State of Delaware 51-0064146
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]. No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [X]
As of March 26, 1999, 5,115,971 shares of common stock were outstanding. The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation, based on the last trade price on March 26, 1999, as reported by the New York Stock Exchange, was approximately $67 million.
TABLE OF CONTENTS
Page
PART I ........................................................................1
Item 1. Business ..............................................................1
Item 2. Properties ...........................................................11
Item 3. Legal Proceedings ....................................................11
Item 4. Submission of
Matters to a Vote of Security Holders ................................14
Item 10. Executive Officers of the Registrant ................................14
PART II ......................................................................15
Item 5. Market for the Registrant's Common Stock
and Related Security Holder Matters ..................................15
Item 6. Selected Financial Data ..............................................16
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ........................17
Item 7a. Quantitative and Qualitative Disclosures
About Market Risk ...................................................24
Item 8. Financial Statements and Supplemental Data ...........................24
Item 9. Changes In and Disagreements With Accountants
on Accounting and Financial Disclosure ...............................44
PART III .....................................................................44
Item 10. Directors and Executive Officers
of the Registrant ...................................................44
Item 11. Executive Compensation ..............................................44
Item 12. Security Ownership of Certain
Beneficial Owners and Management ....................................44
Item 13. Certain Relationships and Related Transactions ......................44
PART IV.......................................................................44
Item 14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K.....................................44
Signatures ...................................................................47
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Item 1. Business
(a) General Development of Business
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a
diversified utility company engaged primarily in natural gas distribution and
transmission, propane distribution and marketing and advanced information
services.
Chesapeake's three natural gas distribution divisions serve approximately 37,100 residential, commercial and industrial customers in southern Delaware, Maryland's Eastern Shore and Central Florida. The Company's natural gas transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"), operates a 273-mile interstate pipeline system that transports gas from various points in Pennsylvania to the Company's Delaware and Maryland distribution divisions, as well as to other utilities and industrial customers in Delaware and on the Eastern Shore of Maryland. The Company's propane distribution operation serves approximately 35,000 customers in southern Delaware and on the Eastern Shore of Maryland and Virginia. The advanced information services segment provides consulting, custom programming, training and development tools for national and international clients.
(b) Financial Information about Industry Segments Financial information by business segment is included in Item 7 under the heading "Notes to Consolidated Financial Statements - Note C".
(c) Narrative Description of Business The Company is engaged in four primary business activities: natural gas transmission, natural gas distribution, propane distribution and marketing and advanced information services. In addition to the four primary groups, Chesapeake has four subsidiaries engaged in other service-related businesses.
(i) (a) Natural Gas Transmission General Eastern Shore, the Company's wholly owned transmission subsidiary, operates an interstate natural gas pipeline and provides open access transportation services for affiliated and non-affiliated companies through an integrated gas pipeline extending from southeastern Pennsylvania to Delaware and the Eastern Shore of Maryland. Eastern Shore also provides contract storage services as well as the purchase and sale of small quantities of gas for system balancing purposes ("swing gas"). Eastern Shore's rates are subject to regulation by the Federal Energy Regulatory Commission ("FERC").
Adequacy of Resources
Eastern Shore has 4,916 thousand cubic feet ("Mcf") of firm transportation
capacity under Rate Schedule FT under contract with Transcontinental Gas
Pipe Line Corporation ("Transco") which expires in 2005. Eastern Shore also
has 7,046 Mcf of firm peak day entitlements and total storage capacity of
278,264Mcf under Rate Schedules GSS, LSS and LGA, respectively, under
contract with Transco. The GSS and LSS contracts expire in 2013 and the LGA
contract expires in 2006.
Eastern Shore also has firm storage service under Rate Schedule FSS and firm storage transportation capacity under Rate Schedule SST under contract with Columbia Gas Transmission ("Columbia"). These contracts, which expire in 2004, provide for 1,073 Mcf of firm peak day entitlement and total storage capacity of 53,738 Mcf.
Eastern Shore has retained the firm transportation capacity and firm storage services described above in order to provide swing transportation service to those customers that requested such service.
Competition
Under the open access environment, interstate pipeline companies have
unbundled the traditional components of their service - gas gathering,
transportation and storage - from the sale of the commodity. Pipelines that
choose to be merchants of gas must form separate marketing operations
independent of their pipeline operations. Hence, gas marketers have
developed as a viable option for many companies because they are providing
expertise in gas purchasing along with collective purchasing capabilities
which, when combined, may reduce the end-user cost. Additional discussion
on competition is included in Item 7 under the heading "Management's
Discussion and Analysis - Competition".
Rates and Regulation
General. Eastern Shore is subject to regulation by the FERC as an
interstate pipeline. The FERC regulates the provision of service, terms and
conditions of service, and the rates and fees Eastern Shore can charge to
its transportation customers. In addition, the FERC regulates the rates
Eastern Shore is charged for transportation and transmission line capacity
and services provided by Transco and Columbia.
Regulatory Proceedings
Amendment to Rt. 72 and Porter Road filing. On March 6, 1998, the FERC
authorized Eastern Shore to replace 2.3 miles of 6-inch pipeline with 10-
inch pipeline along Route 72 and Power Road, all in conjunction with a
Delaware Department of Transportation highway relocation project. On
September 15, 1998, Eastern Shore filed an amendment in Docket No. CP97-
279-001 requesting that the FERC authorize an increase in the diameter of
the previously approved 2.3-mile pipeline from 10 inches to 16 inches.
Eastern Shore filed this amendment in connection with the 1999 System
Expansion described below. The FERC issued an Order Amending Certificate in
this docket on October 16, 1998, approving Eastern Shore's proposal.
Construction has started and is expected to be completed during 1999.
1999 System Expansion. On September 25, 1998, Eastern Shore filed an application before the FERC requesting authorization to construct and operate a total of eight miles (4.5 miles in Pennsylvania and 3.5 miles in Delaware) of 16-inch pipeline looping on Eastern Shore's existing system and to install 1,085 horsepower of additional compression at its Delaware City compressor station. The purpose of these new facilities is to enable Eastern Shore to provide 16,540 dekatherms of additional firm transportation capacity on its system for two existing customers, Delmarva Power and Light Company and Star Enterprise. The proposed expansion has been targeted for completion on November 1, 1999. The estimated project cost is approximately $7.0 million and is expected to generate approximately $1.8 million in additional annual revenue. Eastern Shore also requested the FERC to issue a preliminary determination of rolled-in treatment of the costs incurred in this project into existing rates. The Company is awaiting FERC approval.
Rate Case Filing. In October 1996, Eastern Shore filed for a general rate increase with the FERC. The filing proposed an increase in Eastern Shore's jurisdictional rates that would generate additional annual operating revenue of approximately $1.4 million. Eastern Shore also stated in the filing that it intended to use the cost-of-service submitted in the general rate increase filing to develop rates in the pending Open Access Docket. In September 1997, the FERC approved a rate increase of $1.2 million.
Open Access Filing. In December 1995, Eastern Shore filed its abbreviated
application for a blanket certificate of public convenience and necessity
authorizing the transportation of natural gas on behalf of others. Eastern
Shore proposed to unbundle the sales and storage services it had provided.
Customers who had previously received firm sales and storage services on
Eastern Shore (the "Converting Customers") would receive entitlements to
firm transportation service on Eastern Shore's pipeline in a quantity
equivalent to their existing service rights. Eastern Shore proposed to
retain some of its pipeline entitlements and storage capacity for
operational issues and to facilitate "no-notice" (no prior notification
required to receive service) transportation service on its pipeline system.
Eastern Shore would release or assign to the remaining Converting Customers
the firm transportation capacity, including contract storage, it held on
its upstream pipelines so that the Converting Customers would be able to
become direct customers of such upstream pipelines. Converting Customers
who previously received bundled sales service having no-notice
characteristics would have the right to elect no-notice firm transportation
service.
In connection with the rate increase settlement, the issues listed above
pertaining to Eastern Shore operating as an open access pipeline were also
settled in September 1997, with open access implementation occurring on
November 1, 1997.
Delaware City Compressor Station Filing. In December 1995, Eastern Shore filed an application before the FERC pursuant to Sections 7(b) and (c) of the Natural Gas Act for a certificate of public convenience and necessity authorizing Eastern Shore to: (1) construct and operate a 2,170 horsepower compressor station in Delaware City, New Castle County, Delaware on a portion of its existing pipeline system known as the "Hockessin Line", such new station to be known as the "Delaware City Compressor Station"; (2) construct and operate slightly less than one mile of 16-inch pipeline in Delaware City, New Castle County, Delaware to tie the suction side of the proposed Delaware City Compressor Station into the Hockessin Line; and (3) increase the maximum allowable operating pressure on 28.7 miles of Eastern Shore's pipeline from Eastern Shore's existing Bridgeville Compressor Station in Bridgeville, Sussex County, Delaware to its terminus in Salisbury, Wicomico County, Maryland.
In September 1996 the FERC issued its Final Order, which: authorized Eastern Shore to: (1) construct and operate the facilities requested in its application: (2) roll-in the cost of the facilities into its existing rates if the revenues from the increase in services exceed the cost associated with the expansion portion of the project; and (3) abandon the 100 Mcf per day of firm sale service to one of its direct sale customers. The FERC's Final Order also denied Eastern Shore the authority to increase the level of sales and storage service it provides its customers until it completes its restructuring in its open access proceeding. The compressor facility and associated piping were needed to stabilize capacity on Eastern Shore's system as a result of steadily declining inlet pressures at the Hockessin interconnect with Transcontinental Gas Pipe Line Corporation. Construction of the facilities started during the second half of 1996 and was completed during the first quarter of 1997.
(i) (b) Natural Gas Distribution General Chesapeake distributes natural gas to approximately 37,100 residential, commercial and industrial customers in southern Delaware, the Salisbury and Cambridge, Maryland areas on Maryland's Eastern Shore, and Central Florida. These activities are conducted through three utility divisions, one division in Delaware, another in Maryland and a third division in Florida. In 1993, the Company started natural gas supply management services in the state of Florida under the name of Peninsula Energy Services Company ("PESCO").
Delaware and Maryland. The Delaware and Maryland divisions serve an average of approximately 27,900 customers, of which approximately 27,800 are residential and commercial customers purchasing gas primarily for heating purposes. Annually, residential and commercial customers account for approximately 56% of the volume delivered by the divisions and 75% of the divisions' revenue. The divisions' industrial customers purchase gas, primarily on an interruptible basis, for a variety of manufacturing, agricultural and other uses. Most of Chesapeake's customer growth in these divisions comes from new residential construction using gas heating equipment.
Florida. The Florida division distributes natural gas to an average of approximately 9,100 residential and commercial and 90 industrial customers in Polk, Osceola and Hillsborough Counties. Currently 41 of the division's industrial customers, which purchase and transport gas on a firm and interruptible basis, account for approximately 89% of the volume delivered by the Florida division and 50% of the division's annual natural gas and transportation revenues. These customers are primarily engaged in the citrus and phosphate industries and electric cogeneration. The Company's Florida division also provides natural gas supply management services to compete in the open access environment. Currently, twenty-two customers receive such services, which generated net income of $66,000 in 1998.
Adequacy of Resources
General. Chesapeake's Delaware and Maryland utility divisions ("Delaware",
"Maryland" or "the Divisions") have firm and interruptible contracts with
four (4) interstate "open access" pipelines. The Divisions are directly
interconnected with Eastern Shore and services upstream of Eastern Shore
are contracted with Transco, Columbia, and Columbia Gulf Transmission
Company ("Gulf"). The Divisions use their firm supply sources to meet a
significant percentage of their projected demand requirements. In order to
meet the difference between firm supply and firm demand, Delaware and
Maryland obtain gas supply on the "spot market" from various other
suppliers that is transported by the upstream pipelines and delivered to
the Divisions' interconnects with Eastern Shore as needed. The Company
believes that Delaware and Maryland's available firm and "spot market"
supply is ample to meet the anticipated needs of their customers.
Delaware. Delaware's contracts with Transco include: (a) firm transportation capacity of 8,663 dekatherms ("Dt") per day, which expires in 2005; (b) firm transportation capacity of 311 Dt per day for December through February, expiring in 2006; and (c) firm storage service, providing a total capacity of 142,830 Dt. Delaware and Transco are currently engaged in negotiations with regard to an extension of the term of the firm storage service. Although the original contract expired in 1998, Transco and Delaware have continued under the previous terms and conditions until an agreement is finalized.
Delaware's contracts with Columbia include: (a) firm transportation capacity of 852 Dt per day, which expires in 2004; (b) firm transportation capacity of 1,132 Dt per day, which expires in 2017; (c) firm transportation capacity of 549 Dt per day, which expires in 2018; (d) firm storage service providing a peak day entitlement of 6,193 Dt and a total capacity of 298,195 Dt, expiring in 2004; and (f) firm storage service, providing a peak day entitlement of 583 Dt per day and a total capacity of 52,460 Dt, which expires in 2018. Delaware's contracts with Columbia for storage related transportation provide quantities that are equivalent to the peak day entitlement for the period of October through March and are equivalent to fifty percent (50%) of the peak day entitlement for the period of April through September. The terms of the storage related transportation contracts mirror the storage services that they support.
Delaware's contract with Gulf, which expires in 2004, provides firm transportation capacity of 868 Dt per day for the period November through March and 798 Dt per day for the period April through October.
Delaware's contracts with Eastern Shore include: (a) firm transportation capacity of 25,560 Dt per day for the period December through February, 24,338 Dt per day for the months of November, March and April, and 15,262 Dt per day for the period May through October, with various expiration dates ranging from 2004 to 2017; (b) firm storage capacity under Eastern Shore's Rate Schedule GSS providing a peak day entitlement of 2,655 Dt and a total capacity of 131,370 Dt, which expires in 2013; (c) firm storage capacity under Eastern Shore's Rate Schedule LSS providing a peak day entitlement of 580 Dt and a total capacity of 29,000 Dt, which expires in 2013; and (d) firm storage capacity under Eastern Shore's Rate Schedule LGA providing a peak day entitlement of 911 Dt and a total capacity of 5,708 Dt, which expires in 2006. Delaware's firm transportation contracts with Eastern Shore also include Eastern Shore's provision of swing transportation service. This service includes: (a) firm transportation capacity of 1,846 Dt per day on Transco's pipeline system, retained by Eastern Shore, in addition to Delaware's Transco capacity referenced earlier and (b) an interruptible storage service under Transco's Rate Schedule ESS that supports a swing supply service provided under Transco's Rate Schedule FS.
Delaware currently has contracts for the purchase of firm natural gas supply with four (4) suppliers. These contracts provide the availability of a maximum firm daily entitlement of 12,200 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore under Delaware's transportation contracts. The gas purchase contracts have various expiration dates.
Maryland. Maryland's contracts with Transco include: (a) firm transportation capacity of 4,738 Dt per day, which expires in 2005; (b) firm transportation capacity of 155 Dt per day for December through February, expiring in 2006; and (c) firm storage service providing a total capacity of 33,120 Dt. Maryland and Transco are currently engaged in negotiations with regard to an extension of the term of the firm storage service. Although the original contract expired in 1998, Transco and Maryland have continued under the previous terms and conditions until an agreement is finalized.
Maryland's contracts with Columbia include: (a) firm transportation capacity of 442 Dt per day, which expires in 2004; (b) firm transportation capacity of 908 Dt per day, which expires in 2017; (c) firm transportation capacity of 350 Dt per day, which expires in 2018; (d) firm storage service providing a peak day entitlement of 3,142 Dt and a total capacity of 154,756 Dt, which expires in 2004; and (e) firm storage service providing a peak day entitlement of 521 Dt and a total capacity of 46,881 Dt, which expires in 2017. Maryland's contracts with Columbia for storage related transportation provide quantities that are equivalent to the peak day entitlement for the period October through March and are equivalent to fifty percent (50%) of the peak day entitlement for the period April through September. The terms of the storage related transportation contracts mirror the storage services that they support.
Maryland's contract with Gulf, which expires in 2004, provides firm transportation capacity of 590 Dt per day for the period November through March and 543 Dt per day for the period April through October.
Maryland's contracts with Eastern Shore include: (a) firm transportation capacity of 13,378 Dt per day for the period December through February, 12,654 Dt per day for the months of November, March and April, and 8,093 Dt per day for the period May through October; (b) firm storage capacity under Eastern Shore's Rate Schedule GSS providing a peak day entitlement of 1,428 Dt and a total capacity of 70,665 Dt, which expires in 2013; (c) firm storage capacity under Eastern Shore's Rate Schedule LSS providing a peak day entitlement of 309 Dt and a total capacity of 15,500 Dt, which expires in 2013; and (d) firm storage capacity under Eastern Shore's Rate Schedule LGA providing a peak day entitlement of 569 Dt and a total capacity of 3,560 Dt, which expires in 2006. Maryland's firm transportation contracts with Eastern Shore also include Eastern Shore's provision of swing transportation service. This service includes: (a) firm transportation capacity of 969 Dt per day on Transco's pipeline system, retained by Eastern Shore, in addition to Maryland's Transco capacity referenced earlier and (b) an interruptible storage service under Transco's Rate Schedule ESS that supports a swing supply service provided under Transco's Rate Schedule FS.
Maryland currently has contracts for the purchase of firm natural gas supply with four (4) suppliers. These contracts provide the availability of a maximum firm daily entitlement of 7,239 Dt and the supplies are transported by Transco, Columbia, Gulf and Eastern Shore under Maryland's transportation contracts. The gas purchase contracts have various expiration dates.
Florida. The Florida division receives transportation service from Florida Gas Transmission Company ("FGT"), a major interstate pipeline. Chesapeake has contracts with FGT for: (a) daily firm transportation capacity of 21,123 Dt in May through September, 27,105 Dt in October, and 27,519 Dt in November through April under FGT's firm transportation service (FTS-1) rate schedule; (b) daily firm transportation capacity of 5,100 Dt in May through October, and 8,100 Dt in November through April under FGT's firm transportation service (FTS-2) rate schedule; and (c) daily interruptible transportation capacity of 20,000 Dt under FGT's interruptible transportation services (ITS-1) rate schedule. The firm transportation contract (FTS-1) expires on August 1, 2000 with the Company retaining a unilateral right to extend the term for an additional ten years. After the expiration of the primary or secondary term, Chesapeake has the right to first refuse to match the terms of any competing bids for the capacity. The firm transportation contract (FTS-2) expires on March 1, 2015. The interruptible transportation contract is effective until August 1, 2010 and month to month thereafter unless canceled by either party with thirty days notice.
The Florida division currently receives its gas supply from various suppliers. If needed, some supply is bought on the spot market; however, the majority is bought under the terms of two firm supply contacts with Dynergy Marketing and Trade and Duke Energy. Availability of gas supply to the Florida division is also expected to be adequate under existing arrangements.
Competition
Competition with Alternative Fuels. Historically, the Company's natural gas
distribution divisions have successfully competed with other forms of
energy such as electricity, oil and propane. The principal consideration in
the competition between the Company and suppliers of other sources of
energy is price and, to a lesser extent, accessibility. All of the
Company's divisions have the capability of adjusting their interruptible
rates to compete with alternative fuels.
The divisions have several large volume industrial customers that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers convert to oil to satisfy their fuel requirements. Lower levels in interruptible sales occur when oil prices remain depressed relative to the price of natural gas. However, oil prices as well as the prices of other fuels are subject to change at any time for a variety of reasons; therefore, there is always uncertainty in the continuing competition among natural gas and other fuels. In order to address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales side of its business to maximize sales volumes.
To a lesser extent than price, availability of equipment and operational efficiency are also factors in competition among fuels, primarily in residential and commercial settings. Heating, water heating and other domestic or commercial equipment is generally designed for a particular energy source, and especially with respect to heating equipment, the cost of conversion is a disincentive for individuals and businesses to change their energy source.
Competition within the Natural Gas Industry. FERC Order 636 enables all natural gas suppliers to compete for customers on an equal footing. Under this open access environment, interstate pipeline companies have unbundled the traditional components of their service such as gas gathering, transportation and storage from the sale of the commodity. If they choose to be a merchant of gas, they must form a separate marketing operation independent of their pipeline operations. Hence, gas marketers have developed as a viable option for many companies because they are providing expertise in gas purchasing along with collective purchasing capabilities which, when combined, may reduce end-user cost.
Also resulting from an open access environment, the distribution division can be in competition with the interstate transmission company if the distribution customer is located close to the transmission company's pipeline. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the distribution division. In certain situations the distribution divisions may adjust rates and services for these customers to retain their business.
Rates and Regulation
General. Chesapeake's natural gas distribution divisions are subject to
regulation by the Delaware, Maryland and Florida Public Service Commissions
with respect to various aspects of the Company's business, including the
rates for sales to all of their customers in each jurisdiction. All of
Chesapeake's firm distribution rates are subject to purchased gas
adjustment clauses, which match revenues with gas costs and normally allow
eventual full recovery of gas costs. Adjustments under these clauses
require periodic filings and hearings with the relevant regulatory
authority, but do not require a general rate proceeding. Rates on
interruptible sales by the Florida division are also subject to purchased
gas adjustment clauses.
Management monitors the rate of return in each jurisdiction in order to ensure the timely filing of rate adjustment applications.
Regulatory Proceedings
Maryland. During the month of March 1997, the Maryland Public Service
Commission ("MPSC") approved an order authorizing Chesapeake to implement
new service offerings and rate design for services rendered on and after
April 1, 1997. The approved changes included: (1) class revenue
requirements and restructured sales services which provide for separate
firm commercial and industrial rate schedules for general service, medium
volume, large volume and high load factor customer groups; (2) unbundling
of gas costs from distribution charges; (3) a new gas cost recovery
mechanism, which utilizes a projected period under which the fixed cost
portion of the gas rate will be forecasted on an annual basis and the
commodity cost portion of the gas rate will be estimated quarterly, based
on projected market prices; and (4) a new sharing agreement under which
interruptible margins will continue to be shared, 90% to customers and 10%
to the Company, but distribution costs incurred for incremental load
additions can be recovered with carrying charges utilizing 100% of the
incremental margin if the payback period is within three years.
At the request of the MPSC Staff, consideration of the Company's proposed new transportation services was postponed until Eastern Shore Natural Gas Company's open access filing was settled with the FERC. As mentioned previously, Eastern Shore Natural Gas Company became an open access pipeline on November 1, 1997.
Chesapeake's Maryland division was involved in a roundtable collaborative process with the MPSC Staff, customer representatives, third party suppliers or marketers and the Maryland Office of People's Counsel during the last half of 1997 and the first half of 1998, developing initial transportation services for its commercial and industrial customers. The MPSC issued an order in July 1998 authorizing the Company to implement transportation and balancing services effective October 1, 1998 for commercial and industrial customers with annual consumption over 30,000 Ccf per year to transport customer-owned gas on the Company's distribution system.
Delaware. In September 1998, Chesapeake's Delaware division filed an application with the Delaware Public Service Commission ("DPSC") to propose certain rate design changes to its existing margin sharing mechanism which was approved in the Company's 1997 rate restructuring. Chesapeake filed this application as an alternative to a base rate proceeding in order to provide the Company an opportunity to earn its allowed rate of return, without increasing the price of its natural gas services from the Company's last rate case in 1995.
The Company proposed certain rate design changes to its currently existing margin sharing mechanism in order to address the level of recovery of fixed distribution costs from the residential heating service customers and smaller commercial heating customers. Chesapeake proposed to modify the existing margin sharing thresholds to address the actual level of fixed distribution cost recovered from the residential and smaller commercial customers based on the base tariff rates established in PSC Docket No. 95- 73, Phase II. Chesapeake's base tariff rates established in the last rate case were designed to recover a certain amount of fixed distribution costs in order for Chesapeake to earn its authorized rate of return. The proposal increases or decreases the current margin sharing thresholds based on the actual level of recovery of fixed distribution costs from these respective customer classes as compared to the level which the base tariff rates were designed to recover in the last rate case.
The Company also proposed to change the existing margin sharing mechanism to take into consideration the appropriate treatment of margins achieved by the addition of new interruptible customers on the distribution system for which the Company makes capital investments to serve these customers. Currently, Chesapeake is required to include in its margin sharing calculation the margins achieved from all of its interruptible customers. Chesapeake does not have the opportunity to earn a return on its capital investments until base tariff rates are established in the context of a base rate proceeding. The Company proposes to exclude from the margin sharing mechanism the margins achieved from the addition of new interruptible customers in order to provide the Company a reasonable opportunity to earn its authorized rate of return until the Company's next base rate proceeding.
During October 1998, the DPSC suspended the Company's tariff filing, pending the completion of full evidentiary hearing(s) and a final decision by the DPSC during 1999. During February 1999, the scheduled evidentiary hearing was convened to introduce the Company's testimony and exhibits, as well as DPSC Staff's testimony, into the record of evidence. The parties deferred any cross-examination in this docket until March 1999 when the hearing will reconvene. At this time, the Company and the respective parties are engaged in discussions in an effort to reach a settlement on the issues beneficial to all parties prior to the next scheduled hearing. If a settlement cannot be reached among the parties in this docket, then the hearing will reconvene in March 1999 and the issues will be determined based on a formal commission proceeding. The DPSC most likely would issue a final order in this docket during May or June 1999.
In February 1997, the DPSC approved an order authorizing Chesapeake to implement new service offerings and rate design for services rendered on and after March 1, 1997. The approved changes included: (1) restructured sales services which provided commercial and industrial customers with various service classifications such as general service, medium volume, large volume, and high load factor services; (2) a modified purchased gas cost recovery mechanism which takes into consideration the unbundling of gas costs from distribution charges as well as charging certain firm service classifications different gas cost rates based on the service classification's load factor; (3) the implementation of a mechanism for sharing interruptible, capacity release and off-system sales margins between firm sales customers and the Company, with changing margin sharing percentages based on the level of total margin achieved; and (4) a provision for transportation and balancing services for commercial and industrial customers with annual consumption over 30,000 Ccf per year to transport customer-owned gas on the Company's distribution system. The Company's Delaware division implemented these initial transportation and balancing services on December 1, 1997 as a result of its pipeline supplier, Eastern Shore Natural Gas Company, becoming an open access pipeline on November 1, 1997.
Florida. On August 7, 1998, the Florida Division filed an administrative request for approval to revise its tariff sheets to include Citrus County, Florida in its service territory. On August 19, 1998, we received notification that the tariff sheets had been approved by the PSC Staff. The Company has executed service agreements with several customers in the area and is in the process of securing franchise agreements with the cities of Crystal River and Inverness. The Company's approved tariff sheets became effective on September 10, 1998.
On July 15, 1998, the Florida Division filed a petition seeking the authority to implement a flexible gas service tariff. This tariff is designed to meet the Company's need to compete for potential customers who have other viable energy options and to increase load by working with customers with regard to specific terms and conditions of service. Approval of this tariff would enable the Company to provide potential and existing customers with flexible pricing and contract terms which would be precluded under our existing tariff. On October 6, 1998, the Commission voted to approve our Flexible Gas Service tariff. The tariff became effective upon approval and is now available for use in negotiations with customers at the sole option of the Company.
On May 7, 1998, the Company filed for approval of two transportation agreements with Quincy Farms and Fernlea Nurseries. Both customers are located in Gadsden County, Florida. The agreements provide for a transportation rate equal to the non-fuel rate in existence prior to the rate restructuring for the first two years of each contract. The majority of our negotiations with these two customers took place prior to the rate restructuring proceeding. The Company also requested modification of its tariff sheets to include Gadsden County in its service territory. PSC Staff issued its recommendation supporting the petition on June 18, 1998. The Commission voted to approve the contracts and tariff sheet revisions on June 30, 1998.
On November 26, 1997, the Florida Division filed a request with the Florida Public Service Commission (FPSC) in Docket No. 971559-GU, for a Limited Proceeding to Restructure Rates and for Approval of Gas Transportation Agreements. The Florida Division has entered into Gas Transportation Contracts with its two largest customers which resulted in retaining these two customers on the Company's distribution system at rates lower than previously achieved. As a result of this reduction in non-fuel revenue, the Company has proposed in its application to restructure rates for its remaining customers to more closely reflect the cost of service for each rate class and to recover the level of revenues previously generated by the two Contract customers.
The Company's restructuring proposal is revenue neutral. Approval of this request would not result in additional revenues to the Company; however, FPSC approval would enable the Company to retain its two largest customers while providing the Company with the opportunity to achieve its FPSC authorized rate of return.
FPSC Staff issued their recommendation in this docket on March 12, 1998. The Commission voted to approve the Company's restructuring proposal on March 24, 1998. A Commission Order on this docket was issued on March 31, 1998.
(i) (c) Propane Distribution and Marketing General Chesapeake's propane distribution group consists of Sharp Energy, Inc. ("Sharp Energy"), a wholly owned subsidiary of Chesapeake, its wholly owned subsidiary, Sharpgas, Inc. ("Sharpgas") and Tri-County Gas Company, Inc. ("Tri-County") a wholly owned subsidiary of Chesapeake. The propane marketing group consists of Xeron, Inc. ("Xeron"), a wholly owned subsidiary of Chesapeake.
On May 30, 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeron markets propane to a number of large independent and petrochemical companies, resellers, and southeastern retail propane companies.
On March 6, 1997, the Company acquired Tri-County, a family-owned and operated propane distribution business located in Salisbury and Pocomoke, Maryland. The combined operations of the Company and Tri-County served approximately 35,000 propane customers on the Delmarva Peninsula and delivered approximately 26 million retail and wholesale gallons of propane during 1998.
The propane distribution business is affected by many factors such as seasonality, the absence of price regulation and competition among local providers. The propane marketing business is affected by wholesale price volatility and the demand and supply of propane at a wholesale level.
Propane is a form of liquefied petroleum gas which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is gaseous at normal pressures, it is easily compressed into liquid form for storage and transportation. Propane is a clean-burning fuel, gaining increased recognition for its environmental superiority, safety, efficiency, transportability and ease of use relative to alternative forms of energy. Propane is sold primarily in suburban and rural areas which are not served by natural gas pipelines. Demand is typically much higher in the winter months and is significantly affected by seasonal variations, particularly the relative severity of winter temperatures, because of its use in residential and commercial heating.
Adequacy of Resources
Sharp Energy and Tri-County purchase propane primarily from suppliers,
including major domestic oil companies and independent producers of gas
liquids and oil. Supplies of propane from these and other sources are
readily available for purchase by the Company. Supply contracts generally
include minimum (not subject to a take-or-pay premiums) and maximum
purchase provisions.
Sharp Energy and Tri-County use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to the Company's bulk storage facilities. From these facilities, propane is delivered in portable cylinders or by "bobtail" trucks, owned and operated by the Companies, to tanks located at the customer's premises.
Xeron has no physical storage facilities or equipment to transport propane; however, they contract for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.
Competition
Sharp Energy and Tri-County compete with several other propane distributors
in their service territories, primarily on the basis of service and price,
emphasizing reliability of service and responsiveness. Competition is
generally local because distributors located in close proximity to
customers incur lower costs of providing service. Propane competes with
electricity as an energy source, because it is typically less expensive
than electricity, based on equivalent BTU value. Since natural gas has
historically been less expensive than propane, propane is generally not
distributed in geographic areas serviced by natural gas pipeline or
distribution systems.
Xeron competes against various marketers that may have significantly great resources and are able to obtain price or volumetric advantages over Xeron.
The Company's propane distribution and marketing activities are not subject to any federal or state pricing regulation. Transport operations are subject to regulations concerning the transportation of hazardous materials promulgated under the Federal Motor Carrier Safety Act, which is administered by the United States Department of Transportation and enforced by the various states in which such operations take place. Propane distribution operations are also subject to state safety regulations relating to "hook-up" and placement of propane tanks.
The Company's propane operations are subject to all operating hazards normally associated with the handling, storage and transportation of combustible liquids, such as the risk of personal injury and property damage caused by fire. The Company carries general liability insurance in the amount of $35,000,000 per occurrence, but there is no assurance that such insurance will be adequate.
(i) (d) Advanced Information Services General Chesapeake's advanced information services segment is comprised of United Systems, Inc. ("USI") and Capital Data Systems, Inc. ("CDS"), both wholly owned subsidiaries of the Company. CDS provided programming support for application software, until the first quarter of 1997, at which time it disposed of substantially all of its assets.
USI is an Atlanta-based company that primarily provides support for users of PROGRESST, a fourth generation computer language and Relational Database Management System. USI offers consulting, training, software development "tools", web development and customer software development for its client base, which includes many large domestic and international corporations.
Competition
The advanced information services businesses face significant competition
from a number of larger competitors having substantially greater resources
available to them than the Company. In addition, changes in the advanced
information services businesses are occurring rapidly, which could
adversely impact the markets for the Company's products and services.
(i) (e) Other Subsidiaries Skipjack, Inc. ("Skipjack") and Chesapeake Investment Company ("Chesapeake Investment"), are wholly owned subsidiaries of Chesapeake Service Company. Skipjack owns and leases two office buildings in Dover, Delaware to affiliates. Chesapeake Investment is a Delaware affiliated investment company.
On March 30, 1998, the Company acquired Sam Shannahan Well Co., based in Salisbury, Maryland, operating as Tolan Water Service ("Tolan"). Tolan was a privately owned company serving 3,000 customers on the Delmarva Peninsula with divisions supporting residential, commercial and industrial water treatment.
On March 6, 1997, in connection with the acquisition of Tri-County, the Company acquired Eastern Shore Real Estate, Inc. ("ESR"), which became a wholly owned subsidiary of Chesapeake Service Company. ESR owns and leases office buildings to affiliates and external companies.
(ii) Seasonal Nature of Business Revenues from the Company's residential and commercial natural gas sales and from its propane distribution activities are affected by seasonal variations, since the majority of these sales are to customers using the fuels for heating purposes. Revenues from these customers are accordingly affected by the mildness or severity of the heating season.
(iii) Capital Budget
A discussion of capital expenditures by business segment is included in
Item 7 under the heading "Management Discussion and Analysis - Liquidity
and Capital Resources".
(iv) Employees Chesapeake has 456 employees, including 165 in natural gas distribution and transmission, 135 in propane distribution, 7 in propane marketing, 81 in advanced information services and 25 in water conditioning. The remaining 43 employees are considered general and administrative and include officers of the Company, treasury, accounting, information technology, human resources and other administrative personnel. The acquisition of Tolan Water Service added 25 employees, while the Xeron acquisition added 7 employees.
Item 2. Properties
(a) General
The Company owns offices and operates facilities in the following locations:
Pocomoke, Salisbury, Cambridge, and Princess Anne, Maryland; Dover, Seaford,
Laurel and Georgetown, Delaware; and Winter Haven, Florida. Chesapeake rents
office space in Dover, Delaware; Plant City, Florida; Chincoteague and Belle
Haven, Virginia; Easton and Pocomoke, Maryland; Detroit, Michigan; Houston,
Texas and Atlanta, Georgia. In general, the properties of the Company are
adequate for the uses for which they are employed. Capacity and utilization of
the Company's facilities can vary significantly due to the seasonal nature of
the natural gas and propane distribution businesses.
(b) Natural Gas Distribution Chesapeake owns over 576 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas, and 474 miles of such mains (and related equipment) in its Central Florida service areas. Chesapeake also owns facilities in Delaware and Maryland for propane-air injection during periods of peak demand. Portions of the properties constituting Chesapeake's distribution system are encumbered pursuant to Chesapeake's First Mortgage Bonds.
(c) Natural Gas Transmission Eastern Shore owns approximately 273 miles of transmission lines extending from Parkesburg, Pennsylvania to Salisbury, Maryland. Eastern Shore also owns three compressor stations located in Delaware City, Delaware; Daleville, Pennsylvania and Bridgeville, Delaware. The Delaware City compressor facility and associated piping are needed to stabilize capacity on Eastern Shore's system as a result of steadily declining inlet pressures at the Hockessin interconnect with Transco. The Daleville station is used to increase Columbia supply pressures to match Transco supply pressures, and to increase Eastern Shore's pressures in order to serve Eastern Shore's firm customers' demands, including those of Chesapeake's Delaware and Maryland divisions. The Bridgeville station is being used to provide increased pressures required to meet demands on the system.
(d) Propane Distribution and Marketing Sharpgas and Tri-County own bulk propane storage facilities with an aggregate capacity of approximately 1.9 million gallons at 32 plant facilities in Delaware, Maryland and Virginia, located on real estate they either own or lease. Xeron has no physical storage facilities or equipment to transport propane.
Item 3. Legal Proceedings
(a) General
The Company and its subsidiaries are involved in certain legal actions and
claims arising in the normal course of business. The Company is also involved
in certain legal and administrative proceedings before various governmental
agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings will not have a material effect on the
consolidated financial position of the Company.
(b) Environmental Dover Gas Light Site In 1984, the State of Delaware notified the Company that a parcel of land it purchased in 1949 from Dover Gas Light Company, a predecessor gas company, contained hazardous substances. The State also asserted that the Company is responsible for any clean-up and prospective environmental monitoring of the site. The Delaware Department of Natural Resources and Environmental Control ("DNREC") investigated the site and surroundings, finding coal tar residue and some ground-water contamination.
In October 1989, the Environmental Protection Agency Region III ("EPA") listed the Dover site on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"). At that time under CERCLA, both the State of Delaware and the Company were named as potentially responsible parties ("PRPs") for clean-up of the site.
The EPA issued the site Record of Decision ("ROD") dated August 16, 1994. The remedial action selected by the EPA in the ROD addressed the ground-water contamination with a combination of hydraulic containment and natural attenuation. Remediation selected for the soil at the site was to meet stringent cleanup standards for the first two feet of soil and less stringent standards for the soil below two feet. The ROD estimated the costs of selected remediation of ground-water and soil at $2.7 million and $3.3 million, respectively.
In May 1995, EPA issued an order to the Company under section 106 of CERCLA (the "Order"), which required the Company to fund or implement the ROD. The Order was also issued to General Public Utilities Corporation, Inc. ("GPU"), which both EPA and the Company believe is liable under CERCLA. Other PRPs such as the State of Delaware were not ordered to perform the ROD. EPA may seek judicial enforcement of its Order, as well as significant financial penalties for failure to comply. Although notifying EPA of objections to the Order, the Company agreed to comply. GPU informed EPA that it did not intend to comply with the Order.
In March 1995, the Company commenced litigation against the State of Delaware for contribution to the remedial costs being incurred to carry out the ROD. In December of 1995, this case was dismissed without prejudice based on a settlement agreement between the parties (the "Settlement"). Under the Settlement, the State agreed to: support the Company's proposal to reduce the soil remedy for the site, described below; contribute $600,000 toward the cost of implementing the ROD and reimburse the EPA for $400,000 in oversight costs. The Settlement is contingent upon a formal settlement agreement between EPA and the State of Delaware. Upon satisfaction of all conditions of the Settlement, the litigation will be dismissed with prejudice.
In June 1996, the Company initiated litigation against GPU for contribution to the remedial costs incurred by Chesapeake in connection with complying with the ROD. At this time, management cannot predict the outcome of the litigation or the amount of proceeds to be received, if any.
In July 1996, the Company began the design phase of the ROD, on-site pre- design and investigation. A pre-design investigation report ("the report") was filed in October 1996 with the EPA. The report, which required EPA approval, provided up to date status on the site, which the EPA used to determine if the remedial design selected in the ROD was still the appropriate remedy.
In the report, the Company proposed a modification to the soil clean-up remedy selected in the ROD to take into account an existing land use restriction banning future development at the site. In April of 1997, the EPA issued a fact sheet stating that the EPA was considering the proposed modification. The fact sheet included an overall cost estimate of $5.7 million for the proposed modified remedy and a new overall cost estimate of $13.2 million for the remedy selected in the ROD. On August 28, 1997, the EPA issued a Proposed Plan to modify, with respect to soil remediation only, the current clean-up plan that would involve the following three elements: (1) excavation and off-site thermal treatment of the contents of the former subsurface gas holders; (2) implementation of soil vaporization extraction; and (3) pavement of the parking lot. The overall estimated clean-up cost of the site under the proposed plan was $4.2 million ($1.5 million for soil remediation and $2.7 million for ground-water remediation) as compared to the ROD cleanup estimate of $6.0 million ($3.3 million for soil remediation and $2.7 million for ground-water remediation). In January 1998, the EPA issued a ROD Amendment, which modified the soil remediation to conform to the proposed plan and included the estimated soil clean-up costs of $4.2 million.
During the fourth quarter of 1998 the Company completed the first element of the soil remediation at the Dover site at a cost of $450,000. Over the next twelve to eighteen months the Company will finalize the remaining two elements of the soil remediation and initiate the ground-water remedial activities.
The Company's independent consultants have prepared preliminary cost estimates of two potentially acceptable alternatives to complete the ground-water remediation activities at the site. The costs range from a low of $390,000 in capital and $37,000 per year of operating costs for 30 years for natural attenuation to a high of $4.0 million in capital and $500,000 per year in operating costs for 30 years for a pump and treat system. A decision by the EPA as to the most appropriate ground-water remediation method is likely in 1999. The capital costs necessary to begin ground-water remediation are expected to be incurred over the next twelve to eighteen months.
The Company cannot predict which ground-water remediation method will be selected by the EPA and accordingly, has accrued $2.1 million at December 31, 1998 for the Dover site, as well as a regulatory asset for an equivalent amount. Of this amount, $1.5 million is for ground-water remediation and $600,000 is for the remaining soil remedition. The $1.5 million represents the low end of the ground-water remedy estimates described above. As of December 31, 1997, the Company had accrued both a liability and a regulatory asset of $4.2 million. The Company is currently engaged in investigations related to additional parties who may be PRPs. Based upon these investigations, the Company will consider suit against other PRPs. The Company expects continued negotiations with PRPs in an attempt to resolve these matters.
Management believes that in addition to the $600,000 expected to be contributed by the State of Delaware under the Settlement, the Company will be equitably entitled to contribution from other responsible parties for a portion of the expenses to be incurred in connection with the remedies selected in the ROD. The Company expects that it will be able to recover actual costs incurred (exclusive of carrying costs), which are not recovered from other responsible parties, through the ratemaking process in accordance with the existing environmental cost recovery rider provisions described below.
As of December 31, 1998, the Company has incurred approximately $6.6 million in costs relating to environmental testing and remedial action studies. In 1990, the Company entered into settlement agreements with a number of insurance companies resulting in proceeds to fund actual environmental costs incurred over a five to seven-year period. In 1995, the Delaware Public Service Commission, authorized recovery of all unrecovered environmental costs incurred by a means of a rider (supplement) to base rates, applicable to all firm service customers. The costs, exclusive of carrying costs, would be recovered through a five-year amortization offset by the deferred tax benefit associated with those environmental costs. The deferred tax benefit equals the projected cash flow savings realized by the Company in connection with a reduced income tax liability due to the possibility of accelerated deduction allowed on certain environmental costs when incurred. Each year a new rider rate is calculated to become effective December 1. The rider rate is based on the amortization of expenditures through September of the filing year plus amortization of expenses from previous years. The advantage of the rider is that it is not necessary to file a rate case every year to recover expenses incurred. As of December 31, 1998, the unamortized balance and amount of environmental costs not included in the rider, effective January 1, 1999 were $2.5 million and $679,000, respectively. With the rider mechanism established, it is management's opinion that these costs and any future cost, net of the deferred income tax benefit, will be recoverable in rates.
Salisbury Town Gas Light Site
In cooperation with the Maryland Department of the Environment ("MDE"), the
Company completed assessment of the Salisbury manufactured gas plant site,
determining that there was localized ground-water contamination. During 1996,
the Company completed construction and began the Air Sparging and Soil-Vapor
Extraction remediation procedures. Chesapeake has been reporting the
remediation and monitoring results to the Maryland Department of the
Environment on an ongoing basis since 1996.
The cost of remediation is estimated at $136,000 per year for operating expenses for five years. Based on these estimated costs, the Company recorded both a liability and a deferred regulatory asset of $600,000 on December 31, 1998, to cover the Company's projected remediation costs for this site. As of December 31, 1998, the Company has incurred approximately $2.5 million for remedial actions and environmental studies and has charged such costs to accumulated depreciation. In January 1990, the Company entered into settlement agreements with a number of insurance companies resulting in proceeds to fund actual environmental costs incurred over a three to five-year period beginning in 1990. The final insurance proceeds were requested and received in 1992. In December 1995, the Maryland Public Service Commission approved recovery of all environmental cost incurred through September 30, 1995 less amounts previously amortized and insurance proceeds. The amount approved for a 10-year amortization was $964,251. Of the $2.5 million in costs reported above, approximately $770,000 has not been recovered through insurance proceeds or received ratemaking treatment. It is management's opinion that these costs incurred and future costs incurred, if any, will be recoverable in rates.
Winter Haven Coal Gas Site
In May 1996, the Company filed an Air Sparging and Soil Vapor Extraction Pilot
Study Work Plan for the Winter Haven site with the Florida Department of
Environmental Protection ("FDEP"). The Work Plan described the Company's
proposal to undertake an Air Sparging and Soil Vapor Extraction ("AS/SVE")
pilot study to evaluate at the site. After discussions with the FDEP, the
Company filed a modified AS/SVE Pilot Study Work Plan, scope of work to
complete the site assessment activities and a report describing a limited
sediment investigation performed recently. The Company is awaiting FDEP's
comments to the modified Work Plan. It is not possible to determine whether
remedial action will be required by FDEP and, if so, the cost of such
remediation.
The Company has spent and received ratemaking treatment of approximately $697,000 on these investigations as of December 31, 1998. The Company has been allowed by the Florida Public Service Commission to continue to accrue for future environmental costs. At December 31, 1998, the Company had $501,000 accrued. It is management's opinion that future costs, if any, will be recoverable in rates.
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 10. Executive Officers of the Registrant
Information pertaining to the Executive Officers of the Company is as follows:
Ralph J. Adkins (age 56) Mr. Adkins is Chairman of the Board of Chesapeake. He has served as Chairman of the Board since August 1997. Previously, Mr. Adkins served as Chairman of the Board and Chief Executive Officer, President and Chief Executive Officer, President and Chief Operating Officer, Executive Vice President, Senior Vice President, Vice President and Treasurer of Chesapeake. Mr. Adkins is Chairman of Chesapeake Service Company, Sharp Energy, Inc., Tri-County Gas Company, Inc., Chesapeake Investment Company, Xeron, Inc., Sam Shannahan Well Co. and Eastern Shore Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He has been a director of Chesapeake since 1989.
John R. Schimkaitis (age 51) Mr. Schimkaitis is President and Chief Executive Officer. He has served in this position since January 1, 1999. Mr. Schimkaitis is also Chief Executive Officer of Chesapeake Service Company, Sharp Energy, Inc., Tri-County Gas Company, Chesapeake Investment Company, Xeron, Inc., Sam Shannahan Well Co. and Eastern Shore Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He previously served as President and Chief Operating Officer, Executive Vice President, Chief Financial Officer, Senior Vice President, Treasurer and Assistant Secretary. From 1983 to 1986, Mr. Schimkaitis was Vice President of Cooper & Rutter, Inc., a consulting firm providing financial services to the utility and cable industries. He was appointed as a director of Chesapeake in February 1996.
Michael P. McMasters (age 40) Mr. McMasters is Vice President, Chief Financial Officer and Treasurer of Chesapeake Utilities Corporation. He has served as Vice President, Chief Financial Officer and Treasurer since December 1996. He previously served as Vice President of Eastern Shore, Director of Accounting and Rates and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company.
Stephen C. Thompson (age 38) Mr. Thompson is Vice President of the Natural Gas Operations, as well as Vice President of Chesapeake Utilities Corporation. He has served as Vice President since May 1997. He has served as President, Vice President, Manager, Director of Gas Supply and Marketing, Superintendent of Eastern Shore and Regional Manager for the Florida distribution Operations.
Philip S. Barefoot (age 51) Mr. Barefoot joined Chesapeake as Division Manager of Florida Operations in July 1988. In May 1994, he was elected Vice President of Chesapeake Utilities Corporation. Prior to joining Chesapeake, he was employed by Peoples Natural Gas Company where he held the positions of Division Sales Manager, Division Manager and Vice President of Florence Operations.
Item 5. Market for the Registrant's Common Stock and Related Security Holder
Matters
(a) Common Stock Price Ranges, Common Stock Dividends and Shareholder
Information:
The Company's Common Stock is listed on the New York Stock Exchange under the
symbol "CPK". The high, low and closing prices of Chesapeake's Common Stock
and dividends declared per share for each calendar quarter during the years
1998 and 1997 were as follows:
Dividends
Declared
Quarter Ended High Low Close Per Share
----------------------------------------------------------------------------
1998
March 31 $20.500 $18.250 $18.375 $0.2500
June 30 18.500 17.125 17.625 0.2500
September 30 18.500 16.500 17.938 0.2500
December 31 18.500 17.000 18.938 0.2500
----------------------------------------------------------------------------
1997
March 31 $18.000 $16.500 $17.375 $0.2425
June 30 17.500 16.000 17.000 0.2425
September 30 18.500 16.250 18.375 0.2425
December 31 21.750 18.375 20.500 0.2425
----------------------------------------------------------------------------
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Indentures to the long-term debt of the Company and its subsidiaries contain a restriction that the Company cannot, until the retirement of its Series I Bonds, pay any dividends after December 31, 1988 which exceed the sum of $2,135,188 plus consolidated net income recognized on or after January 1, 1989. As of December 31, 1998, the amounts available for future dividends permitted by the Series I covenant are $14.7 million.
At December 31, 1998, there were approximately 2,271 shareholders of record.
(b) Issuance of shares:
On May 29, 1998, in conjunction with the acquisition of Xeron, Inc., the Company
issued 475,000 shares of common stock to J. Phillip Keeter, Earnest Allen Jr.
and Patrick E. Armand in reliance on the private placement exemption provided by
Section 4(c) of the Securities Act of 1933 and Regulation D, thereunder.
On March 31, 1998, in conjunction with the acquisition of Sam Shannahan Well
Co., the Company issued 25,000 shares of company stock to Deshield J. Shannahan
and Joyce C. Shannahan in reliance on the private placement exemption provided
by Section 4(c) of the Securities Act of 2933 and Regulation D, thereunder.
Item 6. Selected Financial Data
-----------------------------------------------------------------------------------------------------------------
(dollars in thousands except stock data)
For the Years Ended December 31, 1998 1997 1996 1995 1994 (1)
-----------------------------------------------------------------------------------------------------------------
Operating
Operating revenues $183,569 $222,489 $260,102 $235,285 $ 98,572
Operating income $ 8,441 $ 8,666 $ 10,099 $ 9,962 $ 7,227
Net income $ 5,303 $ 5,868 $ 7,782 $ 7,696 $ 4,460
-----------------------------------------------------------------------------------------------------------------
Balance Sheet
Gross plant $152,991 $144,251 $134,001 $120,746 $110,023
Net plant $104,266 $ 99,879 $ 94,014 $ 85,055 $ 75,313
Total assets $145,234 $145,719 $155,786 $130,998 $108,271
Long-term debt, net $ 37,597 $ 38,226 $ 28,984 $ 31,619 $ 24,329
Common stockholders' equity $ 56,356 $ 53,656 $ 50,699 $ 45,587 $ 37,063
Capital expenditures $ 12,650 $ 13,471 $ 15,399 $ 12,887 $ 10,653
-----------------------------------------------------------------------------------------------------------------
Common Stock
Earnings per share:
Basic $ 1.05 $ 1.18 $ 1.58 $ 1.59 $ 1.23
Diluted $ 1.04 $ 1.17 $ 1.55 $ 1.56 $ 1.20
Average shares outstanding 5,060,328 4,972,086 4,912,136 4,836,430 3,628,056
Cash dividends per share $ 1.00 $ 0.97 $ 0.93 $ 0.90 $ 0.88
Book value per share $ 11.06 $ 10.72 $ 10.26 $ 9.38 $ 10.15
Common equity/Total capitalization 59.98% 58.40% 63.63% 59.05% 60.37%
Return on equity 9.41% 10.94% 15.35% 16.88% 12.03%
-----------------------------------------------------------------------------------------------------------------
Other
Number of employees 456 429 418 415 320
Number of registered shareholders 2,271 2,178 2,213 2,098 1,721
Heating degree days 3,704 4,430 4,717 4,594 4,398
Heating degree days (10-year average) 4,579 4,596 4,586 4,564 4,588
-----------------------------------------------------------------------------------------------------------------
(1) 1994 has not been restated to include the business combinations with Tri-County Gas
Company, Inc., Tolan Water Service or Xeron, Inc.
|
[GRAPH APPEARS HERE]
Growth in Book Value
Compared to Dividend Growth
Book Dividends
Year Value Per Share
---- ----- ---------
1994 $10.15 $0.88
1995 $9.37 $0.90
1996 $10.26 $0.93
1997 $10.72 $0.97
1998 $11.06 $1.00
[GRAPH APPEARS HERE]
Earnings Compared to Heating
Degree Days
Heating
Degree
Year Earnings Days
---- -------- -------
1994 $1.23 4,398
1995 $1.59 4,594
1996 $1.58 4,717
1997 $1.18 4,430
1998 $1.05 3,704
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Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Liquidity and Capital Resources
The capital requirements of Chesapeake Utilities Corporation ("Chesapeake" or
"the Company") reflect the capital-intensive nature of its business and are
attributable principally to the construction program and the retirement of
outstanding debt. The Company relies on cash generated from operations and
short-term borrowing to meet normal working capital requirements and
temporarily finance capital expenditures. During 1998, net cash provided by
operating activities was $11.0 million, cash used by investing activities was
$12.5 million and cash used by financing activities was $737,000.
The Board of Directors has authorized the Company to borrow up to $20.0 million from various banks and trust companies. As of December 31, 1998, Chesapeake had three unsecured bank lines of credit, totaling $28.0 million, for short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. The outstanding balances of short-term borrowing at December 31, 1998 and 1997 were $11.6 million and $7.6 million, respectively.
In 1998, Chesapeake used cash provided by operations and short-term borrowing to fund capital expenditures. During 1997, the Company used cash provided by operations and the issuance of long-term debt to fund capital expenditures and reduce short-term borrowing.
During 1998, 1997 and 1996, capital expenditures were approximately $12.0 million, $12.4 million and $14.0 million, respectively. Chesapeake has budgeted $22.7 million for capital expenditures during 1999. This amount includes $10.5 million and $8.6 million for natural gas distribution and transmission, respectively, $1.8 million for propane distribution and marketing, $336,000 for advanced information services and $1.5 million for general plant. The natural gas distribution expenditures are for expansion and improvement of facilities in existing service territories. Natural gas transmission expenditures are for improvement and expansion of the pipeline system, specifically, the construction of eight miles of pipeline to provide additional firm transportation capacity to two existing customers. The propane expenditures are to support customer growth and the replacement of older equipment. The advanced information services expenditures are for computer hardware, software and related equipment. General expenditures are for building improvements, computer software and hardware. Financing for the 1999 construction program is expected to be provided from short-term borrowing and cash from operations. The construction program is subject to continuous review and modification. Actual construction expenditures may vary from the above estimates due to a number of factors including acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation and new growth opportunities.
Chesapeake has budgeted $2.2 million for environmental related expenditures during 1999 and expects to incur additional expenditures in future years, a portion of which may need to be financed through external sources (see Note L to the Consolidated Financial Statements). Management does not expect such financing to have a material adverse effect on the financial position or capital resources of the Company.
Capital Structure
As of December 31, 1998, common equity represented 60.0% of permanent
capitalization, compared to 58.4% in 1997 and 63.6% in 1996. Chesapeake
remains committed to maintaining a sound capital structure and strong credit
ratings to provide the financial flexibility needed to access the capital
markets when required. This commitment, along with adequate and timely rate
relief for the Company's regulated operations, helps to ensure that Chesapeake
will be able to attract capital from outside sources at a reasonable cost. The
achievement of these objectives will provide benefits to customers and
creditors, as well as to the Company's investors.
Financing Activities
On March 31, 1998, Chesapeake acquired Sam Shannahan Well Co., Inc., operating
as Tolan Water Service ("Tolan" or "Tolan Water") in exchange for 25,000
shares of Chesapeake's common stock. Tolan provides water conditioning
services to approximately 3,000 residential, commercial and industrial
customers on the Delmarva Peninsula.
All of the outstanding common stock of Xeron, Inc. ("Xeron") was acquired by Chesapeake on May 29, 1998. Xeron markets propane to a number of large independent oil and petrochemical companies, resellers, and southeastern retail propane companies. Four hundred seventy-five thousand shares of the Company's common stock were exchanged in the transaction.
On March 6, 1997, the Company acquired all of the outstanding common stock of Tri-County Gas Company, Inc. ("Tri-County") and associated properties. Tri- County distributes propane to both retail and wholesale customers on the Delmarva Peninsula. The transaction was effected through the exchange of 639,000 shares of the Company's common stock.
Each of these business combinations was accounted for as a pooling of interests.
During 1998, Chesapeake repaid approximately $1.1 million of long-term debt.
In December 1997, Chesapeake finalized a private placement of $10 million of
6.85% Senior Notes due January 1, 2012. Debt repayments during 1997 totaled
$3.1 million. In 1996, Chesapeake repaid $881,000 in long-term debt.
Chesapeake issued 32,925, 32,169 and 33,926 shares of common stock in connection with its Automatic Dividend Reinvestment and Stock Purchase Plan during the years of 1998, 1997 and 1996, respectively.
Results of Operations
Net income for 1998 was $5.3 million as compared to $5.9 million for 1997 and
$7.8 million for 1996. The decrease in net income is primarily related to
warmer temperatures in the Company's northern service territory, partially
offset by a one-time reduction in pension costs of $1.2 million resulting from
Chesapeake's 1998 restructuring of the Company's retirement benefits plans.
Temperatures in 1998, based upon heating degree days, were 19% warmer than
normal, 16% warmer than 1997 and 21% warmer than 1996. Temperatures in 1997
were approximately 6% warmer than those experienced in 1996. Normal weather
conditions are calculated from the most recent ten years of temperature data
measured in heating degree days. The warmer weather resulted in a reduction in
volumes sold by both the natural gas distribution and propane segments. The
lower volumes contributed to the reduction in Earnings Before Interest and
Taxes ("EBIT") for both segments as shown in the table below.
EARNINGS BEFORE INTEREST AND TAXES (in thousands):
------------------------------------------------------------------------------------------------
Increase Increase
For the Years Ended December 31, 1998 1997 (decrease) 1997 1996 (decrease)
------------------------------------------------------------------------------------------------
EBIT by Business Segment:
Natural gas distribution $ 4,697 $ 5,498 $ (801) $ 5,498 $ 7,167 $(1,669)
Natural gas transmission 4,117 3,721 396 3,721 2,458 1,263
Propane distribution and marketing 971 1,158 (187) 1,158 2,669 (1,511)
Advanced information services 1,316 1,046 270 1,046 1,056 (10)
Other 522 671 (149) 671 633 38
------------------------------------------------------------------------------------------------
Total EBIT $11,623 $12,094 $ (471) $12,094 $13,983 $(1,889)
================================================================================================
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Natural Gas Distribution
The $801,000 reduction in EBIT from 1997 to 1998 was primarily the result of a
reduction in gross margin, as indicated in the following table. Exclusive of
the expense reductions related to the restructuring of the Company's
retirement benefits plans, the decrease in EBIT of $1.5 million or 27% was
attributable to warmer than normal weather conditions. The reduction in gross
margin of $832,000 from the prior year is primarily due to the negative impact
of warmer temperatures on volumes sold, partially offset by customer growth
during the year. After taking into account customer growth of 4% for
residential and commercial customers in the northern service territory,
overall volumes declined by 12% for these customer classifications. Under
normal temperatures and customer usage, the 4% customer growth is estimated to
generate an additional margin of $550,000 annually within this segment. Also
contributing to the decline in margin is an 11% reduction in volumes sold and
transported to industrial customers in the Florida service territory. Although
operating expenses remained relatively unchanged, specific expense categories
such as marketing, building rent, legal costs and depreciation and
amortization increased. These were offset by decreases in pension expense,
administrative fees associated with the pension plan, compensation and outside
services.
The reduction in EBIT of $1.7 million from 1996 to 1997 is primarily related to a decline in total gross margin, as indicated in the following table, coupled with an overall increase in expenses. The reduction in gross margin is primarily the result of a 4% decline in volumes sold to residential and commercial customers and a 5% decrease in volumes sold and transported to industrial customers in Chesapeake's Florida service territory. The reduction in volumes sold to residential and commercial customers was directly related to warmer temperatures, primarily during the first quarter of 1997. Operating expenses increased $996,000 due to increases in compensation, regulatory commission expenses, and costs related to data processing and billable service revenue. In addition, there was a greater level of maintenance to the gas pipeline system and increased depreciation and amortization due to additional plant being placed in service.
NATURAL GAS DISTRIBUTION GROSS MARGIN SUMMARY (in thousands)
-----------------------------------------------------------------------------------------------
Increase Increase
For the Years Ended December 31, 1998 1997 (decrease) 1997 1996 (decrease)
-----------------------------------------------------------------------------------------------
Revenues:
Gas sold $50,466 $54,205 $ (3,739) $54,205 $52,290 $ 1,915
Gas transported 2,875 3,061 (186) 3,061 2,991 70
Gas marketed 11,683 18,419 (6,736) 18,419 19,382 (963)
Other 401 275 126 275 193 82
-----------------------------------------------------------------------------------------------
Total Revenues $65,425 $75,960 $(10,535) $75,960 $74,856 $ 1,104
===============================================================================================
Cost of Sales: *
Gas sold $32,529 $35,507 $ (2,978) $35,507 $32,846 $ 2,661
Gas marketed 11,508 18,233 (6,725) 18,233 19,117 (884)
-----------------------------------------------------------------------------------------------
Total Cost of Sales $44,037 $53,740 $ (9,703) $53,740 $51,963 $ 1,777
===============================================================================================
Gross Margin:
Gas sold $17,937 $18,698 $ (761) $18,698 $19,444 $ (746)
Gas transported 2,875 3,061 (186) 3,061 2,991 70
Gas marketed 175 186 (11) 186 265 (79)
Other 401 275 126 275 193 82
-----------------------------------------------------------------------------------------------
Total Gross Margin $21,388 $22,220 $ (832) $22,220 $22,893 $ (673)
===============================================================================================
* Transportation service does not have an associated cost of sales.
|
Natural Gas Transmission
The Earnings Before Interest and Taxes of the Company's natural gas
transmission segment increased $396,000 from 1997 to 1998. This was the result
of an increase in gross margin of $468,000 offset by an $87,000 increase in
operating expenses. Exclusive of the expense reduction related to the
restructuring of the Company's retirement benefits plans, EBIT increased
$221,000 or 6%. Gross margin increased under a full year of open access
pipeline operations, as well as the full year's effect of both a rate increase
and the implementation of new services which were both effective in 1997.
Operating expenses were higher due to increases in regulatory commission
expenses, legal fees, pipeline system maintenance and depreciation. These
costs were offset by declines in pension costs, compensation and
administrative fees associated with the pension plan.
The transmission segment's EBIT increased $1.3 million from 1996 to 1997. The rise in EBIT was partially attributable to a rate increase and an increase in firm services implemented in 1997, as well as an overall reduction in expenses. Also contributing to the increase in EBIT were additional revenues generated by the increase in transportation services that were effective with the implementation of open access. Operating expenses decreased by $124,000 or 3%, primarily due to reduced compensation, relocation costs, property insurance and pipeline system maintenance. These reductions were offset by higher depreciation expenses generated by capital additions during the year.
Propane Distribution and Marketing
In May 1998, the Company acquired Xeron, Inc., a wholesale marketer of
propane, expanding Chesapeake's propane operations (see Note B to the
Consolidated Financial Statements). The EBIT contribution of the propane
distribution and marketing segment declined by $187,000 from 1997 to 1998 due
to a decrease in gross margin which was partially offset by a decline in
operating expenses. Exclusive of the expense reduction related to the
restructuring of the Company's retirement benefits plans, EBIT decreased
$463,000 or 40%. The propane distribution operation was negatively affected by
the warmer temperatures realized in 1998, resulting in a decline in sales
volumes of 8%, after taking into account a 3% increase in customer growth.
Somewhat offsetting this volume-related decline in margin was an increase of
6% in the margin earned per gallon delivered as compared to the prior year. In
addition, the lack of volatility in the wholesale propane market resulted in a
reduction to propane marketing margins due to fewer gallons being marketed.
Wholesale marketing is a high volume, low margin business. During 1998,
marketing revenues declined by $18.1 million or 18% while margins declined by
$250,000 or 16%. Operating expenses declined primarily due to compensation
linked to Xeron's earnings, pension expense and administrative fees associated
with the pension plan.
The Company estimates that the warm temperatures experienced in 1998 reduced EBIT by $1.9 million when compared to normal temperatures. In addition, margins during 1998 were lower than historical norms, further reducing EBIT by approximately $1.6 million.
The reduction in EBIT of $1.5 million from 1996 to 1997 was primarily due to a reduction in gross margin earned by the distribution operation, partially offset by a reduction in operating expenses. Distribution margins decreased due to a 14% reduction in sales volumes coupled with a 13% lower margin per gallon sold. The decline in sales volumes is directly related to the warmer temperatures which averaged 6% warmer than those experienced in 1996. Furthermore, during the first quarter of 1997, temperatures were 14% warmer than normal. The marketing operation contributed an additional $240,000 to EBIT due to a reduction in compensation expense.
Advanced Information Services
The results of the advanced information services segment consisted primarily
of those of United Systems, Inc. ("USI"). Exclusive of the expense reductions
related to the restructuring of the Company's retirement benefits plans, EBIT
contributed by USI increased 15% or $156,000 from 1997 to 1998. Due to
increased opportunities in areas such as website development, training and
consulting, gross margin increased 38%, or $1.5 million from 1997 to 1998.
Although the EBIT contribution of this segment remained virtually unchanged from 1996 to 1997, USI's gross margin increased by $970,000 or 34%. Operating expenses increased due to the opening of a new office in Detroit, Michigan and the expansion of staff training and marketing efforts to position USI to be able to provide new services and for future growth of current services. Since the rise in operating costs offset most of the growth in gross margin, EBIT remained constant.
Income Taxes
Operating income taxes decreased $245,000 in 1998 due to the reduction in
EBIT. Income taxes also decreased in 1997 due to the reduction in EBIT. This
was partially offset by a one-time expense to establish the deferred income
tax liability in connection with the 1997 acquisition of Tri-County. The 1996
financial statements do not include any income tax expense for the acquisition
due to its subchapter S status during that year.
Other
Non-operating income was $241,000, $545,000 and $688,000 for the years 1998,
1997 and 1996, respectively. The decrease in 1998 is primarily attributable to
one-time pre-tax gains of $452,000 and $300,000 on the sale of fixed assets
included in 1997 and 1996, respectively. Also contributing to the 1998 decline
is a reduction in interest income from $288,000 for 1997 to $188,000 for 1998.
Environmental Matters
The Company continues to work with federal and state environmental agencies to
assess the environmental impact and explore corrective action at several
former gas manufacturing plant sites (see Note L to the Consolidated Financial
Statements). The Company believes that future costs associated with these
sites will be recoverable in rates.
Market Risk
Market risk represents the potential loss arising from adverse changes in
market rates and prices. The Company's long-term debt consists of first
mortgage bonds, senior notes and convertible debentures (see Note G to the
Consolidated Financial Statements for annual maturities of consolidated long-
term debt). All of Chesapeake's long-term debt is fixed rate debt and was not
entered into for trading purposes. The carrying value of the Company's long-
term debt was $38.1 million at December 31, 1998. The fair value was $41.6
million at December 31, 1998, based mainly on current market prices or
discounted cash flows using current rates for similar issues with similar
terms and remaining maturities. The Company is exposed to changes in interest
rates as a result of financing through its issuance of fixed rate long-term
debt. The Company evaluates whether to refinance existing debt or permanently
finance existing short-term borrowing based on the fluctuation in interest
rates.
At December 31, 1998, the wholesale propane marketing operation was a party to natural gas liquids ("NGL") forward contracts, primarily propane contracts, with various third parties. These contracts require that the wholesale propane marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL to the respective party. The wholesale propane marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment of a net amount equal to the difference between the current market price of the futures contract and the original contract price.
The forward and futures contracts are entered into for trading and wholesale marketing purposes. The wholesale propane marketing operation is subject to commodity price risk on their open positions to the extent that NGL market prices deviate from fixed contract settlement amounts. Market risks associated with the trading of futures and forward contracts are monitored daily for compliance with Chesapeake's Risk Management Policy, which includes volumetric limits for open positions. In order to manage exposures to changing market prices, open positions are marked to market and reviewed by oversight officials on a daily basis. Additionally, the Risk Management Committee reviews periodic reports on market and credit risk, approves any exceptions to the Risk Management policy (within the limits established by the Board of Directors) and authorizes the use of any new types of contracts. Listed below is quantitative information on the forward and futures contracts at December 31, 1998. All of the contracts mature during 1999.
----------------------------------------------------------------------
Quantity Estimated Weighted Average
At December 31, 1998 in gallons Market Prices Contract Prices
----------------------------------------------------------------------
Forward Contracts
Sale 20,647,200 $.2125 - $.2550 $0.2569
Purchase 24,263,400 $.2125 - $.2550 $0.2424
Futures Contracts
Sale 4,200,000 $.2125 - $.2550 $0.2194
Purchase 714,000 $.2125 - $.2550 $0.2110
----------------------------------------------------------------------
|
Estimated market prices and weighted average contract prices are in dollars per gallon.
The Year 2000
Chesapeake is dependent upon a variety of information systems to operate
efficiently and effectively. In order to address the impact of the Year 2000
("Year 2000" or "Y2K") on its information systems, Chesapeake is in the
process of evaluating and remediating any deficiencies. The Company's
evaluation of its readiness and the potential impact of the Year 2000 on its
systems have been separated into five components: primary internal
applications, embedded systems, vendors/suppliers, end-user computing systems
and customers.
- Chesapeake's primary internal applications include company maintained software systems for its financial information; natural gas customer information and billing; and propane customer information, billing and delivery. The Company completed testing of these three applications in 1998 and deems them Year 2000 ready.
- Embedded systems include the supervisory control and data acquisition ("SCADA") system for the natural gas transmission segment, telecommunications, metering and other facilities related systems. Chesapeake has currently identified 64 vendors that support the Company's embedded systems. Chesapeake expects to finalize the review for additional vendors and/or embedded systems by the end of the first quarter of 1999. The Company has prioritized these vendors into three potential impact classifications: 15 high impact vendors, supporting items such as the SCADA system; 19 medium impact vendors, supporting systems such as telecommunications; and 30 low impact vendors, supporting items such as copiers and postage meters. The Company has been testing these systems and has contacted all of the vendors currently identified, with 85% responding. Of the vendors contacted, a total of 20 vendors - four high impact, six medium impact and ten low impact vendors - indicated they were Y2K ready. The Company has been either working with vendors to reach a state of readiness with the applicable systems or has changed to vendors or systems that are Y2K ready. The SCADA system, the most critical embedded system, is scheduled to be Y2K ready during the second quarter of 1999. Chesapeake will continue to follow up with vendors that are not Y2K ready and will consider alternate providers as necessary to the extent available.
- Chesapeake has identified 101 vendors/suppliers that supply the Company with products and services that impact various elements of the Company's business. The Company has classified these vendors into three impact classifications: 27 high impact vendors such as suppliers of natural gas or propane; 31 medium impact vendors such as regional communication vendors; and 43 low impact vendors. The Company has requested a Y2K status statement from each of these vendors. The Company has received 72 responses, which indicated that nine medium impact and 13 low impact vendors were Y2K ready. The Company will continue to follow up with vendors that are not Y2K ready and will consider alternate providers as necessary to the extent available.
- End-user computing systems are upgraded periodically through the Company's ongoing replacement program. Almost all of the Company's personal computers are currently Year 2000 ready. Additional personal computers will be replaced during the first quarter of 1999. Chesapeake's local area network is Year 2000 ready as is all PC-based and network-based software.
- Customers, primarily industrial interruptible natural gas customers, must ensure that their plant controls are Year 2000 ready for their alternative fuel. The Company has identified 107 interruptible customers and will contact each of them by the end of the first quarter of 1999. The Company will take into account the results of the survey in developing the natural gas contingency plan.
The Company believes the most significant potential risks with respect to its internal operations, those over which it has direct control, are its ability to: (1) use electronic devices to control and operate its natural gas delivery systems; (2) maintain continuous operation of its computer systems; (3) render timely bills to its customers; and (4) enforce tariffs and contracts applicable to interruptible customers.
The Company relies on the producers of natural gas and suppliers of interstate transportation capacity to deliver natural gas to the Company's natural gas delivery systems. The Company is also dependent on propane producers, suppliers and railroad facilities to receive propane supply. Chesapeake is also dependent on various suppliers of communication services. Should any of these critical vendors fail, the impact of any such failure could become a significant challenge to the Company's ability to meet the demands of its customers, to operate its delivery systems and to communicate with its customers. It could also have a material adverse financial impact, including but not limited to, lost sales revenues, increased operating costs and claims from customers related to business interruptions. The Company's Year 2000 evaluation process is addressing each of these risks and the required remediation. The Company is developing its contingency plan for the Year 2000, which will address various alternatives and will include assessing a variety of scenarios that could emerge and require the Company to react. Chesapeake expects to have its contingency plan finalized by the end of the second quarter of 1999. The contingency plan will continue to be modified as warranted by changing events.
The costs incurred as of December 31, 1998 in addressing Year 2000 issues have
been immaterial. The Company has estimated costs of $270,000 to replace and/or
remediate specific embedded systems. However, until the Company has completed
further analysis of the impact of the Year 2000 issue on its embedded systems,
vendors/suppliers, end-user computing systems, customers and contingency
planning; it is unable to estimate any additional costs it may incur as a
result of its efforts.
Presently, no Year 2000-impacted internal applications or embedded systems
have been identified that cannot be upgraded or modified within acceptable
time frames. The target date for completion of all Year 2000-related
activities remains at mid-1999.
Competition
Historically, the Company's natural gas operations have successfully competed
with other forms of energy such as electricity, oil and propane. The principal
considerations have been price, and to a lesser extent, accessibility. As a
result of Eastern Shore's recent conversion to open access, the Company
expects to be subject to competitive pressures from other sellers of natural
gas. With open access transportation services available on Eastern Shore's
system, third party suppliers will compete with Chesapeake to sell gas to the
local distribution companies and the end-users on Eastern Shore's system.
Eastern Shore has shifted from providing sales service to providing
transportation and contract storage services.
The Company's natural gas distribution operation located in Maryland began to offer transportation services to certain industrial customers during 1998. During 1997, the distribution operation located in Delaware also began offering transportation services. The Company expects to expand the availability of transportation services to additional customers in the future. The Florida distribution operation has been open to certain industrial customers since 1994. The Company established a natural gas brokering and supply operation in Florida to compete for these customers.
Both the propane and advanced information services businesses face significant competition from a number of larger competitors with substantially greater resources available to them than those of the Company. In addition, in the advanced information services business, changes are occurring rapidly which could adversely affect the markets for the Company's services.
Inflation
Inflation affects the cost of labor and other goods and services required for
operation, maintenance and capital improvements. While the impact of inflation
has lessened in recent years, natural gas prices are subject to rapid
fluctuations. These fluctuations are passed on to customers through the gas
cost recovery mechanism in the Company's tariffs. To help cope with the
effects of inflation on its capital investments and returns, the Company seeks
rate relief from regulatory commissions for regulated operations while
monitoring the returns of its unregulated business operations.
Cautionary Statement
We make statements in this report that are considered forward-looking
statements within the meaning of the Private Securities Litigation Reform Act
of 1995. These statements are not matters of historical fact. Sometimes they
contain words such as "believes," "expects," "intends," "plans," "will," or
"may," and other similar words. These statements relate to such topics as
customer growth, increases in revenues or margins, Year 2000 readiness,
regulatory approvals, market risk associated with the Company's new propane
marketing operation, the competitive position of the Company and other
matters. It is important to understand that these forward-looking statements
are not guarantees, but are subject to certain risks and uncertainties and
other important factors that could cause actual results to differ materially
from those in the forward-looking statements. These factors include, among
other things:
- the seasonality and temperature sensitivity of Chesapeake's natural gas and propane businesses (that is, the Company's earnings vary depending on the season and, in the winter months, how cold the weather is);
- consumption patterns of the Company's existing and expected customers in these businesses;
- the wholesale price of propane and market movements in these prices, which affect both the margins in the Company's propane business and the profitability of the propane marketing operation;
- the relative price of alternative energy sources, to which some of Chesapeake's customers have access;
- the effects of competition on both unregulated and regulated businesses;
- the ability of the transmission segment to attract new customers in an open access environment;
- the ability of the Company's new and planned facilities to generate expected revenues;
- the Company's ability to obtain the rate relief requested from utility regulators and the timing of that rate relief; and
- the Company's ability to identify and address Year 2000 issues successfully, in a timely manner and at a reasonable cost, as well as the ability of the Company's vendors, suppliers, and other service providers and customers to successfully address their own Year 2000 issues in a timely manner.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.
Information related to quantitative and qualitative disclosure about market
risk is included in Item 7 under the heading "Management's Discussion and
Analysis - Market Risk".
Item 8. Financial Statements and Supplemental Data
To the Stockholders of Chesapeake Utilities Corporation
In our opinion, the consolidated financial statements listed in the index appearing under item 14(a)(1) of this Form 10-K present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
In addition, in our opinion, the consolidated financial statement schedule listed in the index appearing under item 14(a)(2) of this Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Washington, D.C.
February 12, 1999
CONSOLIDATED STATEMENTS OF INCOME -------------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1998 1997 1996 -------------------------------------------------------------------------------------------------------------------- Operating Revenues $ 183,568,795 $ 222,489,264 $ 260,102,200 Cost of Sales 136,019,813 175,191,090 207,655,979 Gross Margin 47,548,982 47,298,174 52,446,221 -------------------------------------------------------------------------------------------------------------------- Operating Expenses Operations 23,669,514 23,686,774 26,485,013 Maintenance 2,123,456 2,068,114 2,550,197 Depreciation and amortization 6,109,202 5,475,417 5,605,930 Other taxes 4,024,129 3,974,097 3,822,200 Income taxes 3,181,599 3,427,308 3,884,377 -------------------------------------------------------------------------------------------------------------------- Total operating expenses 39,107,900 38,631,710 42,347,717 -------------------------------------------------------------------------------------------------------------------- Operating Income 8,441,082 8,666,464 10,098,504 -------------------------------------------------------------------------------------------------------------------- Other Income Interest income 188,394 288,339 248,632 Other income, net 97,005 533,704 642,238 Income taxes (44,145) (276,888) (202,239) -------------------------------------------------------------------------------------------------------------------- Total other income 241,254 545,155 688,631 -------------------------------------------------------------------------------------------------------------------- Income Before Interest Charges 8,682,336 9,211,619 10,787,135 -------------------------------------------------------------------------------------------------------------------- Interest Charges Interest on long-term debt 2,966,043 2,387,641 2,434,321 Amortization of debt expense 123,335 119,401 120,345 Other 290,372 836,965 450,536 -------------------------------------------------------------------------------------------------------------------- Total interest charges 3,379,750 3,344,007 3,005,202 -------------------------------------------------------------------------------------------------------------------- Net Income $ 5,302,586 $ 5,867,612 $ 7,781,933 =================================================================================================================== Earnings Per Share of Common Stock : Basic $ 1.05 $ 1.18 $ 1.58 Diluted $ 1.04 $ 1.17 $ 1.55 |
Consolidated Statements of Comprehensive Income
--------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
--------------------------------------------------------------------------------------------------------------------
Net Income $ 5,302,586 $ 5,867,612 $ 7,781,933
Unrealized gain on marketable securities,
net of income taxes 566,472 258,274 111,437
--------------------------------------------------------------------------------------------------------------------
Total Comprehensive Income $ 5,869,058 $ 6,125,886 $ 7,893,370
===================================================================================================================
See accompanying notes
|
CONSOLIDATED BALANCE SHEETS Assets --------------------------------------------------------------------------------------------------- At December 31, 1998 1997 --------------------------------------------------------------------------------------------------- Property, Plant and Equipment Natural gas distribution $ 81,844,066 $ 75,564,462 Natural gas transmission 35,388,440 33,856,873 Propane distribution and marketing 27,287,807 27,091,102 Advanced information services 1,087,910 841,757 Other plant 7,382,965 6,896,899 --------------------------------------------------------------------------------------------------- Total property, plant and equipment 152,991,188 144,251,093 Less: Accumulated depreciation and amortization (48,725,412) (44,371,890) --------------------------------------------------------------------------------------------------- Net property, plant and equipment 104,265,776 99,879,203 --------------------------------------------------------------------------------------------------- Investments, at fair market value 4,165,194 2,721,443 --------------------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents 2,598,084 4,829,176 Accounts receivable (less allowance for uncollectibles of $302,513 and $331,775 in 1998 and 1997, respectively) 14,861,255 16,415,922 Materials and supplies, at average cost 1,728,513 1,424,312 Propane inventory, at average cost 1,787,038 2,436,200 Storage gas prepayments 2,152,605 2,926,618 Underrecovered purchased gas costs 1,552,265 1,673,389 Income taxes receivable 344,311 766,178 Deferred income taxes - 247,487 Prepaid expenses 1,596,595 1,107,825 --------------------------------------------------------------------------------------------------- Total current assets 26,620,666 31,827,107 --------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets Environmental regulatory assets 2,700,000 4,865,073 Environmental expenditures 3,418,166 2,372,929 Other deferred charges and intangible assets 4,063,811 4,053,068 --------------------------------------------------------------------------------------------------- Total deferred charges and other assets 10,181,977 11,291,070 --------------------------------------------------------------------------------------------------- Total Assets $145,233,613 $145,718,823 ================================================================================================== See accompanying notes |
CONSOLIDATED BALANCE SHEETS Capitalization and Liabilities --------------------------------------------------------------------------------------------------- At December 31, 1998 1997 --------------------------------------------------------------------------------------------------- Capitalization Stockholders' equity Common stock $ 2,479,019 $ 2,435,142 Additional paid-in capital 24,192,188 22,581,463 Retained earnings 28,892,384 28,533,145 Less: Unearned compensation related to restricted stock awarded (71,041) (190,886) Accumulated other comprehensive income 863,344 296,872 --------------------------------------------------------------------------------------------------- Total stockholders' equity 56,355,894 53,655,736 Long-term debt, net of current portion 37,597,000 38,226,000 --------------------------------------------------------------------------------------------------- Total capitalization 93,952,894 91,881,736 --------------------------------------------------------------------------------------------------- Current Liabilities Current portion of long-term debt 520,000 1,051,241 Short-term borrowings 11,600,000 7,600,010 Accounts payable 11,070,642 16,397,691 Refunds payable to customers 636,153 357,041 Accrued interest 553,444 784,533 Dividends payable 1,273,446 1,092,168 Deferred income taxes 56,100 - Other accrued liabilities 3,754,231 3,829,497 --------------------------------------------------------------------------------------------------- Total current liabilities 29,464,016 31,112,181 --------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 13,260,282 11,490,358 Deferred investment tax credits 766,802 821,617 Environmental liability 2,700,000 4,865,073 Accrued pension costs 1,536,304 2,338,201 Other liabilities 3,553,315 3,209,657 --------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 21,816,703 22,724,906 --------------------------------------------------------------------------------------------------- Commitments and Contingencies (Notes L and M) Total Capitalization and Liabilities $145,233,613 $145,718,823 ================================================================================================== See accompanying notes |
CONSOLIDATED STATEMENTS OF CASH FLOWS
-----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
-----------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income $ 5,302,586 $ 5,867,612 $ 7,781,933
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization 6,864,063 6,168,777 6,248,618
Investment tax credit adjustments (54,815) (54,815) (54,815)
Deferred income taxes, net 1,711,510 1,437,206 1,794,146
Mark-to-market adjustments (242,757) 1,144,966 (1,109,416)
Employee benefits (801,898) (238,826) 471,870
Employee compensation from lapsing of stock restrictions 119,845 173,643 334,745
Other, net (171,616) (286,147) (32,133)
Changes in assets and liabilities:
Accounts receivable, net 1,797,425 10,914,969 (8,597,772)
Other current assets 630,202 1,368,006 (2,766,414)
Other deferred charges 215,119 (623,138) (977,257)
Accounts payable, net (5,327,052) (12,525,992) 12,048,169
Refunds payable to customers 279,112 3,307 (613,206)
Overrecovered (underrecovered) purchased gas costs 121,123 518,781 (2,245,544)
Other current liabilities 584,558 (2,193,548) 1,739,020
-----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 11,027,405 11,674,801 14,021,944
-----------------------------------------------------------------------------------------------------------------------
Investing Activities
Property, plant and equipment expenditures, net (12,021,735) (12,370,932) (14,025,373)
Purchases of investments (500,000) (36,167) (129,406)
-----------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (12,521,735) (12,407,099) (14,154,779)
-----------------------------------------------------------------------------------------------------------------------
Financing Activities
Common stock dividends, net of amounts reinvested of $463,231,
$382,932 and $346,308 in 1998, 1997 and 1996, respectively (4,298,837) (3,846,264) (3,368,545)
Issuance of stock - Dividend Reinvestment Plan optional cash 146,716 167,337 208,813
Issuance of stock - Retirement Savings Plan 466,759 404,297 349,031
Net borrowings (repayments) under line of credit agreements 3,999,990 (5,134,990) 7,334,990
Proceeds from issuance of long-term debt - 9,929,711 -
Repayment of long-term debt (1,051,390) (3,098,455) (881,467)
-----------------------------------------------------------------------------------------------------------------------
Net cash (used) provided by financing activities (736,762) (1,578,364) 3,642,822
-----------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (2,231,092) (2,310,662) 3,509,987
Cash and Cash Equivalents at Beginning of Year 4,829,176 7,139,838 3,629,851
-----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 2,598,084 $ 4,829,176 $ 7,139,838
======================================================================================================================
Supplemental Disclosure of Cash Flow Information
Cash paid for interest $ 3,490,993 $ 3,243,981 $ 2,872,973
Cash paid for income tax $ 2,670,580 $ 3,500,160 $ 2,059,441
See accompanying notes
|
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
-----------------------------------------------------------------------------------------------------------
Common Stock
Balance - beginning of year $ 2,435,142 $ 2,403,978 $ 2,365,562
Dividend Reinvestment Plan 16,240 15,398 16,514
Retirement Savings Plan 12,663 11,305 9,928
Conversion of debentures 3,115 4,461 429
USI restricted stock award agreements - - 10,639
Performance shares 11,859 - -
Exercised stock options - - 906
-----------------------------------------------------------------------------------------------------------
Balance - end of year 2,479,019 2,435,142 2,403,978
-----------------------------------------------------------------------------------------------------------
Additional Paid-in Capital
Balance - beginning of year 22,581,463 21,507,577 20,250,967
Dividend Reinvestment Plan 593,706 529,453 538,607
Retirement Savings Plan 454,096 392,992 328,465
Conversion of debentures 105,736 151,441 14,557
USI restricted stock award agreements - - 344,570
Performance shares 457,187 - -
Exercised stock options - - 30,411
-----------------------------------------------------------------------------------------------------------
Balance - end of year 24,192,188 22,581,463 21,507,577
-----------------------------------------------------------------------------------------------------------
Retained Earnings
Balance - beginning of year 28,533,145 27,113,764 23,458,776
Net income 5,302,586 5,867,612 7,781,933
Cash dividends - Chesapeake (4,943,347) (4,341,964) (3,514,694)
Cash dividends - Pooled companies - (106,267) (612,251)
-----------------------------------------------------------------------------------------------------------
Balance - end of year 28,892,384 28,533,145 27,113,764
-----------------------------------------------------------------------------------------------------------
Unearned Compensation
Balance - beginning of year (190,886) (364,529) (415,107)
Issuance of award - - (284,167)
Amortization of prior years' awards 119,845 173,643 334,745
-----------------------------------------------------------------------------------------------------------
Balance - end of year (71,041) (190,886) (364,529)
-----------------------------------------------------------------------------------------------------------
Accumulated Other Comprehensive Income
Net of income tax expense of approximately
$552,000, $190,000 and $25,000 for the years
1998, 1997 and 1996, respectively 863,344 296,872 38,598
-----------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $56,355,894 $53,655,736 $50,699,388
==========================================================================================================
See accompanying notes
|
CONSOLIDATED STATEMENTS OF INCOME TAXES
-------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
-------------------------------------------------------------------------------------------------------------------
Current Income Tax Expense
Federal $ 1,553,839 $ 2,076,235 $1,940,430
State 307,654 442,563 356,576
Investment tax credit adjustments, net (54,815) (54,815) (54,815)
--------------------------------------------------------------------------------------------------------------------
Total current income tax expense 1,806,678 2,463,983 2,242,191
--------------------------------------------------------------------------------------------------------------------
Deferred Income Tax Expense
Property, plant and equipment 887,175 1,335,802 581,373
Deferred gas costs (111,416) (204,170) 873,904
Pensions and other employee benefits 546,237 (19,508) 107,131
Unbilled revenue (16,198) (104,632) 54,320
Contributions in aid of construction (104,003) (33,028) (6,979)
Environmental expenditures 415,845 249,417 108,578
Other (198,574) 16,332 126,098
--------------------------------------------------------------------------------------------------------------------
Total deferred income tax expense (1) 1,419,066 1,240,213 1,844,425
--------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 3,225,744 $ 3,704,196 $4,086,616
===================================================================================================================
Reconciliation of Effective Income Tax Rates
Federal income tax expense at 34% $ 2,899,632 $ 3,254,412 $4,035,307
State income taxes, net of Federal benefit 363,041 399,213 537,566
Acquisition of subchapter S Corporation (2) - 317,821 (268,211)
Other (36,929) (267,250) (218,046)
--------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 3,225,744 $ 3,704,196 $4,086,616
====================================================================================================================
Effective income tax rate 37.8% 38.7% 34.4%
----------------------------------------------------------------------------------------------------
At December 31, 1998 1997
----------------------------------------------------------------------------------------------------
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment $13,222,141 $12,095,782
Deferred gas costs 546,391 649,681
Environmental costs 1,358,443 855,997
Other 1,077,008 704,991
----------------------------------------------------------------------------------------------------
Total deferred income tax liabilities 16,203,983 14,306,451
----------------------------------------------------------------------------------------------------
Deferred income tax assets:
State operating loss carryforwards 72,041 57,303
Unbilled revenue 984,510 968,311
Pension and other employee benefits 884,286 831,735
Self insurance 625,602 585,995
Other 321,162 620,236
----------------------------------------------------------------------------------------------------
Total deferred income tax assets 2,887,601 3,063,580
----------------------------------------------------------------------------------------------------
Deferred Income Taxes
Per Consolidated Balance Sheet $13,316,382 $11,242,871
===================================================================================================
(1) Includes $156,000, $208,000 and $392,000 of deferred state income taxes
for the years 1998, 1997 and 1996, respectively.
(2) Accounted for as a pooling of interests (see Note B to the Consolidated
Financial Statements).
See accompanying notes
|
A. Summary of Accounting Policies
Nature of Business
Chesapeake Utilities Corporation (the "Company") is engaged in natural gas
distribution to approximately 37,100 customers located in southern Delaware,
Maryland's Eastern Shore and Central Florida. The Company's natural gas
transmission subsidiary operates a pipeline from various points in
Pennsylvania and northern Delaware to the Company's Delaware and Maryland
distribution divisions, as well as other utility and industrial customers in
Delaware and the Eastern Shore of Maryland. The Company's propane distribution
and marketing segment provides distribution service to approximately 35,000
customers in southern Delaware, the Eastern Shore of Maryland and Virginia,
and markets propane to a number of large independent oil and petrochemical
companies, resellers, and propane distribution companies in the southeastern
United States. The advanced information services segment provides consulting,
custom programming, training and development tools for national and
international clients.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and
its wholly owned subsidiaries. Investments in entities in which the Company
owns more than 20 percent but 50 percent or less, are accounted for by the
equity method. All significant intercompany transactions have been eliminated
in consolidation.
System of Accounts
The natural gas distribution divisions of the Company located in Delaware,
Maryland and Florida are subject to regulation by the Delaware, Maryland and
Florida Public Service Commissions with respect to their rates for service,
maintenance of their accounting records and various other matters. Eastern
Shore Natural Gas Company ("Eastern Shore") is an open access pipeline and is
subject to regulation by the Federal Energy Regulatory Commission ("FERC").
The Company's financial statements are prepared on the basis of generally
accepted accounting principles which give appropriate recognition to the
ratemaking and accounting practices and policies of the various commissions.
The propane distribution and marketing and advanced information services
segments are not subject to regulation with respect to rates or maintenance of
accounting records.
Cash and Cash Equivalents
The Company's policy is to invest cash in excess of operating requirements in
overnight income producing accounts. Such amounts are stated at cost, which
approximates market value. Investments with an original maturity of three
months or less are considered cash equivalents.
Property, Plant, Equipment and Depreciation Utility property is stated at original cost while the assets of the propane segment are valued at cost. The costs of repairs and minor replacements are charged to income as incurred and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of utility property, the recorded cost of removal, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of non-utility property, the gain or loss, net of salvage value, is charged to income. The provision for depreciation is computed using the straight-line method at rates which will amortize the unrecovered cost of depreciable property over the estimated useful life. Depreciation and amortization expense for financial statement purposes is provided at an annual rate for each segment. Average rates for 1998 were 5% and 3% for the natural gas distribution and transmission segments, respectively, 5% for propane distribution and marketing, 16% for advanced information services and 6% for general plant.
Environmental Regulatory Assets
Environmental regulatory assets represent amounts related to environmental
liabilities for which cash expenditures have not been made. As expenditures
are incurred, the environmental liability is reduced along with the
environmental regulatory asset. These amounts, awaiting ratemaking treatment,
are recorded to either environmental expenditures as an asset or accumulated
depreciation as cost of removal. Environmental expenditures are amortized
and/or recovered through a rider to base rates in accordance with the
ratemaking treatment granted in each jurisdiction.
Other Deferred Charges and Intangible Assets Other deferred charges include discount, premium and issuance costs associated with long-term debt and rate case expenses. The discount, premium and issuance costs are deferred, then amortized over the original lives of the respective debt issues. Gains and losses on the reacquisition of debt are amortized over the remaining lives of the original issuances. Rate case expenses are deferred, then amortized over periods approved by the applicable regulatory authorities. Intangible assets are associated with the acquisition of non- utility companies, and are amortized on a straight-line basis over a period of five to 40 years. A summary of intangible assets is as follows:
------------------------------------------------- At December 31, 1998 1997 ------------------------------------------------- Gross intangibles $2,776,000 $2,776,000 Accumulated amortization (1,288,000) (1,133,000) ------------------------------------------------- Net unamortized balance $1,488,000 $1,643,000 ================================================= |
Income Taxes and Investment Tax Credit Adjustments The Company files a consolidated federal income tax return. Income tax expense allocated to the Company's subsidiaries is based upon their respective taxable incomes and tax credits.
Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements and tax bases of assets and liabilities, and are measured using current effective income tax rates. The portion of the Company's deferred tax liabilities applicable to utility operations which has not been reflected in current service rates represents income taxes recoverable through future rates. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
The Company had state tax loss carryforwards of $980,000 and $818,000 at December 31, 1998 and 1997, respectively. The Company expects to use all of the loss carryforwards; therefore, no valuation allowance was recorded at December 31, 1998 or 1997. The loss carryforwards expire in 2006 through 2013.
Financial Instruments
Xeron, the Company's wholesale propane marketing operation, engages in trading
activities using forward and futures contracts which have been accounted for
using the mark-to-market method of accounting. Under mark-to-market
accounting, the Company's trading contracts are recorded at fair value, net of
future servicing costs. Changes in market price are recognized as gains or
losses in the period of change. The resulting unrealized gains and losses are
recorded as assets or liabilities.
Operating Revenues
Revenues for the natural gas distribution divisions of the Company are based
on rates approved by the various public service commissions. Customers' base
rates may not be changed without formal approval by these commissions. With
the exception of the Company's Florida division, the Company recognizes
revenues from meters read on a monthly cycle basis. This practice results in
unbilled and unrecorded revenue from the cycle date through month-end. The
Florida division recognizes revenues based on services rendered and records an
amount for gas delivered but not billed.
Chesapeake's natural gas distribution divisions each have a gas cost recovery mechanism that provides for the adjustment of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.
The Company charges flexible rates to the natural gas distribution segment's industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative types of supply. Neither the Company nor the customer is contractually obligated to deliver or receive natural gas.
The natural gas transmission segment became an open access pipeline on November 1, 1997 with revenues based on rates approved by FERC. Before open access, only portions of revenues were based on rates approved by FERC.
The propane distribution operation records revenues on either an "as delivered" or on a "metered" basis depending on the customer type. The wholesale propane marketing operation calculates revenues daily on a mark-to- market basis for open contracts.
Earnings Per Share
The calculations of both basic and diluted earnings per share are presented
below.
-------------------------------------------------------------------------------- For the Years Ended December 31, 1998 1997 1996 -------------------------------------------------------------------------------- Calculation of Basic Earnings Per Share: Net Income $5,302,586 $5,867,612 $7,781,933 Weighted Average Shares Outstanding 5,060,328 4,972,089 4,912,136 -------------------------------------------------------------------------------- Basic Earnings Per Share $ 1.05 $ 1.18 $ 1.58 ================================================================================ Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income - basic $5,302,586 $5,867,612 $7,781,933 Effect of 8.25% Convertible debentures 196,333 204,070 207,825 -------------------------------------------------------------------------------- Adjusted numerator - diluted $5,498,919 $6,071,682 $7,989,758 -------------------------------------------------------------------------------- Reconcilation of Denominator: Weighted Shares Outstanding - basic 5,060,328 4,972,089 4,912,136 Effect of 8.25% Convertible debentures 226,203 238,353 242,742 -------------------------------------------------------------------------------- Adjusted denominator - diluted 5,286,531 5,210,442 5,154,878 -------------------------------------------------------------------------------- Diluted Earnings per Share $ 1.04 $ 1.17 $ 1.55 ================================================================================ |
Certain Risks and Uncertainties
The financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates in measuring
assets and liabilities and related revenue and expenses (see Note L to the
Consolidated Financial Statements for significant estimates). These estimates
involve judgements with respect to, among other things, various future
economic factors that are difficult to predict and are beyond the control of
the Company; therefore, actual results could differ from those estimates.
The Company records certain assets and liabilities in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71. If the Company were required to terminate application of SFAS No. 71 for regulated operations, all such deferred amounts would be recognized in the income statement at that time, resulting in a charge to earnings, net of applicable income taxes.
FASB Statements and Other Authoritative Pronouncements Issued Derivative Instruments and Hedging Activities In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, establishing accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement does not allow retroactive application to financial statements for prior periods. Chesapeake will adopt the requirements of this standard in the first quarter of 2000, as required. The Company believes that adoption of this statement will not have a material impact on the Company's financial position or results of operations.
The Emerging Issues Task Force released Issue 98-10, "Accounting for Energy Trading and Risk Management Activities." The Company records its use of derivatives in accordance with the standard by marking open positions to market value. The adoption of the pronouncement is not expected to have a material impact on the financial position or results of operations of the Company.
Restatement and Reclassification of Prior Years' Amounts Certain prior years' amounts have been reclassified to conform to current year presentation. Additionally, prior year amounts have been restated to reflect acquisitions accounted for as poolings of interests.
B. Business Combinations
In May 1998, Chesapeake acquired all of the outstanding common stock of Xeron,
Inc, based in Houston, Texas for 475,000 shares of Chesapeake common stock.
Xeron markets propane to a number of large independent oil and petrochemical
companies, resellers, and southeastern retail propane companies. The
transaction was accounted for as a pooling of interests.
In March 1998, the Company acquired Sam Shannahan Well Co., Inc., operating as Tolan Water Service in exchange for 25,000 shares of Chesapeake's common stock. Tolan provides water conditioning services to approximately 3,000 residential, commercial and industrial customers on the Delmarva Peninsula. This transaction was also accounted for as a pooling of interests.
The results of operations for the separate companies and the combined amounts are presented in the consolidated financial statements as follows.
------------------------------------------------------------------------------
Five months ended Year Ended Year Ended
May 31, 1998 * December 31, 1997 December 31, 1996
------------------------------------------------------------------------------
Operating Revenues
Chesapeake $ 54,750,771 $ 122,774,593 $ 130,213,409
Xeron 37,136,067 98,164,932 128,633,042
Tolan 719,523 1,549,739 1,255,749
------------------------------------------------------------------------------
Combined $ 92,606,361 $ 222,489,264 $ 260,102,200
==============================================================================
Net Income
Chesapeake $ 4,385,817 $ 5,682,946 $ 7,604,915
Xeron 21,704 128,910 158,991
Tolan 2,346 55,756 18,027
------------------------------------------------------------------------------
Combined $ 4,409,867 $ 5,867,612 $ 7,781,933
==============================================================================
* Statements for the five months ended May 31, 1998 are unaudited.
|
In March 1997, the Company acquired all of the outstanding common stock of Tri-County Gas Company, Inc. and associated properties. Tri-County's principal business was the distribution of propane to both retail and wholesale customers in southern Delaware, the Eastern Shore of Maryland and Virginia. Six hundred thirty-nine thousand shares of the Company's common stock were exchanged in the transaction, which was accounted for as a pooling of interests.
All prior period consolidated financial statements presented have been restated to include the combined results of operations, financial position and cash flows of each of the business combinations discussed above. All material intercompany transactions have been eliminated in consolidation.
C. Segment Information
Chesapeake uses the management approach to identify operating segments.
Chesapeake organizes its business around differences in products or services
and the operating results of every segment are regularly reviewed by the
Company's chief operating decision maker in order to make decisions about
resources and to assess performance.
The following table presents information about the Company's reportable segments.
-------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1998 1997 1996 -------------------------------------------------------------------------------------------------------------- Operating Revenues, Unaffiliated Customers Natural gas distribution $ 65,384,413 $ 75,940,968 $ 74,904,100 Natural gas transmission 3,199,032 12,164,369 15,188,752 Propane distribution and marketing 102,872,909 125,159,336 161,812,156 Advanced information services 10,330,703 7,636,407 6,903,246 Other 1,781,738 1,588,184 1,293,946 -------------------------------------------------------------------------------------------------------------- Total operating revenues, unaffiliated customers $183,568,795 $222,489,264 $260,102,200 ============================================================================================================== Intersegment Revenues * Natural gas distribution $ 40,494 $ 18,970 $ 12,232 Natural gas transmission 7,269,620 19,282,359 21,543,352 Propane distribution and marketing - 52,230 2,059 Advanced information services - 149,602 326,913 Other 634,032 523,007 332,512 -------------------------------------------------------------------------------------------------------------- Total intersegment revenues $ 7,944,146 $ 20,026,168 $ 22,217,068 =============================================================================================================== Operating Income Before Income Taxes Natural gas distribution $ 4,696,759 $ 5,498,471 $ 7,167,237 Natural gas transmission 4,117,366 3,721,148 2,458,442 Propane distribution and marketing 971,215 1,157,543 2,668,839 Advanced information services 1,316,158 1,045,912 1,056,201 Other 461,174 637,971 478,571 -------------------------------------------------------------------------------------------------------------- Total 11,562,672 12,061,045 13,829,290 Eliminations 60,009 32,727 153,591 -------------------------------------------------------------------------------------------------------------- Total operating income before income taxes $ 11,622,681 $ 12,093,772 $ 13,982,881 ============================================================================================================== Depreciation and Amortization Natural gas distribution $ 3,330,624 $ 3,076,654 $ 2,907,831 Natural gas transmission 1,050,714 892,258 697,834 Propane distribution and marketing 1,334,414 1,214,918 1,720,631 Advanced information services 183,553 122,081 131,877 Other 209,897 169,506 147,757 -------------------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 6,109,202 $ 5,475,417 $ 5,605,930 ============================================================================================================== Capital Expenditures Natural gas distribution $ 8,512,661 $ 6,569,865 $ 6,961,652 Natural gas transmission 1,505,830 2,959,019 5,567,509 Propane distribution and marketing 1,544,992 2,820,166 2,189,368 Advanced information services 246,153 273,351 162,189 Other 840,186 848,680 517,997 -------------------------------------------------------------------------------------------------------------- Total capital expenditures $ 12,649,822 $ 13,471,081 $ 15,398,715 ============================================================================================================== Identifiable Assets, at December 31, Natural gas distribution $ 77,756,422 $ 78,732,860 $ 77,426,232 Natural gas transmission 24,862,165 24,781,292 23,981,989 Propane distribution and marketing 27,526,019 31,831,616 44,073,080 Advanced information services 2,304,609 1,751,192 1,496,419 Other 12,784,398 8,621,863 8,808,724 -------------------------------------------------------------------------------------------------------------- Total identifiable assets $145,233,613 $145,718,823 $155,786,444 ============================================================================================================== * All significant intersegment revenues have been eliminated from consolidated revenues. |
D. Fair Value of Financial Instruments
Various items within the balance sheet are considered to be financial
instruments because they are cash or are to be settled in cash. The carrying
values of these items generally approximate their fair value (see Note E to
the Consolidated Financial Statements for disclosure of fair value of
investments). The fair value of the Company's open forward and futures
contracts at December 31, 1998 and December 31, 1997 based on market rates
were $207,000 and $36,000, respectively. The fair value of the Company's long-
term debt is estimated using a discounted cash flow methodology. The estimated
fair value of the Company's long-term debt at December 31, 1998, including
current maturities, is approximately $41.6 million as compared to a carrying
value of $38.1 million. At December 31, 1997, the estimated fair value was
approximately $40.7 million as compared to a carrying value of $38.8 million.
These estimates are based on published corporate borrowing rates for debt
instruments with similar terms and average maturities.
E. Investments
The investment balance at December 31, 1998 and 1997 consists primarily of a
7.3% ownership interest in the common stock of Florida Public Utilities
Company ("FPU"). The Company has classified its investment in FPU as an
"Available for Sale" security, which requires that all unrealized gains and
losses be excluded from earnings and be reported net of income tax as a
separate component of stockholders' equity. At December 31, 1998 and 1997, the
market value exceeded the aggregate cost basis of the Company's portfolio by
$1,552,000 and $487,000, respectively.
In August 1998, the Company entered into an agreement to sell its investment
in FPU for $16.50 per share to The Southern Company. The execution of the
agreement is contingent on the approval of the Securities and Exchange
Commission, which is expected to be obtained in 1999. Once regulatory approval
is received, the Company will recognize a $1,415,000 pre-tax gain or $863,000,
after taxes.
F. Common Stock and Additional Paid-in Capital The following is a schedule of changes in the Company's shares of common stock.
---------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996 (1)
---------------------------------------------------------------------------------------
Common Stock: Shares issued and outstanding (2)
Balance - beginning of year 5,004,078 4,939,515 4,860,588
Dividend Reinvestment Plan (3) 32,925 32,169 33,926
Sale of stock to Company's Retirement Savings Plan 26,018 23,228 20,398
Conversion of debentures 6,401 9,166 881
Performance shares 24,366 - -
USI restricted stock award agreements - - 21,859
Exercised stock options - - 1,863
---------------------------------------------------------------------------------------
Balance - end of year 5,093,788 5,004,078 4,939,515
=======================================================================================
(1) The 1996 beginning balance has been restated to include 639,000,
25,000 and 475,000 shares of Common Stock that were issued to effect
the business combinations with Tri-County Gas Company, Inc., Tolan
Water Service and Xeron, Inc., respectively.
(2) 12,000,000 shares are authorized at a par value of $.4867 per share.
(3) Includes dividends and reinvested optional cash payments.
|
G. Long-term Debt
The outstanding long-term debt, net of current maturities, is as follows:
--------------------------------------------------------------------------- At December 31, 1998 1997 --------------------------------------------------------------------------- First mortgage sinking fund bonds: 9.37% Series I, due December 15, 2004 $ 3,780,000 $ 4,300,000 8.25% Convertible debentures, due March 1, 2014 3,817,000 3,926,000 Uncollateralized senior notes: 7.97% note, due February 1, 2008 10,000,000 10,000,000 6.91% note, due October 1, 2010 10,000,000 10,000,000 6.85% note, due January 1, 2012 10,000,000 10,000,000 --------------------------------------------------------------------------- Total long-term debt $37,597,000 $38,226,000 =========================================================================== Annual maturities of consolidated long-term debt for the next five years are as follows: $1,520,000 for 1999, $2,665,091 for the years 2000 through 2002 and $3,665,091 for 2003. |
On December 15, 1997, the Company issued $10 million of 6.85% senior notes due January 1, 2012. The Company used the proceeds to repay a portion of the Company's short-term borrowing.
The convertible debentures may be converted, at the option of the holder, into shares of the Company's common stock at a conversion price of $17.01 per share. During 1998, $109,000 of debentures were converted. The debentures are redeemable at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000 in the aggregate. At the Company's option, the debentures may be redeemed at the stated amounts.
Indentures to the long-term debt of the Company and its subsidiaries contain various restrictions. The most stringent restrictions state that the Company must maintain equity of at least 40% of total capitalization, the times interest earned ratio must be at least 2.5 and the Company cannot, until the retirement of its Series I bonds, pay any dividends after December 31, 1988 which exceed the sum of $2,135,188 plus consolidated net income recognized on or after January 1, 1989. As of December 31, 1998, the amounts available for future dividends permitted by the Series I covenant approximated $14.7 million.
A portion of the natural gas distribution plant assets owned by the Company are subject to a lien under the mortgage pursuant to which the Company's first mortgage sinking fund bonds are issued.
H. Short-term Borrowing
The Board of Directors has authorized the Company to borrow up to $20.0
million from various banks and trust companies. As of December 31, 1998, the
Company had three unsecured bank lines of credit totaling $28.0 million, none
of which required compensating balances. Under these lines of credit at
December 31, 1998 and 1997, the Company had short-term debt outstanding of
$11.6 million and $7.6 million, respectively, with a weighted average interest
rate of 5.56% and 5.63%, respectively.
I. Lease Obligations
The Company has entered several operating lease arrangements for office space
at various locations. Rent expense related to these leases was $309,000,
$343,000 and $359,000 for 1998, 1997 and 1996, respectively. Future minimum
payments under the Company's current lease agreements are $309,000, $297,000,
$261,000, $187,000 and $169,000 for the years of 1999 through 2003,
respectively; and $299,000 thereafter.
J. Employee Benefits Plans
Pension Plan
Through December 31, 1998, the Company sponsored a defined benefit pension
plan covering substantially all of its employees (see Enhanced Retirement
Savings Plan). Benefits under the plan are based on each participant's years
of service and highest average compensation. The Company's funding policy
provides that payments to the trustee shall be equal to the minimum funding
requirements of the Employee Retirement Income Security Act of 1974.
In December 1998, the Company restructured the employee benefits plans to be competitive with employers in similar industries. Chesapeake offered current participants of the defined benefit plan the option to remain in the current plan or receive a one-time payout and enroll in an enhanced retirement savings plan. Chesapeake closed the defined benefit plan to new participants, effective December 31, 1998. Based on the election options selected by the employees, the Company reduced their accrued pension liability to $1,283,088. Based on the change in the accrued liability, the Company was able to record a curtailment gain of $1,224,298 in 1998.
The following schedule sets forth the funded status of the pension plan at December 31, 1998 and 1997:
-------------------------------------------------------------------------- At December 31, 1998 1997 -------------------------------------------------------------------------- Change in benefit obligation: Benefit obligation at beginning of year $11,534,355 $10,265,987 Service cost 838,177 680,192 Interest cost 803,727 732,188 Effect of curtailment (1,224,298) - Change in discount rate 952,552 - Actuarial (gain) loss (384,492) 146,559 Benefits paid (332,136) (290,571) -------------------------------------------------------------------------- Benefit obligation at end of year 12,187,885 11,534,355 -------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of year 13,592,699 10,720,514 Actual return on plan assets 1,324,606 2,427,768 Employer contribution - 734,988 Benefits paid (332,136) (290,571) -------------------------------------------------------------------------- Fair value of plan assets at end of year 14,585,169 13,592,699 -------------------------------------------------------------------------- Funded Status 2,397,284 2,058,344 Unrecognized transition obligation (111,371) (126,475) Unrecognized prior service cost (67,152) (71,851) Unrecognized net gain (3,501,849) (4,038,679) -------------------------------------------------------------------------- Accrued pension cost $(1,283,088) $(2,178,661) ========================================================================== Assumptions: Discount rate 6.75% 7.25% Rate of compensation increase 4.75% 4.75% Expected return on plan assets 8.50% 8.50% -------------------------------------------------------------------------- |
Net periodic pension costs for the defined pension benefit plan for 1998, 1997 and 1996 include the following components:
-------------------------------------------------------------------------------- For the Years Ended December 31, 1998 1997 1996 -------------------------------------------------------------------------------- Components of net periodic pension cost: Service cost $ 838,177 $ 680,192 $ 656,985 Interest cost 803,727 732,188 658,238 Expected return on assets (1,149,754) (898,037) (784,924) Amortization of: Transition assets (15,104) (15,104) (15,104) Prior service cost (4,699) (4,699) (4,699) Actuarial gain (143,622) (88,900) (68,425) -------------------------------------------------------------------------------- Net periodic pension cost 328,725 405,640 442,071 Curtailment gain (1,224,298) - - Amounts capitalized as construction costs (31,107) (33,942) (38,860) -------------------------------------------------------------------------------- Total pension cost accruals $ (926,680) $ 371,698 $ 403,211 ================================================================================ |
Retirement Savings Plan
The Company sponsors a Retirement Savings Plan, a 401(k) plan, that provides
participants a mechanism for making contributions for retirement savings. Each
participant may make pre-tax contributions up to 15% of eligible base
compensation subject to IRS limitations. Based on each participant's years of
service, the Company makes a contribution matching 60% or 100% of each
participant's pre-tax contributions, not to exceed 6% of the participant's
eligible compensation for the plan year. The Company's contributions totaled
$495,000, $404,000 and $353,000 for the years ended December 31, 1998, 1997
and 1996, respectively. As of December 31, 1998, there are 30,356 shares
reserved to fund future contributions to the Retirement Savings Plan.
Enhanced Retirement Savings Plan
Effective January 1, 1999, the Company will offer an enhanced 401(k) plan to
all new employees, as well as existing employees that elected to no longer
participate in the defined benefit plan. The Company will make a matching
contribution of each employee's pre-tax contribution of up to 6% of the
eligible compensation for the year. The match will be between 100% and 200%
based on a combination of the employee's age and years of service. The first
100% of the funds will be matched with Chesapeake common stock. The remaining
match will be invested in the Company's 401(k) plan according to each
employee's election options.
Other Post-retirement Benefits
The Company sponsors a defined benefit post-retirement health care and life
insurance plan that covers substantially all natural gas and corporate
employees. The Company had deferred approximately $126,000, which represented
the difference between the Maryland division's SFAS No. 106 expense and its
actual pay-as-you-go cost. The amount is being amortized over five years
starting in 1995. The unamortized balance was $50,000 at December 31, 1998.
Net periodic post-retirement costs for 1998, 1997 and 1996 include the following components:
----------------------------------------------------------------------- For the Years Ended December 31, 1998 1997 1996 ----------------------------------------------------------------------- Components of net periodic post-retirement cost: Service cost $ 3,361 $ 3,287 $ 2,820 Interest cost 59,321 60,221 54,651 Amortization of: Transition obligation 27,859 27,859 27,859 Actuarial loss 6,071 1,554 - ----------------------------------------------------------------------- Net periodic post-retirement cost 96,612 92,921 85,330 Amounts capitalized as construction costs (22,459) (16,274) (16,672) Amounts amortized (deferred) 25,254 25,254 25,254 ----------------------------------------------------------------------- Total post-retirement cost accruals $99,407 $101,901 $93,912 ======================================================================= |
The following schedule sets forth the funded status of the post-retirement health care and life insurance plan:
--------------------------------------------------------------- At December 31, 1998 1997 --------------------------------------------------------------- Change in benefit obligation: Benefit obligation at beginning of year $ 868,899 $ 791,871 Retirees 14,236 53,604 Fully-eligible active employees 674 7,978 Other active 3,251 15,446 --------------------------------------------------------------- Benefit obligation at end of year $ 887,060 $ 868,899 =============================================================== Funded Status $(887,060) $(868,899) Unrecognized transition obligation 217,295 245,154 Unrecognized net loss 165,160 147,422 --------------------------------------------------------------- Accrued post-retirement cost $(504,605) $(476,323) =============================================================== Assumptions: Discount rate 6.75% 7.25% --------------------------------------------------------------- |
The health care inflation rate for 1998 is assumed to be 9.0%. This rate is projected to gradually decrease to an ultimate rate of 5% by the year 2007. A one percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated post-retirement benefit obligation by approximately $105,000 as of January 1, 1999, and would increase the aggregate of the service cost and interest cost components of net periodic post-retirement benefit cost for 1999 by approximately $8,000.
K. Executive Incentive Plans
The Performance Incentive Plan ("the Plan") adopted in 1992, provides for the
granting of stock options to certain officers of the Company over a 10-year
period. The Plan provides participants an option to purchase shares of the
Company's common stock, exercisable in cumulative installments of up to one-
third on each anniversary of the commencement of the award period. The Plan
also enables participants the right to earn performance shares upon the
Company's achievement of certain performance goals as set forth in the
specific agreements associated with particular options and/or performance
shares.
The Company has executed Stock Option Agreements for a three-year performance period ending December 31, 2000 with certain executive officers. One-half of these options become exercisable over time and the other half become exercisable if certain performance targets are achieved. Chesapeake also executed Performance Share Agreements for the same period with certain other executive officers. Each year participants are eligible to earn a maximum number of performance shares equal to one-third of the total number of performance shares granted, based on the Company's achievement of certain performance goals. The Company recorded $49,000 of compensation expense associated with these performance shares in 1998.
In November 1994, the Company executed Tandem Stock Option and Performance Share Agreements ("Agreements") with certain executive officers. During the three-year period ended December 31, 1997, the performance goals set forth in the Agreements were achieved. Following the approval of the Board of Directors on February 27, 1998, the Company issued 44,081 performance shares. At that time, 44,906 stock options expired. The Company recorded $416,000 and $227,000 to recognize the compensation expense associated with these performance shares in 1997 and 1996, respectively.
Changes in outstanding options were as follows:
------------------------------------------------------------------------------------------------------------
1998 1997 1996
Number Option Number Option Number Option
of shares Price of shares Price of shares Price
------------------------------------------------------------------------------------------------------------
Balance - beginning of year 208,543 $12.625 - $20.50 113,051 $12.625 - $12.75 125,186 $12.625 - $12.75
Options granted 95,492 $20.50
Options expired (44,906) $12.625
Options exercised (12,135) $12.75
------------------------------------------------------------------------------------------------------------
Balance - end of year 163,637 $12.75 - $20.50 208,543 $12.625 - $20.50 113,051 $12.625 - $12.75
============================================================================================================
Exercisable 68,145 $12.75 98,083 $12.625 - $12.75 83,114 $12.625 - $12.75
------------------------------------------------------------------------------------------------------------
|
In December 1997, the Company granted stock options to certain executive officers of the Company. As required by SFAS No. 123, the pro forma information as if fair value based accounting had been used to account for the stock-based compensation costs is shown below.
--------------------------------------------------------- For the Years Ended December 31, 1998 1997 --------------------------------------------------------- Pro forma Net Income $5,262,468 $5,864,269 Pro forma Earnings Per Share: Basic $ 1.04 $ 1.18 Diluted $ 1.03 $ 1.16 Assumptions: Dividend yield 4.73% 4.73% Expected volatility 15.53% 15.53% Risk-free interest rate 5.89% 5.89% Expected lives 4 years 4 years --------------------------------------------------------- |
Certain key USI employees entered into restricted stock award agreements under which shares of Chesapeake common stock were issued over a five-year period beginning in 1992 as certain targets were met. Restrictions lapse over a five to ten-year period from the award date. At December 31, 1998 and 1997, respectively, 4,371 and 12,515 shares valued at $71,041 and $190,886 remain restricted.
L. Environmental Commitments and Contingencies The Company is currently participating in the investigation, assessment or remediation of three former gas manufacturing plant sites located in different jurisdictions, including the exploration of corrective action options to remove environmental contaminants. The Company has accrued liabilities for two of these sites, the Dover Gas Light and Salisbury Town Gas Light sites.
With respect to the Dover Gas Light site, the Company and General Public Utilities Corporation, Inc. ("GPU") have been ordered by the Environmental Protection Agency ("EPA") to fund or implement the EPA's Record of Decision ("ROD") on the appropriate remedial activities to be performed, which include both soil and ground-water remedies.
During the fourth quarter of 1998, the Company started the soil remediation process at that site at a cost of $450,000. Over the next twelve to eighteen months, the Company will finalize the soil remediation and initiate the ground-water remedial activities.
The Company's independent consultants have prepared preliminary estimates of the costs of two potentially acceptable alternatives to complete the ground- water remediation activities at the site. The costs to remediate the ground- water range from a low of $390,000 in capital and $37,000 per year of operating costs; to a high of $4.0 million in capital and $500,000 per year in operating costs. In both cases, the operating costs are assumed to last for 30 years. A decision by the EPA as to the most appropriate ground-water remediation method is likely in 1999. The capital costs necessary to begin remediation are expected to be incurred over the next twelve to eighteen months.
Chesapeake cannot predict the ground-water remediation the EPA will select; therefore, the Company has accrued $2.1 million at December 31, 1998 for the Dover site and has recorded a regulatory asset for an equivalent amount. Of this amount, $1.5 million is for ground-water remediation and $600,000 is for the remaining soil remedition. The $1.5 million represents the low end of the ground-water remedy estimates described above.
The Company initiated litigation against one of the other potentially responsible parties for contribution to the remedial costs incurred by Chesapeake in connection with complying with the ROD. At this time, management cannot predict the outcome of the litigation or the amount of proceeds to be received, if any. Management believes that the Company will be equitably entitled to contribution from other responsible parties for a portion of the expenses to be incurred in connection with the remedies selected in the ROD. The Company expects that it will be able to recover actual costs incurred, which are not recovered from other responsible parties, exclusive of associated carrying costs, through the ratemaking process in accordance with environmental cost recovery rider provisions currently in effect.
In cooperation with the Maryland Department of the Environment ("MDE"), in 1996 the Company completed construction and began remediation procedures at the Salisbury site. In addition, the Company began quarterly reporting of the remediation and monitoring results to the MDE. The Company has established a liability with respect to the Salisbury site of $600,000 as of December 31, 1998. This amount is based on the estimated operating costs of the remediation facilities over the next five years. A corresponding regulatory asset has been recorded, reflecting the Company's belief that costs incurred will be recoverable in base rates.
In addition, the Company has a site located in the state of Florida which is currently being evaluated. At this time, no estimate of liability can be made. It is management's opinion that any unrecovered current costs and any other future costs incurred will be recoverable through future rates or sharing arrangements with other responsible parties.
ENVIRONMENTAL COSTS INCURRED
------------------------------------------------------------------------- At December 31, 1998 1997 ------------------------------------------------------------------------- Delaware $6,846,722 $5,317,380 Maryland 2,541,263 2,368,168 Florida 696,847 692,391 ------------------------------------------------------------------------- Total costs incurred 10,084,832 8,377,939 Less: Amounts, net of insurance proceeds, which have been approved for ratemaking treatment (8,391,953) (7,319,496) ------------------------------------------------------------------------- Amounts pending ratemaking recovery $1,692,879 $1,058,443 ========================================================================= |
M. Other Commitments and Contingencies
Natural Gas Supply
The Company's natural gas distribution operations have entered into
contractual commitments for daily entitlements of natural gas from various
suppliers. The contracts have various expiration dates.
Other
The Company is involved in certain legal actions and claims arising in the
normal course of business. The Company is also involved in certain legal and
administrative proceedings before various governmental agencies concerning
rates. In the opinion of management, the ultimate disposition of these
proceedings will not have a material effect on the consolidated financial
position of the Company.
N. Quarterly Financial Data (Unaudited)
In the opinion of the Company, the quarterly financial information shown below
includes all adjustments necessary for a fair presentation of the operations
for such periods. Due to the seasonal nature of the Company's business, there
are substantial variations in operations reported on a quarterly basis.
------------------------------------------------------------------------------- For the Quarters Ended, March 31 June 30 September 30 December 31* ------------------------------------------------------------------------------- 1998 Operating Revenue $60,169,102 $43,594,944 $36,231,924 $43,572,825 Operating Income 4,744,218 962,101 (459,965) 3,194,728 Net Income 4,000,602 263,751 (1,266,498) 2,304,731 Earnings per share: Basic $ 0.80 $ 0.05 $ (0.25) $ 0.45 Diluted $ 0.77 $ 0.05 $ (0.25) $ 0.44 ------------------------------------------------------------------------------- 1997 Operating Revenue $76,302,285 $44,918,820 $41,680,719 $59,587,440 Operating Income 4,148,755 1,392,667 (7,026) 3,132,068 Net Income 3,433,648 707,300 (762,784) 2,489,448 Earnings per share: Basic $ 0.69 $ 0.14 $ (0.15) $ 0.50 Diluted $ 0.67 $ 0.14 $ (0.15) $ 0.49 ------------------------------------------------------------------------------- * Results for the fourth quarter of 1998 reflect a one-time pension plan curtailment gain of approximately $750,000, net of income tax expense. See Note J to the Consolidated Financial Statements. |
OPERATING STATISTICS
---------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996 1995 1994 (1)
---------------------------------------------------------------------------------------------------------------------
Revenues (in thousands)
Natural gas
Residential $ 19,274 $ 21,540 $ 18,256 $ 14,857 $15,228
Commercial 15,243 16,557 14,339 11,383 11,594
Industrial 15,953 22,625 28,546 36,898 32,718
Sale for resale 11,683 23,010 24,481 12,459 9,586
Transportation 6,120 4,212 3,369 2,993 2,639
Other 310 162 1,102 515 (50)
---------------------------------------------------------------------------------------------------------------------
Total natural gas revenues 68,583 88,106 90,093 79,105 71,715
Propane distribution and marketing (2) 102,873 125,159 161,812 147,596 17,789
Other 12,113 9,224 8,197 8,584 6,173
---------------------------------------------------------------------------------------------------------------------
Total revenues $183,569 $222,489 $260,102 $235,285 $95,677
===================================================================================================================
Volumes
Natural gas deliveries (in MMCF)
Residential 1,636 1,753 1,987 1,686 1,665
Commercial 1,907 2,113 2,059 1,792 1,771
Industrial 3,115 5,975 7,553 13,622 10,752
Sale for resale 1,194 1,200 1,065 990 998
Transportation 13,548 12,231 12,138 11,131 7,542
---------------------------------------------------------------------------------------------------------------------
Total natural gas deliveries 21,400 23,272 24,802 29,221 22,728
===================================================================================================================
Propane distribution
(in thousands of gallons) (2) 25,979 26,682 29,975 26,184 18,395
===================================================================================================================
Customers
Natural gas
Residential 32,473 31,277 30,349 29,285 28,260
Commercial 4,416 4,288 4,151 4,030 3,879
Industrial (3) 236 229 210 212 204
Sale for resale (3) 3 3 3 3 3
---------------------------------------------------------------------------------------------------------------------
Total natural gas customers 37,128 35,797 34,713 33,530 32,346
Propane distribution 34,988 33,998 32,218 31,372 22,180
---------------------------------------------------------------------------------------------------------------------
Total customers 72,116 69,795 66,931 64,902 54,526
====================================================================================================================
(1) 1994 has not been restated to include the business combinations with
Tri-County Gas Company, Inc., Tolan Water Service or Xeron, Inc.
(2) 1994 amounts exclude $2,895,000 in revenue and nine million gallons of
propane sold to one large wholesale customer.
(3) Includes transportation customers.
|
[GRAPH APPEARS HERE]
Natural Gas and Propane
Customer Growth
Natural Gas Propane
Year Customers Customers
---- --------- ---------
1994 32,346 22,180
1995 33,530 31,372
1996 34,713 32,218
1997 35,797 33,998
1998 37,152 34,988
[GRAPH APPEARS HERE]
Volumes Compared to Heating
Degree Days
Natural Propane Heating
Gas (in thousands Degree
Year (in MMCF) of gallons) Days
---- ------- ---------- -------
1994 22,728 18,395 4,398
1995 29,221 26,184 4,594
1996 24,741 29,975 4,717
1997 23,268 26,682 4,430
1998 21,400 26,029 3,704
|
Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure
None
Item 10. Directors and Executive Officers of the Registrant
Information pertaining to the Directors of the Company is incorporated herein
by reference to the Proxy Statement, under "Information Regarding the Board of
Directors and Nominees", dated and to be filed on or before March 30, 1999 in
connection with the Company's Annual Meeting to be held on May 18, 1999.
The information required by this item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Item 10 of Part I of this Form 10-K under "Executive Officers of the Registrant."
Item 11. Executive Compensation
This information is incorporated herein by reference to the Proxy Statement,
under "Report on Executive Compensation", dated and to be filed on or before
March 30, 1999 in connection with the Company's Annual Meeting to be held on
May 18, 1999.
Item 12. Security Ownership of Certain Beneficial Owners and Management
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company's Securities", dated and to be
filed on or before March 30, 1999 in connection with the Company's Annual
Meeting to be held on May 18, 1999.
Item 13. Certain Relationships and Related Transactions
This information is incorporated herein by reference to the Proxy Statement,
under "Beneficial Ownership of the Company's Securities", dated and to be
filed on or before March 30, 1999 in connection with the Company's Annual
Meeting to be held on May 18, 1999.
Item 14. Financial Statements, Financial Statement Schedules, Exhibits and
Reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements:
- Accountants' Report dated February 12, 1999 of PricewaterhouseCoopers LLP, Independent Accountants
- Consolidated Statements of Income for each of the three years ended December 31, 1998, 1997 and 1996
- Consolidated Balance Sheets at December 31, 1998 and December 31, 1997
- Consolidated Statements of Cash Flows for each of the three years ended December 31, 1998, 1997 and 1996
- Consolidated Statements of Common Stockholders' Equity for each of the three years ended December 31, 1998, 1997 and 1996
- Consolidated Statements of Income Taxes for each of the three years ended December 31, 1998, 1997 and 1996
- Notes to Consolidated Financial Statements
2. The following additional information for the years 1998, 1997 and 1996 is submitted herewith:
- Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not required, are inapplicable or the information is otherwise shown in the financial statements or notes thereto.
(b) Reports on Form 8-K:
None.
(c) Exhibits:
Exhibit 2(a) Agreement and Plan of Merger by and between
Chesapeake Utilities Corporation and Tri-County Gas Company, Inc.,
filed on the Company's Form 8-K, File No. 001-11590 on January 13,
1997, is incorporated herein by reference.
Exhibit 3(a) Amended Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590.
Exhibit 3(b) Amended Bylaws of Chesapeake Utilities Corporation, effective July 11, 1997, are incorporated herein by reference to Exhibit 3.2 of the Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590.
Exhibit 4(a) Form of Indenture between the Company and Boatmen's Trust Company, Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of the Company's Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989.
Exhibit 4(b) Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593.
Exhibit 4(c) Directors Stock Compensation Plan adopted by Chesapeake Utilities Corporation in 1995 is incorporated herein by reference to the Company's Proxy Statement dated April 17, 1995 in connection with the Company's Annual Meeting held in May 1995.
Exhibit 4(d) Note Purchase Agreement entered into by the Company on October 2, 1995, pursuant to which the Company privately placed $10 million of its 6.91% Senior Notes due in 2010, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the Commission upon request.
Exhibit 4(e) Note Purchase Agreement entered into by the Company on December 15, 1997, pursuant to which the Company privately placed $10.million of its 6.85 senior notes due 2012, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the Commission upon request.
Exhibit 10(a) Service Agreement dated November 1, 1989, by and between Transcontinental Gas Pipe Line Corporation and Eastern Shore Natural Gas Company, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, File No. 0-593.
Exhibit 10(b) Service Agreement dated November 1, 1989, by and between Columbia Gas Transmission Corporation and Eastern Shore Natural Gas Company, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1989, File No. 0-593.
Exhibit 10(c) Service Agreement for General Service dated November 1, 1989, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(d) Service Agreement for Preferred Service dated November 1, 1989, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(e) Service Agreement for Firm Transportation Service dated November 1, 1989, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(f) Form of Service Agreement for Interruptible Sales Services dated May 11, 1990, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(g) Interruptible Transportation Service Agreement dated February 23, 1990, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(h) Interruptible Transportation Service Agreement dated November 30, 1990, by and between Florida Gas Transmission Company and Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990, File No. 0-593.
Exhibit 10(i) Executive Employment Agreement dated March 26, 1997, by and between Chesapeake Utilities Corporation and each Ralph J. Adkins and John R. Schimkaitis is incorporated herein by reference to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1997, File No. 001-11590.
Exhibit 10(j) Form of Performance Share Agreement dated January 1, 1998, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Ralph J. Adkins and John R. Schimkaitis is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 001-11590.
Exhibit 10(k) Chesapeake Utilities Corporation Cash Bonus Incentive Plan dated January 1, 1992, is incorporated herein by reference to Exhibit 10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-593.
Exhibit 10(l) Chesapeake Utilities Corporation Performance Incentive Plan dated January 1, 1992, is incorporated herein by reference to the Company's Proxy Statement dated April 20, 1992, in connection with the Company's Annual Meeting held on May 19, 1992.
Exhibit 10(m) Form of Stock Option Agreement dated January 1, 1998, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Stephen C. Thompson, William C. Boyles, Philip S. Barefoot, Jeremy D. West, William P. Schneider and James R. Schneider, is incorporated herein by reference to Exhibit 10 of the Company's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 001-11590.
Exhibit 12 Computation of Ratio of Earning to Fixed Charges, filed herewith. Exhibit 21 Subsidiaries of the Registrant, filed herewith. Exhibit 23 Consent of Independent Accountants, filed herewith. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHESAPEAKE UTILITIES CORPORATION
By: /s/ JOHN R. SCHIMKAITIS
-------------------------
John R. Schimkaitis
President and Chief Executive Officer
Date: March 16, 1999
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ RALPH J. ADKINS /s/ JOHN R. SCHIMKAITIS ------------------------- ------------------------- Ralph J. Adkins, Chairman of the Board John R. Schimkaitis, President, and Director Chief Executive Officer and Director Date: March 16, 1999 Date: March 16, 1999 /s/ MICHAEL P. MCMASTERS /s/ RICHARD BERNSTEIN ------------------------- ------------------------- Michael P. McMasters, Vice President, Richard Bernstein, Director Chief Financial Officer and Treasurer Date: March 16,1999 (Principal Financial Officer) Date: March 16, 1999 /s/ WALTER J. COLEMAN /s/ John W. JARDINE, JR. ------------------------- ------------------------- Walter J. Coleman, Director John W. Jardine, Jr., Director Date: March 16, 1999 Date: March 16, 1999 /s/ RUDOLPH M. PEINS, JR. /s/ ROBERT F. RIDER ------------------------- ------------------------- Rudolph M. Peins, Jr., Director Robert F. Rider, Director Date: March 16, 1999 Date: March 16, 1999 /s/ JEREMIAH P. SHEA ------------------------- ------------------------- Jeremiah P. Shea, Director William G. Warden, III, Director Date: March 16, 1999 Date: March 16, 1999 |
Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts
--------------------------------------------------------------------------------------------
Additions
-----------------------
Balance at Balance at
Beginning Charged to Other End of
For the Year Ended December 31, of Year Income Accounts(1) Deductions(2) Year
--------------------------------------------------------------------------------------------
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
1998 $ 331,775 $280,391 $ 57,759 $ (367,412) $ 302,513
1997 $ 392,412 $203,624 $ 68,038 $ (332,299) $ 331,775
1996 $ 309,955 $364,622 $ 55,631 $ (337,796) $ 392,412
--------------------------------------------------------------------------------------------
(1) Recoveries.
(2) Uncollectible accounts charged off.
|
Chesapeake Utilities Corporation and Subsidiaries
Exhibit 12
Ratio of Earnings to Fixed Charges
--------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
--------------------------------------------------------------------------------------
Income from continuing operations $ 5,302,586 $ 5,867,612 $ 7,781,933
Add:
Income taxes 3,225,744 3,704,196 4,086,616
Portion of rents representative of interest 130,717 167,029 155,916
Interest on indebtedness 3,256,415 3,224,606 2,884,858
Amortization of debt discount and expense 123,335 119,401 120,345
--------------------------------------------------------------------------------------
Earnings as adjusted $12,038,797 $13,082,844 $15,029,668
======================================================================================
Fixed Charges
Portion of rents representative of interest $ 130,717 $ 167,029 $ 155,916
Interest on indebtedness 3,256,415 3,224,606 2,884,858
Amortization of debt discount and expense 123,335 119,401 120,345
--------------------------------------------------------------------------------------
Fixed Charges $ 3,510,467 $ 3,511,036 $ 3,161,119
======================================================================================
Ratio of Earnings to Fixed Charges 3.43 3.73 4.75
======================================================================================
|
CHESAPEAKE UTILITIES CORPORATION
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
Subsidiaries State Incorporated ------------ ------------------ Eastern Shore Natural Gas Company Delaware Sharp Energy, Inc. Delaware Chesapeake Service Company Delaware United Systems, Inc. Georgia Tri-County Gas Company, Inc. Maryland Eastern Shore Real Estate Maryland Xeron, Inc. Texas Sam Shannaham Well Co. Maryland Sharp Water, Inc. Delaware Subsidiary of Eastern Shore Natural Gas Company State Incorporated ----------------------------------------------- ------------------ Dover Exploration Company Delaware Subsidiaries of Sharp Energy, Inc. State Incorporated ---------------------------------- ------------------ Sharpgas, Inc. Delaware Sharpoil, Inc. Delaware Subsidiaries of Chesapeake Service Company State Incorporated ------------------------------------------ ------------------ Skipjack, Inc. Delaware Capital Data Systems, Inc. North Carolina Currin and Associates, Inc. North Carolina Chesapeake Investment Company Delaware |
We consent to the incorporation by reference in the Prospectuses of Chesapeake Utilities Corporation on Form S-2 (File No. 33-26582), Form S-3 (File Nos. 33-28391, 33-64671, 333-37165, 333-64757 and 333-63381) and Form S-8 (File No. 33-301175) of our report dated February 12, 1998 on our audits of the consolidated financial statements and the consolidated financial statement schedules of Chesapeake Utilities Corporation as of December 31, 1998 and 1997 and for each of the three years in the period ended December 31, 1998 included in this Annual Report on Form 10-K.
PricewaterhouseCoopers LLP
Washington, D.C.
March 25, 1999
ARTICLE UT
This schedule contains summary financial information extracted from the
Balance Sheets, Income Statements and Statements of Cash Flows for
the fiscal year 1998 and is qualified in its entirety by reference to
such financial statements.
RESTATED:
PERIOD TYPE
3 MOS
6 MOS
9 MOS
12 MOS
FISCAL YEAR END
DEC 31 1998
DEC 31 1998
DEC 31 1998
DEC 31 1998
PERIOD END
MAR 31 1998
JUN 30 1998
SEP 30 1998
DEC 31 1998
BOOK VALUE
PER BOOK
PER BOOK
PER BOOK
PER BOOK
TOTAL NET UTILITY PLANT
78105923
79207740
80165270
81626158
OTHER PROPERTY AND INVEST
25021432
25319525
25694382
26804812
TOTAL CURRENT ASSETS
26432358
21511067
20977538
26620666
TOTAL DEFERRED CHARGES
11164550
11575896
11716399
10181977
OTHER ASSETS
0
0
0
0
TOTAL ASSETS
140728263
137614228
139053589
145233613
COMMON
2455068
2462270
2470819
2479019
CAPITAL SURPLUS PAID IN
23342529
23601702
23903562
24192188
RETAINED EARNINGS
31397823
31709187
27908713
28892384
TOTAL COMMON STOCKHOLDERS EQ
57515755
58322151
54878856
56355894
PREFERRED MANDATORY
0
0
0
0
PREFERRED
0
0
0
0
LONG TERM DEBT NET
38152000
37892000
37870000
37597000
SHORT TERM NOTES
0
2100000
5200000
11600000
LONG TERM NOTES PAYABLE
0
0
0
0
COMMERCIAL PAPER OBLIGATIONS
0
0
0
0
LONG TERM DEBT CURRENT PORT
520000
520000
520000
520000
PREFERRED STOCK CURRENT
0
0
0
0
CAPITAL LEASE OBLIGATIONS
0
0
0
0
LEASES CURRENT
0
0
0
0
OTHER ITEMS CAPITAL AND LIAB
44540508
38780077
40584733
39160719
TOT CAPITALIZATION AND LIAB
140728263
137614228
139053589
145233613
GROSS OPERATING REVENUE
60169102
103764046
139995969
183568795
INCOME TAX EXPENSE
2426791
2529298
1757692
3181599
OTHER OPERATING EXPENSES
9132650
18353227
27731584
35926301
TOTAL OPERATING EXPENSES
11559441
20882525
29489276
39107900
OPERATING INCOME LOSS
4744218
5706320
5246355
8441082
OTHER INCOME NET
110390
199577
222629
241254
INCOME BEFORE INTEREST EXPEN
4854608
5905897
5468984
8682336
TOTAL INTEREST EXPENSE
854007
1641544
2471129
3379750
NET INCOME
4000602
4264353
2997854
5302586
PREFERRED STOCK DIVIDENDS
0
0
0
0
EARNINGS AVAILABLE FOR COMM
4000602
4264353
2997854
5302586
COMMON STOCK DIVIDENDS
1135924
2400768
3669900
4943347
TOTAL INTEREST ON BONDS
745684
1487015
2226800
2966043
CASH FLOW OPERATIONS
13196414
10634780
10045773
11027405
EPS PRIMARY
.80
.85
.59
1.05
EPS DILUTED
.77
.83
.59
1.04
ARTICLE UT
This schedule contains summary financial information extracted from the
Balance Sheets, Income Statements and Statements of Cash Flows for the
fiscal year 1997 and is qualified in its entirety by reference to
such financial statements.
RESTATED:
PERIOD TYPE
3 MOS
6 MOS
9 MOS
12 MOS
FISCAL YEAR END
DEC 31 1997
DEC 31 1997
DEC 31 1997
DEC 31 1997
PERIOD END
MAR 31 1997
JUN 30 1997
SEP 30 1997
DEC 31 1997
BOOK VALUE
PER BOOK
PER BOOK
PER BOOK
PER BOOK
TOTAL NET UTILITY PLANT
75314310
76180847
76766578
77787816
OTHER PROPERTY AND INVEST
23225413
23286176
24062505
24812830
TOTAL CURRENT ASSETS
27138881
22202081
25254288
31827107
TOTAL DEFERRED CHARGES
12738268
11944514
12841914
11291070
OTHER ASSETS
0
0
0
0
TOTAL ASSETS
138416872
133613619
138925285
145718823
COMMON
2410397
2417414
2424364
2435142
CAPITAL SURPLUS PAID IN
21723848
21959895
22195138
22581463
RETAINED EARNINGS
29388364
28998887
27149356
28533145
TOTAL COMMON STOCKHOLDERS EQ
53232486
53129331
51599071
53655736
PREFERRED MANDATORY
0
0
0
0
PREFERRED
0
0
0
0
LONG TERM DEBT NET
28907000
38647000
28642000
38226000
SHORT TERM NOTES
12000010
9900010
18400010
7600000
LONG TERM NOTES PAYABLE
0
0
0
0
COMMERCIAL PAPER OBLIGATIONS
0
0
0
0
LONG TERM DEBT CURRENT PORT
1257057
1177485
1107545
1051241
PREFERRED STOCK CURRENT
0
0
0
0
CAPITAL LEASE OBLIGATIONS
0
0
0
0
LEASES CURRENT
0
0
0
0
OTHER ITEMS CAPITAL AND LIAB
38217405
38406731
37142185
45185846
TOT CAPITALIZATION AND LIAB
138416872
133613619
138925285
145718823
GROSS OPERATING REVENUE
76302285
121221105
162901824
222489264
INCOME TAX EXPENSE
2253635
2687549
2132434
3427308
OTHER OPERATING EXPENSES
9057058
17733587
26368156
35204402
TOTAL OPERATING EXPENSES
11310693
20421136
28500590
38631702
OPERATING INCOME LOSS
4148755
5541422
5534397
8666464
OTHER INCOME NET
94682
199593
270086
545155
INCOME BEFORE INTEREST EXPEN
4243437
5741015
5804483
9211619
TOTAL INTEREST EXPENSE
809790
1600068
2426318
3344007
NET INCOME
3433648
4140948
3378165
5867612
PREFERRED STOCK DIVIDENDS
0
0
0
0
EARNINGS AVAILABLE FOR COMM
3433648
4140948
3378165
5867612
COMMON STOCK DIVIDENDS
1079781
2163059
3249798
4341964
TOTAL INTEREST ON BONDS
596357
1190742
1960747
2387641
CASH FLOW OPERATIONS
7531133
11315440
6177387
11674801
EPS PRIMARY
.69
.84
.68
1.18
EPS DILUTED
.67
.82
.68
1.17