equivalents at End of Year $1,952,998 $977,407 $398,751
==========================================================
Supplemental Disclosure of Cash Flow Information
Cash paid for interest $2,660,595 $2,657,972 $2,652,323
Cash paid for income tax $2,122,120 $3,288,895 $3,509,034
See accompanying notes
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- -------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------
Common Stock
Balance -- beginning of year $1,811,211 $1,785,514 $1,754,547
Dividend Reinvestment Plant 16,514 18,816 15,046
USI restricted stock award agreements 10,639 6,881 15,778
Conversion of debentures 429 143
Company's Retirement Savings Plan 9,927
Exercised stock options 906
----------------------------------------------------
Balance -- end of year 1,849,626 1,811,211 1,785,514
----------------------------------------------------
Additional Paid-in Capital
Balance -- beginning of year 17,592,242 16,834,823 15,850,319
Dividend Reinvestment Plant 538,607 488,125 412,144
USI restricted stock award agreements 344,570 176,029 458,335
Sale of treasury stock to Company's
Retirement Savings Plan 93,265 109,184
Conversion of debentures 14,557 4,841
Company's Retirement Savings Plan 328,464
Exercised stock options 30,411
----------------------------------------------------
Balance -- end of year 18,848,851 17,592,242 16,834,823
----------------------------------------------------
Retained Earnings
Balance -- beginning of year 23,385,097 19,480,374 18,219,083
Net income 6,910,428 7,236,695 4,459,922
Cash dividends (1) (3,514,694) (3,331,972) (3,198,631)
----------------------------------------------------
Balance -- end of year 26,780,831 23,385,097 19,480,374
----------------------------------------------------
Treasury Stock
Balance -- beginning of year (99,842) (192,362)
Sale of treasury stock to Company's
Retirement Savings Plan 99,842 92,520
-------------------------------
Balance -- end of year (99,842)
-------------------------------
Unearned Compensation
Balance -- beginning of year (415,107) (696,679) (663,557)
Issuance of award (284,167) (121,343) (474,113)
Amortization of prior years' awards 334,745 402,915 440,991
----------------------------------------------------
Balance -- end of year (364,529) (415,107) (696,679)
----------------------------------------------------
Unrealized Gain (Loss) on Marketable Securities (2) 38,598 (72,839) (241,609)
----------------------------------------------------
Total Stockholders' Equity $47,153,377 $42,300,604 $37,062,581
====================================================
(1) Dividends per share of common stock were $.93, $.90 and $.88 for the years
1996, 1995 and 1994, respectively.
(2) Net of income tax expense (benefit) of approximately $25,000, ($48,000) and
($160,000) for the years 1996, 1995 and 1994, respectively.
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME TAXES
- -------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------------
Current Income Tax Expense
Federal $1,884,609 $3,182,346 $2,375,332
State 356,576 621,238 707,190
Investment tax credit adjustments, net (54,815) (54,815) (54,815)
----------------------------------------------------------
Total current income tax expense 2,186,370 3,748,769 3,027,707
----------------------------------------------------------
Deferred Income Tax Expense
Property, plant and equipment 581,373 455,151 383,306
Deferred gas costs 873,904 (56,915) (656,772)
Pensions and other employee benefits 107,131 57,508 (169,731)
Alternative minimum tax 230,575
Unbilled revenue 54,320 (260,922) 188,356
Contributions in aid of construction (6,979) (283,033) (32,345)
Environmental expenditures 108,578 272,068 (22,067)
Allowance for refund 121,671 442,064 (580,361)
Other 4,357 (244,136) 173,700
----------------------------------------------------------
Total deferred income tax expense (1) 1,844,355 381,785 (485,339)
----------------------------------------------------------
Total Income Tax Expense $4,030,725 $4,130,554 $2,542,368
==========================================================
(1) Total deferred income tax expense includes $392,000, $108,000 and $66,000
of deferred state income taxes for the years 1996, 1995 and 1994,
respectively.
Reconciliation of Effective Income Tax Rates
Federal income tax expense at 34% 3,719,992 3,864,864 2,380,779
State income taxes, net of Federal benefit 505,481 530,471 322,105
Other (194,748) (264,781) (160,516)
----------------------------------------------------------
Total income tax expense $4,030,725 $4,130,554 $2,542,368
==========================================================
Effective income tax rate 36.8% 36.3% 36.3%
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment $10,716,757 $10,363,259
Deferred gas costs 853,851
Other 1,322,272 1,149,563
--------------------------------------
Total deferred income tax liabilities 12,892,880 11,512,822
--------------------------------------
Deferred income tax assets:
State operating loss carryforwards 3,320 126,073
Deferred investment tax credit 426,565 454,590
Unbilled revenue 863,679 918,001
Pension and other employee benefits 917,568 1,024,698
Self insurance 545,836 529,559
Other 495,246 685,382
--------------------------------------
Total deferred income tax assets 3,252,214 3,738,303
--------------------------------------
Deferred Income Taxes Per Consolidated Balance Sheet $9,640,666 $7,774,519
======================================
See accompanying notes
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Accounting Policies
Nature of Business
Chesapeake Utilities Corporation (the "Company") is a diversified utility
company. The Company is engaged in natural gas distribution to approximately
34,700 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 23,100 customers in
southern Delaware, the Eastern Shore of Maryland and Virginia. The advanced
information services segment provides software services and products to a wide
variety of clients.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and
its wholly owned subsidiaries, Eastern Shore Natural Gas Company ("Eastern
Shore"), Sharp Energy, Inc. and Chesapeake Service Company. Sharp Energy, Inc.'s
accounts include those of its wholly owned subsidiary, Sharpgas, Inc.
Chesapeake Service Company's accounts include 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 advanced information
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 4.50% for natural gas distribution, 2.70%
for natural gas transmission, 4.56% for propane distribution, 5.11% for gas
plant acquisition adjustments, 16.10% for advanced information services and
2.22% for other plant.
34
Allowance for Funds Used During Construction
The allowance for funds used during construction ("AFUDC") is an accounting
procedure whereby the cost of borrowed funds and other funds used to finance
construction projects is capitalized as part of utility plant on the balance
sheet, crediting the cost as a non-cash item on the income statement. The cost
of borrowed and equity funds is segregated between interest expense and other
income, respectively. AFUDC was capitalized on utility plant construction at
the rates of 9.51%, 7.31% and 7.15% for 1996, 1995 and 1994, respectively.
Environmental Regulatory Assets
Environmental regulatory assets represent amounts related to environmental
liabilities for which cash expenditures have not been made. As expenditures are
incurred the environmental liability can be reduced along with the environmental
regulatory asset. These amounts are recorded to either environmental
expenditures or accumulated depreciation as cost of removal. All amounts
incurred are amortized in accordance with the ratemaking treatment granted in
each jurisdiction.
Other Deferred Charges and Intangible Assets
Other deferred charges include discount, premium and issuance costs associated
with long-term debt, restricted stock earned for services performed but not yet
awarded and rate case expenses. The discount, premium and issuance costs are
deferred 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 twelve to 40 years.
The gross intangible assets were $1,920,851 and $5,020,851 at December 31, 1996
and 1995, respectively. Accumulated amortization related to intangible assets
was $962,227 and $3,587,090 at December 31, 1996 and 1995, 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.
The Company had state tax loss carryforwards of $46,000 and $2,004,000 at
December 31, 1996 and 1995, respectively. The Company anticipates using all of
the loss carryforwards at December 31, 1996, and therefore no valuation
allowance at December 31, 1996 and 1995 had been recorded. The loss
carryforwards expire in various years beginning in 1997 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 C 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
35
(including current maturities) at December 31, 1996, is approximately $30.3
million as compared to the carrying value of $29.8 million. At December 31,
1995, the estimated fair value was approximately $32.8 million as compared to a
carrying value of $30.7 million.
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 in 1995, 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% of total revenue
during 1995. During 1996 and 1994, no individual customer accounted for 10% or
more of operating revenues.
The Company's natural gas transmission and distribution segments have industrial
interruptible customers that are charged rates which can be adjusted up or down
to make natural gas competitive with alternative fuels. 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 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.
Impairment of Long-Lived Assets
During 1996, the Company adopted SFAS No. 121 "Accounting for the Impairment of
Long-Lived Assets." This statement requires that long-lived assets be reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Additionally, the standard
requires rate-
36
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." When circumstances indicate that the carrying amount of an asset
may be impaired, the Company estimates the future cash flows expected to result
from the use of the asset and its eventual disposition. If the sum of the
undiscounted expected future cash flows is less than the carrying amount of the
asset, the Company recognizes an impairment loss in accordance with SFAS No.
121. The adoption of SFAS No. 121 did not have a material effect on the
Company's financial statements.
Reclassification of Prior Years' Amounts
Certain prior years' amounts have been reclassified to conform with the 1996
presentation.
B. Acquisition
In January 1997, the Company entered into an agreement and plan of merger to
acquire all the outstanding common stock of Tri-County Gas Company, Inc. ("Tri-
County") and associated properties. The principal business of Tri-County is the
distribution of propane to both retail and wholesale customers on the Delmarva
Peninsula.
The transaction, which is expected to be completed in the first calendar
quarter, will be effected through the exchange of 639,000 shares of the
Company's common stock and accounted for as a pooling of interests. Accordingly,
historical financial data in future reports will be restated to include Tri-
County data. The following unaudited pro forma data summarizes the combined
results of operations of the Company and Tri-County as though the transaction
had occurred at the beginning of calendar year 1995.
For the Years Ended December 31,
(Unaudited pro forma) 1996 1995
- --------------------------------------------------------------------------------
Operating revenue $130,234,503 $111,825,347
Operating income before income taxes $ 14,034,590 $ 14,050,757
Operating income $ 9,857,769 $ 9,916,355
Net income $ 7,335,790 $ 7,455,242
Primary earnings per share $ 1.66 $ 1.72
Fully diluted earnings per share $ 1.61 $ 1.67
- --------------------------------------------------------------------------------
The unaudited pro forma data does not purport to be indicative of what results
may occur of the combined companies in the future.
C. Investments
The investment balance at December 31, 1996 and 1995 consists primarily of the
common stock of Florida Public Utilities Company ("FPU"). The Company's
ownership at December 31, 1996 and 1995 represents a 7.41% and 7.04% 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. At December 31, 1996, the market value exceeded the
aggregate cost basis of the Company's portfolio by $63,598. The aggregate cost
basis of the Company's portfolio at December 31, 1995 exceeded its market value
by $120,839.
37
D. Lease Obligations
The Company has entered into several operating leases for office space at
various locations. Rent expense related to these leases was $293,038, $409,214
and $418,047 for 1996, 1995 and 1994, respectively. Future minimum payments
under the Company's current lease agreements are $220,103; $139,533; $141,958;
$146,454 and $74,396 for the years of 1997 through 2001, respectfully; and
$114,261 thereafter.
E. Segment Information
- -----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
Operating Revenues, Unaffiliated Customers
Natural gas distribution $74,904,076 $54,120,280 $49,523,743
Natural gas transmission 15,188,777 24,984,767 22,191,896
Propane distribution 22,333,969 17,607,956 20,684,150
Advanced information services and other 6,903,246 7,307,413 6,172,508
----------------------------------------------------------
Total operating revenues, unaffiliated customers $119,330,068 $104,020,416 $98,572,297
==========================================================
Intersegment Revenues *
Natural gas distribution $8,711 $42,037 $55,888
Natural gas transmission 21,543,327 16,663,043 17,303,529
Propane distribution 2,059 139,052 85,552
Advanced information services and other 710,949 1,722,135 2,277,361
----------------------------------------------------------
Total intersegment revenues $22,265,046 $18,566,267 $19,722,330
==========================================================
Operating Income Before Income Taxes
Natural gas distribution $7,167,236 $4,728,348 $4,696,659
Natural gas transmission 2,458,442 6,083,440 3,018,212
Propane distribution 2,053,299 1,852,630 2,287,688
Advanced information services and other 1,305,203 1,170,970 174,033
----------------------------------------------------------
Total 12,984,180 13,835,388 10,176,592
Add (Less): Eliminations 206,580 (248,595) (419,883)
----------------------------------------------------------
Total operating income before income taxes $13,190,760 $13,586,793 $9,756,709
==========================================================
Depreciation and Amortization
Natural gas distribution $2,854,843 $2,502,531 $2,136,979
Natural gas transmission 697,834 638,099 641,485
Propane distribution 1,306,053 1,312,048 1,323,698
Advanced information services 131,877 969,588 1,021,944
Other plant 111,216 39,486 16,573
----------------------------------------------------------
Total depreciation and amortization $5,101,823 $5,461,752 $5,140,679
==========================================================
Capital Expenditures
Natural gas distribution $6,634,827 $7,236,848 $8,160,874
Natural gas transmission 5,567,509 1,335,793 619,852
Propane distribution 1,693,113 1,640,203 828,519
Advanced information services 162,189 114,461 411,957
Other plant 244,120 1,772,454 632,137
----------------------------------------------------------
Total capital expenditures $14,301,758 $12,099,759 $10,653,339
==========================================================
Identifiable Assets, at December 31,
Natural gas distribution $81,250,030 $75,630,741 $68,528,774
Natural gas transmission 23,981,989 19,292,524 17,792,415
Propane distribution 20,791,588 18,855,507 16,949,431
Advanced information services 1,496,418 1,635,100 3,196,064
Other 3,617,885 3,380,108 1,803,933
----------------------------------------------------------
Total identifiable assets $131,137,910 $118,793,980 $108,270,617
==========================================================
* All significant intersegment revenues have been eliminated from
consolidated revenues.
38
F. Long-Term Debt
The outstanding long-term debt, net of current maturities is as follows:
- ------------------------------------------------------------------------------------
At December 31, 1996 1995
First mortgage sinking fund bonds:
Adjustable rate Series G*, due January 1, 1998 $ 62,500 $ 312,500
9.37% Series I, due December 15, 2004 4,820,000 5,340,000
12.00% Mortgage, due February 1, 1998 14,868 28,139
8.25% Convertible debentures, due March 1, 2014 4,087,000 4,114,000
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 10,000,000
-------------------------
Total long-term debt $28,984,368 $29,794,639
-------------------------
* The Series G bonds are subject to an interest rate equal to seventy-three
percent (73%) of the prime rate (8.25% and 8.5% at December 31, 1996 and 1995),
respectively.
The convertible debentures may be converted, at the option of the holder, into
shares of the Company's common stock at a conversion price of $17.01 per share.
During 1996, $15,000 in debentures were converted. The debentures are redeemable
at the option of the holder, subject to an annual non-cumulative maximum
limitation of $200,000 in the aggregate. As of December 31, 1996, approximately
$8,000 of the debentures have been accepted for redemption in 1997. 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, 1996, the amounts available for future
dividends permitted by the Series I covenant approximated $13.0 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 1997 through 2001
are $791,271, $597,368, $1,520,000, $2,665,091 and $2,665,091.
G. Short-Term Borrowings
The Board of Directors has authorized the Company to borrow up to $20,000,000
from various bank and trust companies. As of December 31, 1996, 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, 1996 and
1995, the Company had short-term debt outstanding of $12,000,000 and $4,800,000,
respectively, with a weighted average interest rate of 6.12% and 6.00%,
respectively.
39
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.
- -----------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stock: Shares issued and outstanding*
Balance - beginning of year 3,721,589 3,668,791 3,605,152
Dividend Reinvestment Plan 33,926 38,660 30,928
USI restricted stock award agreements 21,859 14,138 32,418
Conversion of debentures 881 293
Exercised stock options 1,863
Sale of stock to Company's Retirement Savings Plan 20,398
Balance - end of year 3,800,516 3,721,589 3,668,791
-------------------------------------------
Shares of common stock held in treasury
Balance - beginning of year 15,609 30,084
Sale of stock to Company's Retirement Savings Plan (15,609) (14,475)
-------------------------------------------
Balance - end of year 15,609
-------------------------------------------
*12,000,000 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 were awarded as a
non-cash transaction over a five-year period beginning in 1992, and restrictions
lapse over a five to ten-year period from the award date, if certain financial
targets are met. At December 31, 1996 and 1995, respectively, 24,350 and 29,598
shares valued at $364,529 and $415,107 remain restricted.
The Performance Incentive Plan, which was adopted in 1992, provides for the
granting of stock options to certain officers of the Company over a 10-year
period. In November 1994, the Company executed Tandem Stock Option and
Performance Share Agreements ("Agreements") with certain executive officers.
These Agreements provide the participants an option to purchase shares of the
Company'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 1996, the Company recorded $276,522 to recognize the
compensation expense associated with the performance shares. Changes in
outstanding options were as follows:
- -----------------------------------------------------------------------------------------------------------------------------------
1996 1995 1994
Number Option Number Option Number Option
of shares price of shares price of shares price
- -----------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year 125,186 $12.625 - $12.75 136,186 $12.625 - $12.75 80,280 $ 12.75
Options granted 55,906 $12.625
Options exercised (12,135) $12.75
Options forfeited (11,000) $ 12.625
Balance - end of year 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75 136,186 $12.625 - $12.75
Exercisable 83,114 $12.625 - $12.75 80,280 $ 12.75 53,520 $ 12.75
- ------------------------------------------------------------------------------------------------------------------------------------
40
During 1996, the Company adopted SFAS No. 123, "Accounting for Stock-Based
Compensation", for note disclosure purposes only, as prescribed by the standard.
No stock options were granted during 1996 or 1995, and therefore, no pro forma
disclosures have been provided.
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.
Total Net Pension Cost
- -----------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------------
Service cost $ 656,985 $ 474,000 $ 592,294
Interest cost 658,238 562,003 518,184
Less: Actual (return) loss on assets (1,142,287) (1,546,325) 742,949
Net amortization and deferral 269,135 689,947 (1,465,744)
--------------------------------------------------
Total net pension cost 442,071 179,625 387,683
Amounts capitalized as construction cost (38,860) (30,740) (52,549)
--------------------------------------------------
Amount charged to expense $ 403,211 $ 148,885 $ 335,134
---------------------------------------------------
Discount rate used in calculating net pension cost 7.25% 8.50% 7.00%
The following schedule sets forth the funding status of the pension plan at
December 31, 1996 and 1995.
Accrued Pension Cost
- ------------------------------------------------------------------------------------------------------------------------------------
At December 31, 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------------
Vested $ 6,834,661 $ 5,730,239
Non-vested 139,483 100,878
------------------------------
Total accumulated benefit obligation $ 6,974,144 $ 5,831,117
------------------------------
Plan assets at fair value $ 10,720,514 $ 9,173,094
Projected benefit obligation (10,265,987) (9,331,890)
------------------------------
Plan assets less projected benefit obligation 454,527 (158,796)
Unrecognized net gain (2,820,957) (2,319,138)
Unamortized net assets from adoption of SFAS No. 87 (141,579) (156,683)
-------------------------------
Accrued pension cost ($2,508,009) ($2,634,617)
-------------------------------
Assumptions:
Discount rate 7.25% 7.25%
Average increase in future compensation levels 4.75% 5.50%
Expected long-term rate of return on assets 8.50% 8.50%
41
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 the first quarter of 1994, the Company increased the amount that
future retirees would be required to contribute to participate in the Company's
health care program. The change reduced the Company's transition obligation and
annual costs to $357,000 and $70,000, respectively. The change also resulted in
a one-time curtailment loss of $64,000 in 1994. The Company had deferred
approximately $126,000, which represented the difference between the Maryland
division's SFAS No. 106 expense and its actual pay-as-you-go cost. The amount is
being amortized over five years starting in 1995. The unamortized balance is
$101,000 at December 31, 1996.
Net Periodic Postretirement Benefit Cost
At December 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------------
Service cost $ 2,820 $ 1,827 $ 3,553
Interest cost on APBO 54,651 59,706 44,118
Amortization of transition obligation over 20 years 27,859 27,859 22,148
Curtailment loss 63,821
-------------------------------------------
Net periodic postretirement benefit cost 85,330 89,392 133,640
Amount capitalized as construction cost (16,672) (14,010) (20,134)
Amount deferred (20,561) (13,212)
-------------------------------------------
Amount charged to expense $ 68,658 $ 54,821 $100,294
--------------------------------------------
Assumption:
Discount rate 7.25% 8.50% 7.00%
Accrued Postretirement Benefit Liability
- --------------------------------------------------------------------------------------------------------
At December 31, 1996 1995
- --------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 567,599 616,664
Fully eligible active employees 137,378 135,297
Other active 86,894 90,724
---------------------------
Total accumulated postretirement benefit obligation 791,871 842,685
Unrecognized transition obligation (273,013) (300,872)
Unrecognized net (loss) gain (67,155) (70,873)
---------------------------
Accrued postretirement liability $451,703 $470,940
---------------------------
Assumption:
Discount rate 7.25% 7.25%
The health care inflation rate for 1996 is assumed to be 10%. This rate is
projected to gradually decrease to an ultimate rate of 5% by the year 2007. A
one percentage point increase in the health care inflation rate from the assumed
rate would increase the accumulated postretirement benefit obligation by
approximately $90,396 as of January 1, 1997, and would increase the aggregate of
the service cost and interest cost components of net periodic postretirement
benefit cost for 1997 by approximately $7,366.
42
Retirement Savings Plan
upon eligible compensation. The Company makes a contribution equal exceed 6%, of
the to 60% or 100% of each participant's pre-participant's eligible compensation
for the plan year. The Company's contributions totaled $353,350, $301,794 and
$240,103 for the years ended December 31, 1996, 1995 and 1994, respectively. As
of December 31, 1996, there are 79,602 shares reserved to fund future
contributions to the Plan.
J. Environmental Commitments and Contingencies
The Company currently is participating in the investigation, assessment or
remediation of 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 ground-water remediation and $3.3 million for soil remediation. On May 17,
1995, EPA issued an order to the Company under Section 106 of CERCLA (the
"Order"), which requires the Company to fund or implement the ROD. The Order was
also issued to General Public Utilities Corporation, Inc. ("GPU"), which both
EPA and the Company believe is liable under CERCLA. Other potentially
responsible parties ("PRPs") such as the State of Delaware were not ordered to
perform the ROD. In July 1996, the Company commenced the design phase of the
ROD, on-site pre-design and investigation. A pre-design investigation report
("the report") was filed in October 1996 with the EPA. The report, which
requires EPA approval, will provide up to date status on the site, which the EPA
will use to determine if the remedial design selected in the ROD is still the
appropriate remedy.
On March 6, 1995, the Company commenced litigation against the State of Delaware
for contribution to the remedial costs being incurred to carry out the ROD. In
December of 1995, this case was dismissed without prejudice based on a
settlement agreement between the parties (the "Settlement"). Under the
Settlement, the State agreed to contribute $600,000 toward the cost of
implementing the ROD and to reimburse the EPA for $400,000 in oversight costs.
The Settlement is contingent upon a formal settlement agreement between EPA and
the State of Delaware being reached within the next two years. Upon satisfaction
of all conditions of the Settlement, the litigation will be dismissed with
prejudice.
On June 25, 1996, the Company initiated litigation against one of the other PRPs
for contribution to the remedial costs incurred by Chesapeake in connection with
complying with the ROD. At this time, management cannot predict the outcome of
the litigation or the amount of proceeds to be received, if any.
The Company is currently engaged in investigations related to additional parties
who may be PRPs. Based upon these investigations, the Company will consider suit
against other PRPs. The Company expects continued negotiations with PRPs in an
attempt to resolve these matters.
In the third quarter of 1994, the Company increased its liability recorded with
respect to the Dover site to $6.0 million. This amount reflected the EPA's
estimate, as stated in the ROD, for remediation of the site according to the
ROD. The recorded liability may be adjusted upward or downward as the design
phase progresses and the Company obtains construction bids for performance of
the work. The Company has also recorded a regulatory asset of $6.0 million,
corresponding to the recorded liability. Management believes that in addition to
the $600,000 expected to be contributed by the State of Delaware under the
Settlement, the Company will be equitably entitled to contribution from other
responsible parties for a portion of the expenses to be incurred in connection
with the remedies selected in the ROD. Management also believes that the amounts
not so contributed will be recoverable in the Company's rates.
43
During 1996, the Company completed construction and began remediation procedures
at the Salisbury site and will be reporting, on an ongoing basis, the
remediation and monitoring results to the Maryland Department of the
Environment. The Company has accrued a liability with respect to the Salisbury
site of $650,088 as of December 31, 1996. This amount is based on the estimated
operating costs of the remediation facilities. A corresponding regulatory asset
has been recorded, reflecting the Company's belief that costs incurred will be
recoverable in rates.
Portions of the liability payouts for the Dover and Salisbury sites are expected
to be over 30 and five-year periods, respectively. In addition, the Company has
two other sites. One site located in the state of Florida, is currently being
evaluated for which no estimate of liability can be made at this time. The other
site has been remediated, and in 1996 the Company received the site closure
certificate. 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.
- ------------------------------------------------------------------------------
At December 31, 1996 1995
- ------------------------------------------------------------------------------
Environmental Costs Incurred
Delaware $ 4,423,843 $3,929,417
Maryland 2,187,810 1,805,572
Florida 660,828 629,153
-----------------------
7,272,481 6,364,142
Less: Amounts approved for ratemaking treatment,
net of insurance proceeds 6,396,108 6,066,096
-----------------------
Amounts pending ratemaking recovery $ 876,373 $ 298,046
-----------------------
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 this issue.
In response to the FERC's May 19, 1994 Order, Eastern Shore accrued $412,000
during the second quarter of 1994 as an estimated liability for potential
refunds relating to prior periods. Thereafter, Eastern Shore accrued each month
to ensure that the potential refund was fully accrued. On August 17, 1995, the
FERC issued an Order approving an Offer of Settlement submitted by Eastern
Shore. The Order approved a change in Eastern Shore's PGA methodology
retroactive to June 1, 1994, which resulted in a rate reduction of approximately
$234,000 per year. The reserves that the Company had accrued for the potential
refund were significantly greater than the rate reduction ordered. Accordingly,
Eastern Shore reversed a large portion of the estimated liability that had been
accrued. This reversal contributed $1,385,000 to pre-tax earnings, or $833,000
to after-tax earnings, during the third quarter of 1995. In connection with the
offer of settlement and the resulting FERC Order, Eastern Shore applied in
December 1995 to the FERC for a blanket certificate authorizing open access
transportation service on its pipeline system. The implementation of open access
transportation service, expected to occur during 1997, will provide all of
Eastern Shore's customers with the opportunity to transport gas over its system
at FERC regulated rates. Open access is thus likely to result in a shift of
Eastern Shore's business from margins earned on sales of gas to large industrial
customers, to a possibly lower margin earned on transportation services.
Other Commitments and Contingencies
The Company is involved in certain legal actions and claims arising in the
normal course of business. The Company is also involved in certain legal and
administrative proceedings before various governmental agencies
44
concerning rates. In the opinion of management, the ultimate dispositon of these
proceedings will 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.
- -----------------------------------------------------------------------------------
First Second Third Fourth
1996 Quarter Quarter Quarter Quarter
- -----------------------------------------------------------------------------------
Operating Revenue $44,270,265 $23,850,551 $18,475,914 $32,733,338
Operating Income $ 5,277,681 $ 1,401,082 $ 153,444 $ 2,411,567
Net Income $ 4,649,009 $ 832,457 ($390,871) $ 1,819,833
Primary Earnings Per Share $ 1.24 $ 0.22 ($0.10) $ 0.48
Fully Diluted Earnings Per
Share $ 1.17 $ 0.22 ($0.10) $ 0.46
- -----------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------
Results for the third quarter 1995 refelect a non-recurring increase in net
income of $833,000, (see Note K to the Consolidated Financial Statements).
45
OPERATING STATISTICS
- --------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------------------------
Revenues (In thousands)
Natural gas
Residential $18,256 $14,857 $15,228 $14,007 $12,935
Commercial 14,339 11,383 11,594 10,837 9,857
Industrial 28,546 36,898 32,718 31,622 26,977
Sale for resale 24,481 12,459 9,586 5,242 3,843
Transportation 3,369 2,993 2,639 2,480 2,400
Other 1,102 515 (50) 193 (134)
-----------------------------------------------------------------------------------
Total natural gas revenues 90,093 79,105 71,715 64,381 55,878
Propane 22,334 17,608 17,789/*/ 16,908 16,489
Other 6,903 7,307 6,173 4,584 3,568
===================================================================================
Total revenues $119,330 $104,020 $95,677 $85,873 $75,935
===================================================================================
Volumes
Natural gas deliveries (in MMCF)
Residential 1,987 1,686 1,665 1,596 1,561
Commercial 2,092 1,792 1,771 1,676 1,633
Industrial 7,501 13,622 10,752 9,308 8,014
Sale for resale 1,065 990 998 984 997
Transportation 12,096 11,131 7,542 5,880 5,139
-----------------------------------------------------------------------------------
Total natural gas deliveries 24,741 29,221 22,728 19,444 17,344
===================================================================================
Propane (in thousands of gallons) 19,853 17,748 18,395/*/ 17,250 17,125
===================================================================================
Customers
Natural gas
Residential 30,349 29,285 28,260 27,312 26,523
Commercial 4,151 4,030 3,879 3,759 3,683
Industrial/**/ 210 212 204 196 198
Sale for resale/**/ 3 3 3 3 3
-----------------------------------------------------------------------------------
Total natural gas customers 34,713 33,530 32,346 31,270 30,407
Propane 23,096 22,609 22,180 21,622 21,132
-----------------------------------------------------------------------------------
Total customers 57,809 56,139 54,526 52,892 51,539
===================================================================================
/*/ Excludes revenue of $2,895,000, which resulted from the sale of nine
million gallons of propane to one large wholesale customer in 1994.
/**/Includes transportation customers.
Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure
None
PART III
Item 10. Directors and Executive Officers of the Registrant
Information pertaining to the Directors of the Company is incorporated herein by
reference to the Proxy Statement, under "Information Regarding the Board of
Directors and Nominees", dated and to be filed on or before April 4, 1997 in
connection with the Company's Annual Meeting to be held on May 20, 1997.
The information required by this item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Item 10 of Part I of this Form 10-K under "Executive Officers of the
Registrant."
Item 11. Executive Compensation
This information is incorporated herein by reference to the Proxy Statement,
under "Report on Executive Compensation", dated and to be filed on or before
April 4, 1997 in connection with the Company's Annual Meeting to be held on May
20, 1997.
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 4, 1997 in connection with the Company's Annual Meeting to be
held on May 20, 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 4, 1997 in connection with the Company's Annual Meeting to be
held on May 20, 1997.
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 13, 1997 of Coopers &
Lybrand L.L.P., Independent Accountants
- Consolidated Statements of Income for each of the three
years ended December 31, 1996, 1995 and 1994
- Consolidated Balance Sheets at December 31, 1996 and
December 31, 1995
- Consolidated Statements of Cash Flows for each of the three
years ended December 31, 1996, 1995 and 1994
- Consolidated Statements of Common Stockholders' Equity for
each of the three years ended December 31, 1996
- Consolidated Statements of Income Taxes for each of the
three years ended December 31, 1996
- Notes to Consolidated Financial Statements
47
2. The following additional information for the years 1996, 1995 and 1994
is submitted herewith: Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not required, are inapplicable,
or the information is otherwise shown in the financial statements or notes
thereto.
(b) Reports on Form 8-K
On January 13, 1997, the Company filed a report on Form 8-K, reporting
under Item 5 that the Company has agreed to purchase all of the
outstanding shares of Tri-County Gas Company, Inc.
(c) 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 10-Q 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 10-K 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.*
48
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.*
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.*
49
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 10-K for the year ended December 31,
1994 for Chesapeake Utilities Corporation.*
Exhibit 10.(n) - Agreement and Plan of Merger by and between Chesapeake
Utilities Corporation and Tri-County Gas Company, Inc. is
incorporated herein by reference from the Form 8-K filed on
January 13, 1997.
Exhibit 11. - Computation of Primary and Fully Diluted Earnings Per Share,
filed herewith.
Exhibit 12. - 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.
50
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange
Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
CHESAPEAKE UTILITIES CORPORATION
By: /s/ RALPH J. ADKINS
----------------------
Ralph J. Adkins
President and Chief Executive Officer
Date: March 17, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
/s/ JOHN W. JARDINE, JR. /s/ RALPH J. ADKINS
- ------------------------- --------------------
John W. Jardine, Jr., Ralph J. Adkins, President,
Chairman of the Board and Director Chief Executive Officer and
Director
Date: March 17, 1997 Date: March 17, 1997
/s/ JOHN R. SCHIMKAITIS /s/ MICHAEL P. MCMASTERS
- ------------------------- -------------------------
John R. Schimkaitis, Executive Vice Michael P. McMasters
President, Chief Operating Officer, Vice President, Chief Financial
Director Officer and Treasurer
(Principal Financial Officer)
Date: March 17, 1997 Date: March 17, 1997
/s/ JEREMIAH P. SHEA /s/ ROBERT F. RIDER
- --------------------- --------------------
Jeremiah P. Shea, Director Robert F. Rider, Director
Date: March 17, 1997 Date: March 17, 1997
/s/ WILLIAM G. WARDEN, III /s/ RUDOLPH M. PEINS, JR.
- --------------------------- --------------------------
William G. Warden, III, Director Rudolph M. Peins, Jr., Director
Date: March 17, 1997 Date: March 17, 1997
/s/ RICHARD BERNSTEIN /s/ WALTER J. COLEMAN
- ---------------------- ----------------------
Richard Bernstein, Director Walter J. Coleman, Director
Date: March 17, 1997 Date: March 17, 1997
51
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
======================================== =============== =================================== =============== =================
----- Additions -----
===================================
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Description of Period Expense Accounts Deductions of Period
======================================== =============== =============== ================== =============== =================
Valuation accounts deducted from assets
to which they apply for doubtful
accounts receivable:
1996 . . . . . . . . . . . . . $309,955 $364,622 $55,631 (B) ($337,796) (A) $392,412
1995 . . . . . . . . . . . . . $202,152 $328,012 $43,151 (B) ($263,360) (A) $309,955
1994 . . . . . . . . . . . . . $186,018 $130,263 $57,633 (B) ($171,762) (A) $202,152
Notes:
(A) Uncollectible accounts charged off.
(B) Recoveries.
52