ITEM 1. BUSINESS
(A) GENERAL DEVELOPMENT OF BUSINESS
Chesapeake Utilities Corporation ("Chesapeake" or "the Company") is a diversified utility company engaged in natural gas distribution and transmission, propane distribution and information technology services.
Chesapeake's three natural gas distribution divisions serve more than 32,300 residential, commercial and industrial customers in southern Delaware, Maryland's Eastern Shore and Central Florida. The natural gas transmission subsidiary operates a 271-mile interstate pipeline system that transports gas from various points in Pennsylvania to the Company's Delaware and Maryland distribution divisions, as well as to other utilities and industrial customers in Delaware and the Eastern Shore of Maryland. The Company's propane segment serves approximately 22,600 customers in southern Delaware and the Eastern Shore of Maryland and Virginia. The information technology services segment provides software products and services to a wide variety of customers and clients.
(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
(C) NARRATIVE DESCRIPTION OF BUSINESS
The Company is engaged in four primary business activities: natural gas transmission; natural gas distribution; propane distribution; and information technology services. In addition to the four primary groups, Chesapeake has four subsidiaries engaged in other service related businesses. During 1994 and 1992 no individual customer accounted for 10% or more of revenues. The Company had one customer, Texaco Refining and Marketing, with revenues equal to or greater than 10% of total revenue in 1993. This industrial interruptible customer of the Company's natural gas transmission subsidiary accounted for approximately $9,600,000 or 11.2% of total consolidated revenue and 25.7% of the transmission subsidiary's total revenue.
(I) (A) NATURAL GAS TRANSMISSION
Eastern Shore Natural Gas Company ("Eastern Shore"), the Company's wholly owned transmission subsidiary, operates an interstate pipeline that delivers gas to five utility and thirteen industrial customers in Delaware and the Eastern Shore of Maryland. Eastern Shore is the sole source of gas supply for Chesapeake's Maryland and Delaware divisions and for two unaffiliated distribution entities. Eastern Shore has not elected to be an "open access" pipeline which would only provide transportation services. However, Eastern Shore has authority from the Federal Energy Regulatory Commission ("FERC") to provide firm transportation to two of its customers for gas they own and deliver to Eastern Shore for redelivery.
Operating income before income taxes attributable to natural gas transmission has varied from between $2.7 to $3.1 million from 1992 to 1994, with the high occurring in 1993. These fluctuations have resulted primarily from variations in volumes and margins on Eastern Shore's interruptible sales to industrial customers that have the capability of switching to oil for their fuel requirements. Rates charged to these customers are determined through negotiation and thus are flexible. When lower oil prices prevail Eastern Shore normally reduces the price it charges to its interruptible customers, thereby reducing the profit margin on such sales. In addition, certain customers switch from natural gas to oil, reducing volumes sold.
NATURAL GAS SUPPLY
General. Eastern Shore has firm contracts with three major interstate pipelines, Transcontinental Pipe Line Corporation ("Transco"), Columbia Gas Transmission Corporation ("Columbia") and Columbia Gulf Transmission Corporation ("Gulf"), all of which are "open-access" pipelines.
Eastern Shore's contracts with Transco include (a) firm transportation capacity of 22,900 MCF per day, which expires in 2005; (b) firm transportation capacity of 500 MCF per day for December through February, which expires in 2006; (c) three firm storage services providing a peak day entitlement of 7,046 MCF and a total capacity of 288,730 MCF and (d) two interruptible storage services with a total capacity of 427,182 MCF.
Eastern Shore's contracts with Columbia include: (a) firm transportation capacity of 1,481 MCF per day, which expires in 2003 and (b) firm storage service providing a peak day entitlement of 10,525 MCF per day and a total capacity of 509,954 MCF.
Eastern Shore's contract with Gulf is for firm transportation of 1,510 MCF per day, which also expires in 2003.
Eastern Shore currently has contracts for the purchase of firm natural gas supplies with six reputable suppliers. These six contracts provide a maximum daily entitlement of 18,572 MCF and the supplies are transported by both Transco and Columbia under Eastern Shore's firm transportation agreements. The gas purchase contracts have various expiration dates.
Adequacy of Gas Supply. Eastern Shore's firm obligations to its customers, including Chesapeake's Delaware and Maryland utility divisions, are 40,237 MCF for peak days and 9,200,565 MCF on an annual basis. Eastern Shore's maximum daily firm transportation capacity on the Transco and Columbia
systems is 42,452 MCF per day. Currently, Eastern Shore's firm daily peak supply is 36,643 MCF and its total annual firm supply is 7,054,332 MCF. This is equivalent to 91% of Eastern Shore's firm daily demand and 77% of its annual firm demand being satisfied by firm supply sources. To meet the difference between firm supply and firm demand, Eastern Shore obtains gas supply on the "spot market" from various other suppliers which is transported by Transco or Columbia and sold to Eastern Shore's customers as required. The Company believes that Eastern Shore's available firm, interruptible and "spot market" supply is ample to meet the anticipated needs of Eastern Shore's customers.
There was no curtailment of firm gas supply to Eastern Shore in 1994, nor does Eastern Shore anticipate any such curtailment during 1995.
COMPETITION
Competition with Alternative Fuels. Historically, the Company's natural gas operations have successfully competed with other forms of energy such as electricity, oil, and propane. The principal consideration in the competition between the Company and suppliers of other sources of energy is price and, to a lesser extent, accessibility. All of the Company's divisions have the capability of adjusting their interruptible rates to compete with alternative fuels.
The Company has several large volume industrial customers that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, some of Chesapeake's natural gas distribution and transmission interruptible customers convert to oil to satisfy their fuel requirements. Lower levels in interruptible sales occur when oil prices remain depressed relative to the price of natural gas. However, oil prices as well as the prices of other fuels are subject to change at any time for a variety of reasons. Therefore, there is always uncertainty in the continuing competition among natural gas and other fuels. In order to address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales side of its business to maximize sales volumes.
To a lesser extent than price, availability of equipment and operational efficiency are also factors in competition among fuels, primarily in residential and commercial settings. Heating, water heating, and other domestic or commercial equipment is generally designed for a particular energy source, and especially with respect to heating equipment, the high cost of conversion is a disincentive for individuals and businesses to change their energy source.
Competition within the Natural Gas Industry. FERC Order 636 enables all natural gas suppliers to compete for customers on equal footing. Under this "open access" environment, interstate pipeline companies have unbundled the traditional components of their service--gas gathering, transportation and storage. If they choose to be a merchant of gas, they must form a separate marketing operation independent of their pipeline operations. Hence, gas markets 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.
Eastern Shore has not elected to be an "open access" pipeline and is permitted to transport gas for only two of its existing customers. Thus, most of Eastern Shore's customers, including Chesapeake's Maryland and Delaware utility divisions, and, in turn, customers of these divisions, do not have the capability of directly contracting for alternative sources of gas supply and have Eastern Shore transport the gas to them.
RATES AND REGULATION
General. Eastern Shore is subject to regulation by the FERC as an interstate pipeline and the Delaware Public Service Commission ("Commission") as a supplier of gas to industrial customers in the state of Delaware. The FERC regulates the provision of service, terms and conditions of service, and the rates and fees Eastern Shore can charge its transportation and sale for resale customers. In addition, the
FERC regulates the rates Eastern Shore is charged for transportation and transmission line purchases provided by Transco and Columbia. Eastern Shore's direct sales rates to industrial customers are currently not regulated. The rates for such sales are established by contracts negotiated between Eastern Shore and each industrial customer.
On February 11, 1992, the Commission issued an Order that declared Eastern Shore to be a "public utility" under Delaware law subject to the Commission's jurisdiction in connection with Eastern Shore's direct retail sales of natural gas to end-users in the State of Delaware. The Order also initiated proceeding to consider the extent to which public utility regulatory supervision should be imposed upon the direct sales of Eastern Shore within the State of Delaware. On May 14, 1994 the Company filed with the commission a proposal for a limited level of regulation. On October 4, 1994, the Commission issued an Order essentially agreeing with a level of regulation limited to the following: accepting and considering complaints from customers, requiring Eastern Shore to file the annual and other periodic reports and requiring Eastern Shore to pay the annual public utility tax. In the opinion of management, the Order will not have a material effect on Eastern Shore's financial position or results of operations.
The rates for Eastern Shore's "sale for resale" customers, (i.e., sales to its utility customers) are subject to a purchased gas adjustment clause. Eastern Shore's firm industrial contracts generally include tracking provisions that permit automatic adjustment for the full amount of increases or decreases in Eastern Shore's suppliers' firm rates.
Rate Proceedings. On August 31, 1992, Eastern Shore filed with the FERC to restate its Base Tariff Rates in compliance with Section 154.303(e) of the FERC's regulations for sales and transportation to its jurisdictional customers, including the Company's Delaware and Maryland divisions. On March 26, 1993, Eastern Shore filed a stipulation and agreement with FERC, which was subsequently approved on May 24, 1993 by letter. The final settlement did not materially affect the consolidated financial position of the Company because the resulting FERC order allowed current billing rates to stay in effect.
FERC PGA. On May 19, 1994, the FERC issued an Order directing Eastern Shore to refund, with interest, what the FERC characterized as overcharges from November 1, 1992 to the current billing month. The May 19, 1994 Order also directed Eastern Shore to file a report showing how the refund was calculated, and revised tariff language clarifying the purchased gas adjustment provisions its tariff.
Eastern Shore filed a request for rehearing of the Order on June 20, 1994 based on what Eastern Shore believes is the FERC's erroneous interpretation of Eastern Shore's tariff. It is Eastern Shore's position that the FERC's Order essentially requires a retroactive change to the FERC approved PGA procedures which Eastern Shore has consistently applied over the last six years. Such retroactive application is a violation of Sections 4 and 5 of the Natural Gas Act.
On June 21, 1994, in compliance with the FERC's May 19, 1994 Order, Eastern Shore filed: (1) revised tariff sheets clarifying its PGA methodology and (2) two alternative refund calculations based of the FERC's Order. The two alternatives were filed due to what Eastern Shore believes to be an inconsistency or contradiction with respect to the FERC's language in its Order.
On July 18, 1994 the FERC issued an "Order Granting a Rehearing Solely for the Purpose of Further Consideration". This Order was issued only to afford the FERC additional time for consideration of the issues raised in Eastern Shore's request for rehearing.
As of this filing date, the FERC has not approved either of the alternative refund calculations submitted by Eastern Shore on June 21, 1994, nor has it made a final determination as to Eastern Shore's request for rehearing. Accordingly, Eastern Shore accrued $412,000 in the second quarter of 1994, relating to prior periods. Eastern Shore has also accrued an amount each month in 1994 to insure full refunding of the potential refund. The total amount accrued on December 31, 1994 is $1,283,000.
(I) (B) NATURAL GAS DISTRIBUTION
Chesapeake distributes natural gas to approximately 32,300 residential, commercial and industrial customers in southern Delaware, the Salisbury and Cambridge, Maryland areas on Maryland's Eastern Shore, and Central Florida. These activities are conducted through three utility divisions, consisting of one division in Delaware, one division in Maryland, and one division in Florida. In 1993, the Company started brokering natural gas in the state of Florida under the name of Peninsula Energy Services Company ("PESCO").
Delaware and Maryland. The Delaware and Maryland divisions serve approximately 24,287 customers, of which approximately 24,200 are residential and commercial customers purchasing gas primarily for heating purposes. Residential and commercial customers account for approximately 67% of the volume delivered by the divisions, and 79% of the divisions' revenue, on an annual basis. The divisions' industrial customers purchase gas, primarily on an interruptible basis, for a variety of manufacturing, agricultural and other uses. Most of Chesapeake's customer growth in these divisions comes from new residential construction utilizing gas heating equipment.
Florida. The Florida division distributes natural gas to approximately 8,000 residential and commercial and 83 industrial customers in Polk, Osceola and Hillsborough Counties. Currently 34 of the division's industrial customers, which are engaged primarily in the citrus and phosphate industries and electric cogeneration, and purchase and transport gas on a firm and interruptible basis, account for approximately 82% of the volume delivered by the Florida division, and 67% of the division's natural gas sales and transportation revenues, on an annual basis. In November 1993, the Company's Florida division began providing natural gas brokering services to compete in the open access environment. Currently, fourteen customers receive brokering service which generated margin of $63,000 in 1994.
NATURAL GAS SUPPLY
Delaware and Maryland. Chesapeake's Delaware and Maryland utility divisions receive all of their gas supply requirements from Eastern Shore. The divisions purchase most of this gas under contracts with Eastern Shore which extend through November 1, 2000. The contracts provide for the purchase of 15,629 firm MCF daily (up to a maximum of 5,704,585 MCF annually). The divisions have additional firm supplies available under contract with Eastern Shore for peak demand periods occurring during the winter heating season. These contracts, which are renewable on a year-to- year basis, provide for the purchase of up to 450 MCF daily (up to a maximum of 13,500 MCF annually) of peaking service. In addition, the divisions have contracted with Eastern Shore for firm and interruptible storage capacity. On days when gas volumes available to the divisions from Eastern Shore are greater than their requirements, gas is injected into storage and is then available for withdrawal to meet heavier winter loads. These storage contracts also permit the utility divisions to purchase lower cost gas during the off-peak summer season. Effective November 1, 1993, the storage capacity under contract with Eastern Shore totaled 829,532 MCF, with a firm peak daily withdrawal entitlement of 14,605 MCF. On those days when requirements exceed these contract pipeline supplies, the divisions have propane-air injection facilities for peak shaving.
Eastern Shore has no authority to transport natural gas purchased from a third party for the Delaware and Maryland divisions; however, while Chesapeake's divisions have no direct access to lower priced "spot market" gas, they benefit from Eastern Shore's ability to obtain "spot market" gas and the resulting reductions in Eastern Shore's rates.
Florida. The Florida division receives transportation service from Florida Gas Transmission Company ("FGT"), a major interstate pipeline. Chesapeake has contracts with FGT for (a) daily firm transportation capacity of 20,523 dekatherms in May through September, 27,105 dekatherms in October, and 26,919 dekatherms in October through April under FGT's firm transportation service (FTS-1) rate schedule; (b) daily firm transportation capacity of 5,100 dekatherms in May through October, and 8,100
dekatherms in November through April under FGT's firm transportation service (FTS-2) rate schedule; (c) preferred interruptible transportation service up to 2,300,000 dekatherms annually under FGT's preferred transportation service (PTS-1) rate schedule; and (d) daily interruptible transportation capacity of 20,000 dekatherms under FGT's interruptible transportation services (ITS-1) rate schedule. The firm transportation contract (FTS-1) expires on August 1, 2000 with the Company retaining a unilateral right to extend the term for an additional ten years. After the expiration of the primary or secondary term, Chesapeake has the right to first refuse to match the terms of any competing bids for the capacity. The firm transportation contract (FTS-2) expires on March 1, 2015. The preferred interruptible contract expires on the earlier of (a) the effective date of FGT's first rate case which includes costs for phase III expansion; or (b) August 1, 1995 and or (c) August 1 of any subsequent year, provided that FGT or Chesapeake gives to the other at least one hundred eighty (180) days written notice prior to such August 1. The interruptible transportation contract is effective until August 1, 2010 and month to month thereafter unless cancelled by either party with thirty days notice.
The Florida division currently receives its gas supply from various suppliers. Some supply is bought on the spot market and some is bought under the terms of two firm supply contacts with MG National Gas Corp. and Hadson Gas Systems, Inc.
Having restructured its arrangements with FGT, Chesapeake believes it is well positioned to meet the continuing needs of its customers with secure and cost effective gas supplies.
Adequacy of Gas Supply. The Company believes that Eastern Shore's available firm and interruptible supply is ample to meet the anticipated needs of the Company's Delaware and Maryland natural gas distribution divisions. Availability of gas supply to the Florida division is also expected to be adequate under existing arrangements. Moreover, additional supply sources have become available as a result of FGT becoming an "open access" pipeline.
Competition within the Natural Gas Industry. Historically, Chesapeake's Florida division has been supplied solely by FGT. In 1990, FGT became an "open access" pipeline. The Florida division's large industrial customers now have the option of remaining with the Florida division for gas supply or obtaining alternative supplies from FGT, gas marketers or other suppliers. These conditions have increased competition between Chesapeake's Florida division, FGT, gas marketers and other natural gas providers for industrial customers in Central Florida. Starting in early 1993, in recognition of the opportunity created by FERC Order 636, Chesapeake's Florida division began contacting all of the Florida division's large industrial customers and other large users of natural gas throughout the state of Florida about changes in the natural gas industry. As a result, the Company has entered into agreements with a number of these large users of natural gas to supply them with brokering and regulatory support services.
RATES AND REGULATION
General. Chesapeake's natural gas distribution operations are subject to regulation by the Delaware, Maryland, and Florida Public Service Commissions with respect to various aspects of the Company's business, including the rates for sales to all of their customers in each jurisdiction. All of Chesapeake's firm distribution rates are subject to purchased gas adjustment clauses, which match revenues with gas costs and normally allow eventual full recovery of gas costs. Adjustments under these clauses require periodic filings and hearings with the relevant regulatory authority, but do not require a general rate proceeding. Rates on interruptible sales by the Florida division are also subject to purchased gas adjustment clauses.
Management monitors the rate of return in each jurisdiction in order to ensure the timely filing of rate adjustment applications.
RATE PROCEEDINGS
Maryland. During 1994, the Company filed a petition with and received approval from the Maryland Public Service Commission to consolidate, for rate and accounting purposes, its two distribution divisions located in Salisbury and Cambridge, Maryland.
Florida. On December 10, 1993, the Florida Public Service Commission issued an order reducing the Florida divisions allowed return on equity from 12% to 11%, in response to lower interest rates. On August 5, 1994, the Florida division filed Modified Minimum Filing Requirements which are required every 4 years by Florida Public Service Commission regulations. As of December 31, 1994, no decision had been rendered by the Florida Public Service Commission on the Division's MMFR's. However, as a result of the order received by the Division regarding its 1994 potential overearnings, any change in the Division's authorized return on equity that results from the PSC's decision on the MMFR's will not become effective until January 1, 1996. On February 6, 1995, the Florida Public Service Commission approved the Florida division's proposal to cap its 1994 and 1995 earnings at 12%. The order also allows the division to offset any 1994 excess earnings against anticipated increases in major expense areas in 1995 and permits the division to resume recovery of its annual accrual to the environmental clean-up reserve.
(I) (C) PROPANE DISTRIBUTION
Chesapeake's propane distribution group consists of Sharp Energy, Inc. ("Sharp Energy"), a wholly owned subsidiary of Chesapeake, and its wholly owned subsidiaries, Sharpgas, Inc. ("Sharpgas") and Sharpoil, Inc. ("Sharpoil").
Sharpgas purchases, stores and distributes propane to approximately 22,600 customers on the Delmarva Peninsula. The propane distribution business is affected by many factors such as seasonality, the absence of price regulation and competition among local providers.
Propane is a form of liquefied petroleum gas which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is gaseous at normal pressures, it is easily compressed into liquid form for storage and transportation. Propane is a clean-burning fuel, gaining increased recognition for its environmental superiority, safety, efficiency, transportability and ease of use relative to alternative forms of energy.
Propane is sold primarily in suburban and rural areas which are not served by natural gas pipelines. Demand is typically much higher in the winter months and is significantly affected by seasonal variations, particularly the relative severity of winter temperatures, because of its use in residential and commercial heating.
The Company purchases propane primarily from five suppliers, including major domestic oil companies and independent producers of gas liquids and oil. Supplies of propane from these and other sources are readily available for purchase by the Company. Supply contracts generally include minimum (not subject to take-or-pay) and maximum purchase provisions.
The Company uses trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to the Company's bulk storage facilities. From these facilities, propane is delivered by "bobtail" trucks owned and operated by the Company to tanks located at the customer's premises, or in portable cylinders. Most of the tanks and cylinders are owned by the Company and are utilized by the customer free of charge.
Sharpgas competes with several other propane distributors in its service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally local because distributors located in close proximity to customers incur lower costs of providing service.
Propane competes with electricity and fuel oil as an energy source. Propane is typically comparable in price to fuel oil and generally less expensive than electricity based on equivalent BTU value. Because natural gas historically has been less expensive than propane, propane is generally not distributed in geographic areas serviced by natural gas pipeline or distribution systems.
The Company's propane distribution activities are not subject to any federal or state pricing regulation. Transport operations are subject to regulations concerning the transportation of hazardous materials promulgated under the Federal Motor Carrier Safety Act, which is administered by the United States Department of Transportation and enforced by the various states in which such operations take place. Propane distribution operations are also subject to state safety regulations relating to "hook-up" and placement of propane tanks.
The Company's propane operations are subject to all operating hazards normally incident to the handling, storage and transportation of combustible liquids, such as the risk of personal injury and property damage caused by fire. The Company carries general liability insurance in the amount of $35,000,000 per occurrence, but there is no assurance that such insurance will be adequate.
In 1991, the Company decided to discontinue its entire fuel oils and motor fuels delivery business. During 1992, the Company consummated the sale of substantially all of the assets of Sharpoil. Chesapeake originally acquired Sharpoil's assets in December 1988, when it purchased certain propane and oil assets of Kellam Energy, Inc. Sharpoil was formed at that time to conduct a small oil products distribution business in Virginia and Maryland which served approximately 2,500 customers. The decision to dispose of Sharpoil resulted in a charge to fourth quarter 1991 earnings of $500,000 and includes the write-off of goodwill and other intangible assets, estimated losses on the sale of all of its oil products distribution assets and an estimated loss anticipated in 1992 with respect to operating the remaining business through the date of sale (the actual loss was $426,500). See Note B to the Company's Consolidated Financial Statements.
(I) (D) INFORMATION TECHNOLOGY SERVICES
Chesapeake's information technology services segment is comprised of two wholly owned subsidiaries of the Company: Capital Data Systems, Inc. ("CDS") and United Systems, Inc. ("USI").
CDS is an information technology provider offering software products and services primarily to the telecommunications companies and Chesapeake's subsidiaries. Application software solutions include customer information, management information, billing and financial systems. To a broader market, CDS offers outsourcing/facilities management, network design and management, disaster recovery, contract programming and consulting services.
USI is an Atlanta-based company that primarily provides support for users of PROGRESS (R), a fourth generation computer language and Relational Database Management System. USI offers consulting, training, software development "tools" and customer software development for their client base, which includes many large domestic and international corporations. The Information Technology businesses face significant competition from a number of larger competitors having substantially greater resources available to them than the Company. In addition, changes in the Information Technology business is occurring rapidly, which could adversely impact the markets for the Company's products and services.
(I) (E) OTHER LINES OF BUSINESS
In addition to the four business segments previously mentioned, the Company is involved in other businesses under the umbrella of Chesapeake Service Company ("Chesapeake Service"), a wholly owned subsidiary of the Company. In addition to CDS, the group contains Currin and Associates, Inc. ("C&A"), Skipjack, Inc. ("Skipjack"), and Chesapeake Investment Company ("Chesapeake Investment"), all three of which are wholly owned subsidiaries of Chesapeake Service. Skipjack owns and leases to affiliates an office building in Dover, Delaware. Chesapeake Investment is a Delaware affiliated investment company.
In 1994, based on declining revenue and business projections, the Company disposed of its investment in C&A, a rate and regulatory consulting subsidiary acquired in 1988. Revenue declined from
a high of $593,000 in 1992 to a low of $52,000 for 1994. The disposition has resulted in a $260,000 after tax loss recorded to Other Income and Deductions. The loss resulted from the write-off of goodwill and the disposition of other assets.
(II) SEASONAL NATURE OF BUSINESS
Revenues from the Company's residential and commercial natural gas sales and from its propane distribution activities are affected by seasonal variations, since the majority of these sales are to customers using the fuels for heating purposes. Revenues from these customers are accordingly affected by the mildness or severity of the heating season.
(III) CAPITAL BUDGET
The Company's current capital budget for 1995 contemplates expenditures totalling approximately $16.6 million. The total includes approximately $11.7 million for Chesapeake's natural gas distribution divisions, consisting mainly of extensions to and replacements of the distribution facilities and related equipment; $1.7 million for natural gas transmission operations, providing principally for improvements and enhancements to its measuring and regulating stations; $1.7 million for propane distribution, principally for the purchase of storage facilities, additional tanks and transportation equipment; $452,000 for computer hardware, software and related equipment required for expansion of the Company's information technology services activities; and $1.0 million for building construction and improvements in Chesapeake's Skipjack subsidiary, along with miscellaneous equipment for the administrative group. These capital requirements are expected to be financed by cash flow provided by the Company's operating activities and short-term borrowing.
(IV)ENVIRONMENTAL
(IV) (A) DOVER GAS LIGHT SITE
In 1984, the State of Delaware notified the Company that a parcel of land it purchased in 1949 from Dover Gas Light Company, a predecessor gas company, contains hazardous substances. The State also asserted that the Company is responsible for any clean-up and prospective environmental monitoring of the site. The Delaware Department of Natural Resources and Environmental Control ("DNREC") investigated the site and surroundings, finding coal tar residue and some ground-water contamination.
In October 1989, the Environmental Protection Agency Region III ("EPA") listed the Dover Site on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"). Under CERCLA, the State of Delaware and the Company are potentially responsible parties ("PRP") for clean-up of the site. In July 1990, the Company entered into an agreement with EPA and DNREC to perform a Remedial Investigation/ Feasibility Study under the supervision of EPA and DNREC to study the site and surroundings to determine any environmental impacts. Pursuant to the agreement the Company agreed to pay for the study and 80% of EPA's oversight cost while DNREC is paying for all of its own oversight costs as the lead agency plus 20% of EPA's oversight costs. The Company submitted its reports on the Remedial Investigation ("RI") and Feasibility Study ("FS") to EPA and DNREC on January 25, 1993 and February 15, 1993, respectively. The Company received extensive comments from EPA and DNREC on the RI and FS reports. The Company submitted to the EPA and DNREC its revised RI and FS on May 14, 1993 and June 25, 1993, respectively. In the FS Report, Chesapeake proposed a remedy which involved capping the site and monitoring ground-water quality in the surrounding area. Chesapeake's consultant estimated that it would cost approximately $700,000 to execute this plan of remediation.
After further discussions with the regulatory authorities, Chesapeake agreed to undertake an additional phase study, the Ground Water Evaluation Study--Phase III, which focused on delineating
the area of maximum ground-water impact from the site. The results of that study were submitted to EPA and DNREC in September 1993. On February 1, 1994, EPA issued its proposed plan of action (the "Plan"). The Plan adopted many findings of the Phase III Study, acknowledging that the Dover Site has impacted ground-water only in a limited area.
The Plan presented and discussed a number of remedial alternatives, including the remedial strategy proposed by the Company in the FS. The EPA Plan proposed a more extensive remediation strategy that involves removal of contaminated soils from the site and drilling a series of twenty (20) wells. EPA estimated that execution of its Plan would cost $4.9 million. The Plan was submitted by the EPA for public comment. The 30-day public comment period ended on April 4, 1994. During this period, the EPA received public comments, including those submitted by the Company.
The EPA issued the site Record of Decision ("ROD") dated August 16, 1994. The remedial action selected by the EPA in the ROD differed significantly from the Plan. The EPA selected a remediation addressing the ground-water contamination with a combination of hydraulic containment and natural attenuation. Remediation selected for the soil at the site is to meet stringent cleanup standards for the first two feet of soil and less stringent standards for the soil below two feet. These selected levels of remediation were not alternatives listed in the Plan, but utilized elements proposed. In addition, the ROD incorporated many of the public comments that were received. The ROD estimates the costs of selected remediation of ground-water and soil at $2.7 million and $3.3 million, respectively. The remediation selected in the ROD is substantially more limited than had been suggested in the Plan. In the ROD, the EPA indicated that its previous $4.9 million estimate was incorrect.
On November 18, 1994, EPA issued a "Special Notice Letter" (the "Letter") to Chesapeake and three other PRPs. The Letter included, inter alia, (1) a demand for payment by the PRPs of EPA's past costs (currently estimated to be approximately $300,000) and future costs incurred overseeing site work; (2) notice of EPA's commencement of a 60 day moratorium on certain EPA response activities at the site; (3) a request by EPA that Chesapeake and the other PRPs submit a "good faith proposal" to conduct or finance the work identified in the ROD; and (4) proposed consent orders by which Chesapeake and other parties may agree to perform the good faith proposal.
In January 1995, Chesapeake submitted to the EPA a good faith proposal to perform a substantial portion of the work set forth in the ROD, which was subsequently rejected. It is unknown whether other PRPs will submit good faith proposals, what such proposals might include, and whether EPA would accept such proposals. Under CERCLA, the EPA may reject any of the proposals, and seek an administrative or court order to require any or all of the PRPs to implement the work. EPA may also do the work itself and seek recovery of its costs in court.
The Company and the EPA are each attempting to secure voluntary performance of part of the remediation by other parties. These parties include the State of Delaware, which is the owner of the property and was identified in the ROD as a PRP, and a business identified in the ROD as a PRP for having contributed to ground-water contamination. On March 6, 1995, in order to protect its interests, the Company filed suit in federal court for a determination that the State of Delaware is a liable party and for recovery from the State of costs of complying with the ROD. The Company is also considering suit against other PRPs. In addition, EPA has stated that it will take steps to secure prompt commencement of the remedial design phase needed to implement the ROD. The Company therefore anticipates further negotiations to resolve these matters among the parties and with the government. Management is evaluating the ROD to determine the most economic approach to implementation of the remedies selected in the ROD.
In the third quarter of 1994, the Company increased its accrued liability recorded with respect to the Dover Site to $6.0 million from $700,000. This amount reflects the EPA's present estimate, as stated in the ROD, for remediation of the site according to the ROD. Future developments in the matters discussed above would be accompanied by appropriate reductions to the liability recorded as they occur. The Company also increased the corresponding regulatory asset to $6.0 million. If the Company incurs expenses of that amount in connection with undertaking the remedies selected in the ROD, management's belief is that the Company will be equitably entitled to contribution from other responsible parties for the greater part of these expenses. Management also believes that any amounts not so contributed will be recoverable in the Company's rates.
As of December 31, 1994, the Company has incurred approximately $3,099,000 in costs relating to environmental testing and remedial action studies. In 1990, the Company entered into settlement agreements with a number of insurance companies resulting in proceeds to fund actual environmental costs incurred over a five to seven year period beginning in 1990. On February 23, 1993, the Delaware Public Service Commission, consistent with prior base rate proceedings, authorized the Company to amortize an additional $749,971 in environmental expenses for ratemaking purposes over a seven year period. At December 31, 1994 the unamortized balance is approximately $554,000. Of the $3,099,000 in costs reported above, approximately $227,000 has not yet been recovered through insurance proceeds or received ratemaking treatment. It is management's opinion that these costs incurred will be recoverable in rates.
(IV) (B) SALISBURY TOWN GAS LIGHT SITE
In cooperation with the Maryland Department of the Environment ("MDE"), the Company has completed an assessment of the Salisbury manufactured gas plant site. The assessment determined that there was localized contamination of ground-water. A remedial design report was submitted to MDE in November 1990 and included a proposal to monitor, pump and treat any contaminated ground-water on-site. The Company has proposed to MDE to proceed with these activities over a maximum period of five years, after which time any residual environmental impacts from the site will be reevaluated. The remedial design was approved by MDE by a letter dated July 20, 1992, subject to certain conditions stated in that letter. The Company responded by a letter dated August 6, 1992, objecting to certain conditions imposed by MDE; however, none of these issues is expected to delay implementation of the remedial design. In January 1993, after discussions between the Company and MDE, the monitoring portion of the remedial design was revised. MDE has approved additional revisions to the remedial action workplan, resulting in a substantial reduction in the overall cost of this project. The Company continues discussions with the MDE on the final stage of remediation addressing the ground-water contamination.
The cost of remediation is estimated to be approximately $250,000 in capital costs with yearly operating expenses of approximately $125,000. Based on these estimated costs, the Company recorded both a liability and a deferred regulatory asset of $642,092 on December 31, 1994, to cover the Company's projected remediation costs for this site. The liability payout for this site is expected to be over a five year period. As of 1994, the Company has incurred approximately $1,723,000 for remedial actions and environmental studies and has charged such costs to accumulated depreciation. In a previous rate proceeding, the Company requested and received recovery for all costs incurred as of November 30, 1988, through base rates, including both a ten year amortization of these costs and rate base treatment for the unamortized balance. As of 1994, the unamortized balance was approximately $201,586 which will be fully amortized by May 31, 1999. 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. Of the $1,723,000 in costs reported above, approximately $765,000 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.
(IV) (C) WINTER HAVEN COAL GAS SITE
The Company is currently conducting investigations of a site in Winter Haven, Florida, where the Company's predecessors manufactured coal gas earlier this century. A Contamination Assessment Report ("CAR") was submitted to the Florida Department of Environmental Protection ("FDEP") on July 11, 1990. The CAR contained the results of additional investigations of conditions at the site. These investigations confirmed limited soil and ground-water impacts to the site. By letter dated March 26, 1991, FDEP directed the Company to conduct additional investigations on-site to fully delineate the vertical and horizontal extent of soil and ground-water impacts.
Additional contamination assessment activities were conducted at the site in late 1992 and early 1993. On March 25, 1993, a Contamination Assessment Report Addendum ("CAR Addendum") was delivered to FDEP. The CAR Addendum concluded that soil and ground-water impacts have been adequately delineated as a result of the additional field work. The FDEP approved the CAR and CAR Addendum in March of 1994. The next step is a Risk Assessment ("RA") and a Feasibility Study ("FS") on the site. The RA and FS are expected to be filed with the FDEP during the first six months of 1995 at an estimated cost of $54,000. Until the RA and FS are completed and accepted as final by the FDEP, it is not possible to determine whether remedial action will be required by FDEP and, if so, the cost of such remediation.
The Company has spent approximately $595,000, as of December 31, 1994, on these investigations, and expects to recover these expenses, as well as any future expenses, through base rates. These costs have been accounted for as charges to accumulated depreciation. The Company requested and received from the Florida Public Service Commission ("FPSC") approval to amortize through base rates $359,659 of clean-up and removal costs incurred as of December 31, 1986. As of December 31, 1992, these costs were fully amortized. In January 1993, the Company received approval to recover through base rates approximately $217,000 in additional costs related to the former manufactured gas plant. This amount represents recovery of $173,000 of costs incurred from January 1987 through December 1992, as well as prospective recovery of estimated future costs which have not yet been incurred at that time. The FPSC has allowed for amortization of these costs over a three year period and provided for rate base treatment for the unamortized balance. In a separate docket before the FPSC, the Company has requested and received approval to apply a refund of 1991 overearnings of approximately $118,000 against the balance of unamortized environmental charges incurred as of December 31, 1992. As a result, these environmental charges were fully amortized as of June 1994. Of the $595,000 in costs reported above, all costs have received ratemaking treatment. It is management's opinion that future costs, if any, will be recoverable in rates.
(IV) (D) SMYRNA COAL GAS SITE
On August 29, 1989 and August 4, 1993, representatives of DNREC conducted sampling on property owned by the Company in Smyrna, Delaware. This property is believed to be the location of a former manufactured gas plant. Analysis of the samples taken by DNREC shows a limited area of soil contamination.
On November 2, 1993, DNREC advised the Company that it would require a remediation of the soil contamination under the state's Hazardous Substance Cleanup Act and submitted a draft Consent Decree to the Company for its review. The Company met with DNREC personnel in December 1993 to discuss the scope of any remediation of the site and, on January 3, 1994, submitted a proposed workplan, together with comments on the draft Consent Decree. Initial comments from DNREC on the Work Plan were received on March 2, 1994, appropriate revisions were prepared and the Work plan was resubmitted. Several additional sets of comments on the Work Plan were received from DNREC and the final Work Plan was submitted on September 27, 1994. DNREC has approved the Work Plan and the Consent Decree. Remediation based on the Work Plan, is scheduled to begin in 1995, at a cost of approximately $75,000. It is management's opinion that future costs, if any, will be recoverable in rates.
(V) EMPLOYEES
The Company has 320 employees including 144 natural gas distribution employees, 18 natural gas transmission employees, 92 propane distribution employees and 38 information technology services employees. The remaining 28 employees are considered general and administrative and include officers of the Company and treasury, accounting, marketing, human resources and other administrative personnel.
ITEM 2.
ITEM 2. PROPERTIES
(A) GENERAL
The Company rents office space for its corporate headquarters located in Dover, Delaware. The Company owns office and operations buildings in Salisbury, Cambridge, and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; and Winter Haven, Florida, and rents office space in Plant City, Florida; Chincoteague and Belle Haven, Virginia; Raleigh and Cary, North Carolina; Easton and Pocomoke, Maryland; and Atlanta, Georgia. In general, the properties of the Company are adequate for the uses for which they are employed. Capacity and utilization of the Company's facilities can vary significantly due to the seasonal nature of the natural gas and propane distribution businesses.
(B) NATURAL GAS DISTRIBUTION
Chesapeake owns over 482 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in its Delaware and Maryland service areas, and 454 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.
Nearly all of the properties constituting Chesapeake's distribution system are encumbered pursuant to Chesapeake's First Mortgage Bonds.
(C) NATURAL GAS TRANSMISSION
Eastern Shore owns approximately 271 miles of transmission lines extending from Parkesburg, Pennsylvania to Salisbury, Maryland. Eastern Shore also owns two compressor stations located in Daleville, Pennsylvania and Bridgeville, Delaware. The Daleville station is utilized to increase Columbia supply pressures to match Transco supply pressures, and to increase Eastern Shore's pressures in order to serve growing demands from Chesapeake's Delaware division. The Bridgeville station is being used to provide increased pressures required to meet the demands on the system.
(D) PROPANE DISTRIBUTION
Sharpgas owns bulk propane storage facilities with an aggregate capacity of 1,230,000 gallons at 26 plant facilities in Delaware, Maryland, and Virginia, located on real estate it either owns or leases.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Environmental disclosures are set forth in Part I, Item 1(c)(iv) of this 10- K, under "Environmental".
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.
ITEM 4.
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 52) (present term expires May 16, 1995). Mr. Adkins is President and Chief Executive Officer of Chesapeake. He has served as President and Chief Executive Officer since November 8, 1990. Prior to holding his present position, Mr. Adkins served as President and Chief Operating Officer, Executive Vice President, Senior Vice President, Vice President and Treasurer of Chesapeake. Mr. Adkins is also Chairman, President and Chief Executive Officer of Chesapeake Service Company, and Chairman and Chief Executive Officer of Sharp Energy, Inc. and Eastern Shore Natural Gas Company, all wholly owned subsidiaries of Chesapeake. He has been a director of Chesapeake since 1989.
John R. Schimkaitis (age 47) (present term expires May 16, 1995). Mr. Schimkaitis is Senior Vice President, Assistant Treasurer and Chief Financial Officer of Chesapeake. He previously served as Vice President, Treasurer and Chief Financial Officer from 1987 to 1992 and has served as Assistant Secretary from 1986 to 1992. 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.
Jeremy D. West (age 45) (present term expires May 16, 1995). Mr. West is the President of Sharp Energy, Inc. and Vice President of Chesapeake. He joined Sharp Energy in 1990 as President and in May 1992 was elected Vice President of Chesapeake. Mr. West was Vice President of Marketing from March 1987 to March 1989, and President from March 1989 to June 1990, of Columbia Propane Corporation, a subsidiary of Columbia Gas System. Previously, Mr. West was with Suburban Propane Gas Corp. as Regional Manager from September 1985 to March 1987.
Jack E. Reinhard (age 47) (present term expires May 16, 1995). Mr. Reinhard joined Chesapeake in 1988 as Superintendent of Division Operations, and in 1990 was promoted to General Manager of Natural Gas Operations. In May 1992, he was elected Vice President of Chesapeake. Mr. Reinhard was previously employed by Southern Union Gas Company, a division of Southern Union Corporation.
Kenneth H. Dean (age 55) (present term expires May 16, 1995). Mr. Dean joined Chesapeake in May 1994 as Senior Vice President of Corporate Development and Planning. He was previously employed for 11 years with Stone and Webster Management Consultants, must recently as Senior Vice President. Prior to that, Mr. Dean served as Executive Vice President of Mobile (Alabama) Gas Service Corporation.
Philip S. Barefoot (age 47) (present term expires May 16, 1995). Mr. Barefoot joined Chesapeake as Division Manager of Florida Operation in July 1988. In May 1994 he was elected Senior Vice President of Natural Gas Operations, as well as President of Eastern Shore Natural Gas Company. Prior to joining Chesapeake, he was employed with Peoples Natural Gas Company where he held the positions of Division Sales Manager, Division Manager and Vice President of Florence Operations.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS
(A) COMMON STOCK DIVIDENDS AND PRICE RANGES:
The following table sets forth sale price and dividend in formation for each calendar quarter during the years December 31, 1994 and 1993:
The common stock of the Company trades on the New York Stock Exchange under the symbol "CPK".
(B) APPROXIMATE NUMBER OF HOLDERS OF COMMON STOCK AS OF DECEMBER 31, 1994:
(C) DIVIDENDS:
During the years ended December 31, 1994 and 1993, cash dividends have been declared each quarter, in the amounts set forth in the table above.
Indentures to the long-term debt of the Company and its subsidiaries contain a restriction that the Company cannot, until the retirement of its Series I Bonds, pay any dividends after December 31, 1988 which exceed the sum of $2,135,188 plus consolidated net income recognized on or after January 1, 1989. As of December 31, 1994, the amounts available for future dividends permitted by the Series I covenant are $5,669,300.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
The Company's capital requirements reflect the capital intensive nature of its business and are attributable principally to its construction program and the retirement of its outstanding debt. The Company relies on cash generated from operations and short-term borrowings to meet normal working capital
requirements and to temporarily finance capital expenditures. During 1994, the Company's net cash provided by operating activities, net cash used by investing activities and net cash used by financing activities were $14,381,011, $10,424,411 and $4,720,646, respectively.
The Board of Directors has authorized the Company to borrow up to $14,000,000 from various banks and trust companies. As of December 31, 1994, the Company had four unsecured bank lines of credit each in the amount of $8,000,000. Funds provided from these lines of credit are used for short-term cash needs to meet seasonal working capital requirements and to fund portions of its capital expenditures. The outstanding balances of short-term borrowings at December 31, 1994 and 1993 were $8,000,000 and $8,900,000, respectively. Based upon anticipated cash requirements in late 1995, the Company may refinance the short-term debt through the issuance of common equity, long-term debt or a combination thereof. The timing of such an issuance is dependent upon the nature of the securities involved as well as current market and economic conditions.
CAPITAL EXPENDITURES
In 1994 and 1992 the Company's capital additions were funded from operations, unlike 1993 when funding was provided by operations and financing activities. In 1994, cash provided by operations increased due to the collection of a large amount of underrecovered purchase gas costs present at the end of 1993. Cash provided by operations in 1993 was lower than 1992 due, in part, to a large accounts payable amount that was outstanding at the end of 1992 and paid in 1993 along with an increase in the amount of underrecovered purchase gas costs.
During 1994, 1993 and 1992, capital expenditures were approximately $10,653,000, $10,064,000 and $6,720,000, respectively. For 1995, the Company has budgeted $16,556,000 for capital expenditures. The breakdown of this amount is $11,682,000 for natural gas distribution, $1,651,000 for natural gas transmission, $1,734,000 for propane distribution, $452,000 for information technology services and $1,037,000 for Skipjack, Inc. and other. The natural gas and propane expenditures are for expansion and improvement of their existing service territories. The information technology services expenditures are for computer hardware, software and related equipment. The majority of expenditures for Skipjack are for construction and improvements. Financing for the 1995 construction program will be provided primarily using short-term borrowings and cash from operations. The construction program is subject to continuous review and modification. Actual construction expenditures may vary from the above estimates due to a number of factors including inflation, changing economic conditions, regulation, load growth, and the cost and availability of capital.
GROSS PROPERTY, PLANT & EQUIPMENT
The Company expects to incur environmental related expenditures in the future (see Note K to the Consolidated Financial Statements), a portion of which may need to be financed through external sources.
Management does not expect such financing to have a material adverse effect on the financial position or capital resources of the Company.
Capital Structure
As of December 31, 1994, common equity represented 60.4% of permanent capitalization, compared to 57.6% in 1993 and 56.3% in 1992. The Company remains committed to maintaining a sound capital structure and strong credit ratings in order to provide the financial flexibility needed to access the capital markets when required. This commitment, along with the adequate and timely rate relief for the Company's regulated operations, helps to ensure that the Company will be able to attract capital from outside sources at a reasonable cost. The achievement of these objectives will provide benefits to customers and creditors, as well as to the Company's investors.
Financing Activities
The Company issued no long-term debt in 1994. During the first quarter of 1993, the Company issued $10,000,000 of 7.97% senior notes due on February 1, 2008. The Company used a portion of the funds to repay the short-term borrowing balance outstanding (see Note F to the Consolidated Financial Statements). In April 1993, the Company used the remaining funds, along with available short- term borrowings, to repay $3,600,000 of the Company's 10.45% Series H First Mortgage Bonds. These Bonds were originally due April 1, 2001. During the year, the Company repaid a total of approximately $1,291,000 of long-term debt, compared to $5,026,000 and $2,667,000 in 1993 and 1992, respectively. The 1992 repayment of long-term debt includes a prepayment, using available short-term borrowing, of $900,000 to retire the Company's 12.50% Series F First Mortgage Bonds. These Bonds were originally due in 1998. The Company issued no long-term debt in 1992.
COMMON EQUITY
The Company issued 30,928, 27,942 and 12,546 shares of common stock in connection with its Automatic Dividend Reinvestment and Stock Purchase Plan during the years of 1994, 1993 and 1992, respectively. In 1993, the Company realized an increase in the number of shares issued from the Plan due to an increase in the level of optional cash payments from existing stockholders as well as the option made available in the fourth quarter of 1992 which allows employee stock purchases through payroll deductions.
The Company began utilizing treasury stock during the second half of 1993 to fund the monthly Company matching contribution to the Retirement Savings Plan. In 1994 and 1993, 14,475 and 4,808 shares respectively, were utilized, leaving 15,609 shares of treasury stock available. In 1995, the Company anticipates the continued use of treasury stock to administer the Company's Retirement Savings Plan.
Results of Operations
Net income for 1994 was $4,459,922, an increase of $488,251 from 1993 earnings of $3,971,671 which included $57,467 for the cumulative effect of a change in accounting for income taxes (see Note A to the Consolidated Financial Statements). Net income for 1993 also increased over 1992 earnings by $423,162. Earnings for 1992 include income of $73,500 for the reversal of the estimated loss from discontinued operations recorded in 1991 from our oil distribution business (see Note B to the Consolidated Financial
Statements). Earnings before interest and taxes ("EBIT") increased by $1,456,000 or 17.5% in 1994 after increasing by $412,000 or 5.2% in 1993.
NET INCOME
Natural Gas Distribution
The natural gas distribution segment contributed EBIT of approximately $4.7 million for 1994 as compared to $4.1 million in 1993 and $4.4 million in 1992. The 14.1% increase in 1994 EBIT was the result of a 6.2% increase in gross margin partially offset by an increase in operating expenses. The decrease in 1993 EBIT as compared to 1992 was the result of an increase in operating expenses, offset by an increase in gross margin.
Operating revenues increased to $49.6 million in 1994 from $44.3 million in 1993 after increasing from $42.0 million in 1992. Cost of gas was $32.4 million, $28.1 million and $26.1 million in 1994, 1993 and 1992, respectively. The 1994 increase in revenue and cost of gas is primarily due to the first full year of natural gas brokering operations for large industrial users and local distribution companies in Florida. Overall, the brokering of gas provided a minimal increase in gross margin for 1994. In addition, the Florida division has increased sales to its phosphate producing and citrus processing customers and two electric co-generation plants, which began operation in the first quarter of 1994. Despite temperatures being 6.5% warmer than last year, deliveries in the northern territories to residential and commercial customers increased 5.1% because of the timing and magnitude of colder weather in the first quarter of 1994. The 1993 increase was the result of an increase in Florida's transportation volumes. This was partially offset by a 25.7% reduction in interruptible sales volume due to competition from alternative fuel services and Florida industrial customers switching to transportation services.
REVENUES
Operating expenses increased by $418,000 in 1994 after increasing by $596,000 in 1993. The 1994 increase was due primarily to higher payroll, customer accounting and maintenance of meter and regulating stations offset partially by a reduction in employee pension and benefits, legal fees, regulatory expenses and the absence of the one-time expense of listing of our stock on the NYSE in the first quarter of 1993. The 1993 increase was due primarily to higher sales expenses, employee benefit expenses, legal fees and the NYSE fees for listing the Company's stock. Depreciation and property taxes increased in 1994 and 1993 due to plant additions during the years.
NUMBER OF CUSTOMERS
Natural Gas Transmission
The natural gas transmission operations contributed EBIT of approximately $3.0 million for 1994 as compared to $3.1 million in 1993 and $2.7 million in 1992. The 2% decrease in 1994 EBIT was the result of an increase in operating expenses exceeding the slight increase in gross margin. The increase in 1993 EBIT was the result of an increase in gross margin partially offset by a slight increase in operating expenses.
Operating revenues increased to $39.5 million in 1994 from $37.4 million in 1993 after increasing from $29.5 million in 1992. The 1994 and 1993 increases in operating revenues were partially offset by increases in cost of gas of $1.9 million in 1994 and $7.5 million in 1993. The net effect of the increases in revenue and cost of gas is an increase in gross margin of $113,000 in 1994 and $404,000 in 1993. However, the prior period component of the reserve for refund recorded during the second quarter of 1994 (see Note L to the Consolidated Financial Statements) has the impact of understating 1994 margins by $412,000. This $412,000 accrual was recorded to adjust on a cumulative basis, the 1993 and 1992 margins as originally recorded on the books. Had the reserve been recorded in the years that the revenue was actually generated, 1994 gross margin would have increased by $871,000 over 1993, not $113,000.
The 1994 increase in revenue was due to a combination of factors including an increase in industrial interruptible sales volumes of 33%, an increase in contract demand levels effective November 1993, partially offset by a 9.4% decrease in the commodity cost of gas, which was passed on to our customers. The majority of the industrial interruptible sales volumes increase was attributable to one industrial customer, which purchased natural gas, instead of higher price alternative fuels. The increased sales to this customer contributed $533,000 and $91,000 for the years 1994 and 1993, respectively. It is expected that this customer will not continue to contribute to gross margin at the 1994 levels. Deliveries to our large methanol producing industrial customer were up 8.3% over the same period last year; however, margins earned were lower. The 1993 increase in revenue was due to an increase in the cost of gas and an 81% increase in interruptible sales volumes which was primarily due to deliveries to the methonal plant.
Operating expenses increased by $187,000 in 1994 after increasing by $44,000 in 1993. Depreciation and taxes other than income increased in both 1994 and 1993. Depreciation expense increased from $604,000 to $641,000 from 1992 to 1994, primarily due to plant additions being placed in service during those periods.
BOOK VALUE PER SHARE
Other taxes also increased from $298,000 in 1992 to $352,000 in 1994 due to property taxes associated with the above plant additions. Maintenance expenses increased by $125,000 due to the painting of a bridge structure and cathodic protection related maintenance costs to the pipeline. Administrative expenses increased slightly over 1993 as a result of an increase in payroll, legal fees and telemetering communication expenses. This was partially offset by a reduction in sales expense, employee pension and benefits and the other administrative expenses.
In 1993, the FERC began reevaluating the methodology being used by Eastern Shore in calculating its purchased gas adjustment ("PGA"). PGA clauses provide for the adjustment of rates charged to customers as gas costs fluctuate. In May 1994, the FERC issued an Order directing Eastern Shore to refund, with interest, what the FERC characterized as overcharges from November 1992 to the current billing month. In June 1994, Eastern Shore filed a request for rehearing of the Order based upon Eastern Shore's belief that the Order essentially requires a retroactive change to the FERC approved PGA tariff. In July 1994, the FERC
issued an "Order Granting Rehearing Solely For The Purpose of Further Consideration." This Order was issued only to afford the FERC additional time for consideration of the issues raised in Eastern Shore's request for rehearing.
TOTAL CAPITALIZATION
Eastern Shore has indicated to the FERC staff that it intends on filing an offer of settlement to resolve all of the FERC's concerns. The ultimate outcome of these proceedings cannot be forecasted with any degree of certainty and accordingly Eastern Shore has accrued $1,283,000 for the potential refund.
Propane
For 1994, the propane segment realized record earnings, achieving an increase in EBIT of $699,000 or 44% over 1993's results. This increase in EBIT resulted from an increased gross margin, offset partially by higher operating costs. Although not as dramatic as 1994, the results for 1993 were also positive, with the segment recognizing an increase in EBIT of $149,000 over 1992. Like 1994, the increase in 1993's EBIT was attributable to an increased gross margin partially offset by higher operating expenses.
Comprising the increase in 1994's gross margin were several factors. The segment recognized volume growth of 6.6% and a 2.7% increase in the gross margin per gallon. The volume growth was principally a result of the timing and severity of cold weather experienced in the first quarter of 1994, despite temperatures for the year being 6.5% warmer than 1993. The increase in gross margin per gallon resulted from a lower average cost per gallon, primarily a result of more competitive supply contracts, offset partially by a lower average selling price per gallon, largely due to competition. Finally, additional margin comprising approximately 7.8% of the increase in total gross margin was obtained from one large wholesale customer to which the segment supplied 9 million gallons of propane in 1994.
Operating expenses in 1994 increased by 1.7%. Of this modest increase, the majority of it represented expenses which were a direct result of the severe weather as well as normal customer growth, including salaries for service and delivery personnel and associated vehicle fuel and maintenance costs. Increased expenses were also incurred for consulting services and higher insurance claims. Partially offsetting these higher costs were lower employee benefit costs.
For 1993, the increase in gross margin resulted from a slight growth in volume, as well as an 8.3% increase in the gross margin per gallon. The volume growth was a direct result of temperatures being 1.3% colder than 1992. The increase in gross margin was the result of a reduction in the segment's average cost per gallon. Operating expenses rose approximately 8%, of which the majority corresponded to non-recurring programming costs, increased advertising expenses, and higher insurance costs. Inherent within this 8% expense growth is a recovery of bad debts expense, which was achieved as a result of improved collection procedures; a recovery was also recognized in 1994, although not to the extent of that recorded in 1993.
EARNINGS PER SHARE
Information Technology Services and Other
The information technology services and other segment recognized an increase of $17,000, or 10.9%, in EBIT for 1994. This increase is directly attributable to an increase in EBIT of $169,000 for United Systems, Inc. ("USI"), partially offset by decreases in EBIT of $130,000 and $40,000 for Capital Data Systems, Inc. ("CDS") and Currin and Associates, Inc. ("C&A"), respectively. For 1993, the segment recognized an increase in EBIT of approximately $536,000 over 1992. Comprising this escalation were increases in EBIT of $474,000 and $66,000 for CDS and USI, respectively, partially offset by a small reduction in C&A's EBIT.
Contributing to the 1994 increase in EBIT for USI were higher revenues of $742,000, primarily relating to programming and consulting. Salaries, benefits, and other normal operating expenses for USI rose by $573,000, in response to these increased sales. For CDS, the increase in 1994's operating expenses of $1,127,000 surpassed the increase in revenues of $997,000. Although a majority of these expenses are a direct result of the increase in revenue, the balance of the increased expenses represents the absence of any capitalized payroll costs for software development in 1994. Slightly offsetting these expenses were reductions in depreciation expense and employee benefit costs.
The total increase in revenues of $997,000 for 1994 represents sales to external customers. During 1994, CDS recognized revenues of $1,227,000 associated with the ongoing development of the natural gas distribution segment's customer billing system, UtiliCIS. This compares closely to $1,239,000 for 1993. For these amounts, it is Chesapeake's policy to eliminate the corresponding portion of EBIT, which represented $468,000, $651,000, and $257,000 for 1994, 1993 and 1992, respectively. Chesapeake will reverse this eliminated EBIT once the project is complete and the natural gas distribution segment begins depreciating the system. Finally, as a result of declining revenue and business prospects, Chesapeake disposed of its investment in C&A in 1994. Contributing to the increase in 1993's EBIT for CDS were increased revenues of $1,306,000, of which approximately $815,000, or 62.4% correspond to intercompany billings. Offsetting this rise in revenues were increased operating expenses associated with higher programming and payroll costs as well as increased maintenance and depreciation expenses on various pieces of computer hardware. For USI, the increase in 1993's EBIT stemmed from higher consulting and programming revenues of $743,000, partially offset by higher salaries, benefits, and consulting fees of $677,000. In 1993, the net reduction in C&A's EBIT was minimal, approximately $9,000 or 9.6%.
Other
Non-operating income was approximately $16,000 in 1994 as compared to $265,000 in 1993. The 1994 decrease is primarily due to the disposition of its investment in Currin & Associates and the 1993 increase of $140,000 from interest associated with upstream supplier refunds. The 1993 decrease as compared to 1992 is primarily due to a non-recurring gain of $382,000 on the sale of Company-owned rental property which occurred in 1992, somewhat offset by the interest from upstream supplier refunds received in 1993.
DIVIDENDS PER SHARE
Environmental Matters
The Company continues to work with federal and state environmental agencies to assess the environmental impacts and explore corrective action at several former gas manufacturing plant sites (see Note K to the Consolidated Financial Statements). The Company believes that any future costs associated with these sites will be recoverable in rates.
FERC Order 636
In April 1992, the FERC issued Order No. 636 ("Order") to be effective November 1, 1993. The Order requires that pipelines restructure their services and operations in an attempt to enhance competition and maximize the benefits of wellhead price deregulation. The restructuring will force pipelines to incur transition costs. Pipelines will be allowed to recover prudently incurred transition costs from customers after approval by the FERC.
Currently, the Company is unable to determine what future transition costs will be incurred by Eastern Shore and the effect, if any, that these costs will have on its financial position. The Company's Florida distribution division is currently being billed transition costs from Florida Gas Transmission. The Company is recovering all transition costs incurred through the purchased gas adjustment (see note L to the Consolidated Financial Statements).
Competition
Historically, the Company's natural gas operations have successfully competed with other forms of energy such as electric, oil and propane. The principal considerations have been price and to a lesser extent, accessibility. However, natural gas shows great potential for increased sales as a vehicle fuel and for electric power generation because of its environmentally superior qualities, its production from domestic sources and endorsements received by government officials. Since Eastern Shore has not elected to be an "open access" pipeline, the Company is not subject to the competitive pressures, on the Delmarva Peninsula, of FERC Order No. 636.
Both the propane distribution and the information technology businesses face significant competition from a number of larger competitors having substantially greater resources available to them than the Company. In addition, in the information technology business, changes are occurring rapidly which could adversely impact the markets for the Company's products and services.
Inflation
Inflation impacts the prices the Company must pay for labor and other goods and services required for operation, maintenance and capital improvements, although in recent years, the impact of inflation has lessened. Purchased gas costs, which have been relatively stable, are passed on to customers through the purchased gas adjustment clause in the Company's tariff. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from its regulatory commissions for its regulated segments and constantly monitors the returns of its unregulated business segments.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
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To the Shareholders of Chesapeake Utilities Corporation
We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation and Subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, cash flows, stockholders' equity, and income taxes for each of the three years in the period ended December 31, 1994, and the consolidated financial statement schedules listed in Item 14(a)(1) and (2) of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's Management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimate made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Chesapeake Utilities Corporation and Subsidiaries as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. In addition, in our opinion, the consolidated financial schedules referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As discussed in Note A to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for income taxes.
We have also previously audited, in accordance with generally accepted standards, the consolidated balance sheets as of December 31, 1992, 1991, and 1990, and the related consolidated statements of income, cash flows, stockholders' equity, and income taxes for each of the two years in the period ended December 31, 1991, (none of which are presented herein); and we expressed unqualified opinion on those financial statements. In our opinion, the information set forth in the Selected Financial Data section, for each of the five years in the period ended December 31, 1994, is fairly stated in all material respect in relation to the financial statements from which it has been derived.
Coopers & Lybrand, L.L.P.
Baltimore, Maryland February 10, 1995
CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes
CONSOLIDATED BALANCE SHEETS
See accompanying notes
CONSOLIDATED BALANCE SHEETS
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-------- (1) Dividends per share of common stock were $.88, $.86 and $.86 for the years 1994, 1993 and 1992, respectively. (2) Net of income taxes of approximately $160,000, $60,000 and $21,000 for the years 1994, 1993 and 1992, respectively.
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME TAXES
-------- (1) Total deferred income tax expense includes $66,000, $38,000 and $99,000 of deferred state income taxes for the years 1994, 1993 and 1992, respectively.
See accompanying notes
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements of Chesapeake Utilities Corporation (the "Company") include the Company's subsidiaries: Eastern Shore Natural Gas Company ("Eastern Shore"), Sharp Energy, Inc. ("Sharp Energy") and Chesapeake Service Company ("Chesapeake Service"). Eastern Shore's accounts include those of its wholly owned subsidiary, Dover Exploration Company ("Dover Exploration"). Sharp Energy's accounts include those of its wholly owned subsidiaries, Sharpgas, Inc. ("Sharpgas") and Sharpoil, Inc. ("Sharpoil"). Chesapeake Service's accounts include those of Capital Data Systems, Inc. ("CDS"), Currin and Associates, Inc. ("C&A"), United Systems, Inc. ("USI"), Skipjack, Inc. ("Skipjack") and Chesapeake Investment Company ("Chesapeake Investment").
All intercompany transactions have been eliminated in consolidation.
System of Accounts
The natural gas distribution divisions of the Company located in Delaware, Maryland and Florida are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore is subject to regulation by the Federal Energy Regulatory Commission ("FERC") and the Delaware Public Service Commission. The Company's financial statements are prepared on the basis of generally accepted accounting principles which give appropriate recognition to the ratemaking and accounting practices and policies of the various commissions. The propane and information technology services subsidiaries are not subject to regulation with respect to rates or maintenance of accounting records.
Cash and Cash Equivalents
The Company's policy is to invest cash in excess of operating requirements in overnight income producing accounts. Such amounts are stated at cost which approximates market. Investments with an original maturity of three months or less are considered cash equivalents.
Property, Plant and Equipment and Depreciation
Utility property is stated at original cost while the assets of the propane subsidiary are valued at cost. The costs of repairs and minor replacements are charged as incurred to the appropriate operating expense 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 the income statement.
The provision for depreciation is computed using the straight-line method at rates which will amortize the unrecovered cost of depreciable property over the estimated useful life. Depreciation and amortization expense for financial statement purposes is provided at an annual rate averaging 4.5% for natural gas distribution, 2.8% for natural gas transmission, 5.2% for propane distribution, 6.2% for gas plant acquisition adjustments and 14.4% for information technology services and other.
Allowance for Funds Used During Construction
The allowance for funds used during construction ("AFUDC") is an accounting procedure whereby the cost of borrowed funds and other funds used to finance construction projects is capitalized as part of utility plant on the balance sheet, crediting the cost as a non-cash item on the income statement. The cost of borrowed and equity funds is segregated between interest expense and other income, respectively. The Company used
rates of 4.23% in 1994, 3.52% in 1993 and 4.05% in 1992 for calculating AFUDC on borrowed funds. In 1994, AFUDC for equity funds was calculated using an average rate of 2.92%.
Other Deferred Charges
Other deferred charges include discount, premium and issuance costs associated with long-term debt, restricted stock earned for services performed but not yet awarded and rate case expenses. The discount, premium and issuance costs are deferred and amortized over the lives of the respective debt issues. Rate case expenses are deferred and amortized over periods approved by the applicable regulatory authorities.
Income Taxes and Investment Tax Credit Adjustments
The Company files a consolidated federal income tax return. Income tax expense allocated to the individual companies 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 basis of assets and liabilities, and is measured using current effective income tax rates. The portion of the Company's deferred tax liabilities applicable to utility operations which has not been reflected in current service rates represents income taxes recoverable through future rates.
Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
Effective January 1, 1993 the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 109 "Accounting for Income Taxes." The adoption of SFAS No. 109 changed the method of accounting for income taxes from the deferred method to the asset and liability approach. In adopting SFAS No.109, the Company elected to restate its financial statements in order to include the tax consequences on the amounts paid in excess of original cost in gas plant acquisition adjustments for prior utility acquisitions. Restated prior years' financial statements have not been presented due to the immaterial impact of SFAS No. 109. The principal effect on the Company's financial statements of adopting SFAS No. 109 was the recording of deferred regulatory assets and liabilities.
The deferred regulatory assets consist primarily of income taxes on temporary depreciation differences, which were previously flowed through to ratepayers. Deferred regulatory assets were approximately $885,000 and $931,000 at December 31, 1994 and 1993, respectively. The deferred regulatory liabilities primarily represent excess deferred income tax credits resulting from the reduction in the federal income tax rate and also deferred tax credits provided on investment tax credits which were previously flowed through to ratepayers. Deferred regulatory liabilities were approximately $1,233,000 and $1,322,000 at December 31, 1994 and 1993, respectively.
Changes in accumulated deferred income taxes related to the Company's non- regulated operations have been recorded as a cumulative effect of change in accounting principle on the income statement and a deferred tax asset on the balance sheet. The result was a one-time increase to net income of $57,467. The increase to net income resulted from a reduction in the deferred income taxes associated with depreciation, coupled with the recording of net state tax loss carryforwards. The Company has state tax loss carryforwards of $5,529,000 and $8,753,000 at December 31, 1994 and 1993, respectively. The Company has recorded valuation allowances of $153,000 and $255,000 at December 31, 1994 and 1993, respectively. The loss carryforwards expire in various years beginning in 1997 through 2007.
Operating Revenues
Revenues for the natural gas distribution divisions of the Company and a portion of Eastern Shore revenues are based on rates approved by the various commissions. Customers' base rates may not be changed without formal approval of these commissions. The Company, except for its Florida division, recognizes
revenues from meters read on a monthly cycle basis. This practice results in unbilled and unrecorded revenue from the cycle date through month-end. The Florida division recognizes revenues based on services rendered and records an amount for gas delivered but not billed.
The natural gas distribution divisions of the Company and Eastern Shore have purchased gas adjustment clauses that provide for the adjustment of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.
Intangible Assets
Intangible assets are associated with the acquisition of non-utility companies, and are being amortized on a straight-line basis. At December 31, 1994 and 1993, the balances and amortization periods for these assets were as follows:
Earnings Per Share
Earnings per common share are based on the weighted average number of shares of common stock outstanding for each year presented. The dilutive effect of the Company's common stock equivalents related to convertible debentures is insignificant.
Reclassification of Prior Years Amounts
Certain prior years' amounts have been reclassified to conform with 1994 presentation.
B. DISCONTINUED OPERATIONS
During 1992, the Company consummated the sale of all the remaining assets of Sharp Energy's oil products distribution subsidiary, Sharpoil. The Company's decision to discontinue the operations of Sharpoil resulted in a charge to fourth quarter 1991 earnings of $500,000, which represented the estimated after-tax loss on the disposal of Sharpoil's assets and the expected loss on operating the business up to the time that the assets were sold. The actual loss incurred in 1992 was $426,500. The remaining $73,500 of the estimated loss was reversed in the fourth quarter of 1992 and is included as income from discontinued operations in the 1992 consolidated statement of income. Sharpoil revenues in 1992 were approximately $595,000.
C. WRITE-OFF OF INVESTMENT
In 1994, based on declining revenue and business projections, the Company disposed of its investment in Currin and Associates, Inc. ("C&A"), a rate and regulatory consulting subsidiary acquired in 1988. Revenue declined from a high of $593,000 in 1992 to a low of $51,000 for 1994. The disposition has resulted in a $260,000 after tax loss recorded to Other Income and Deductions on the income statement. The loss resulted from the write-off of goodwill and the disposition of other assets.
D. SEGMENT INFORMATION
The Company is engaged in natural gas distribution and transmission, propane distribution and information technology services. Information concerning these segments of the Company is stated below. The information provided pertains only to continuing operations except where noted otherwise. All intersegment revenues have been eliminated from consolidated revenues. During 1994 and 1992, no individual customer accounted for 10% or more of revenues. In 1993, the Company had sales to one customer which exceeded 10% of total revenue. Total sales to this industrial interruptible customer of our transmission segment were approximately $9,600,000 or 11.2% of total revenue.
E. INVESTMENTS
The investment balance at December 31, 1994 and 1993 consists primarily of the common stock of Florida Public Utilities Company ("FPU"). The Company's ownership at December 31, 1994 and 1993 represents a 6.84% and 6.50% interest, respectively. The Company adopted Statement of Financial Accounting Standards ("SFAS") No. 115 "Accounting for Certain Investments in Debt and Equity Securities" effective January 1, 1994, as required. SFAS No. 115 addresses the accounting and reporting for investments in equity securities that have readily determinable fair values. 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 tax as a separate component of stockholders' equity. The adoption of SFAS No. 115 had no effect on the Company's 1994 results of operation. The aggregate cost basis of the Company's portfolio at December 31, 1994 and 1993 exceeded its market value by $401,609 and $150,517, respectively. In management's opinion, the decline in the value of the stock is a temporary decline. At December 31, 1994 and 1993, the investment was stated at the lower of cost or market, and was reported net of tax as a separate component of stockholders' equity.
F. LEASE OBLIGATIONS
The Company has entered into several operating leases for office space at various locations. Rent expense related to these leases was $418,043, $439,445 and $472,148 for 1994, 1993 and 1992, respectively. Future minimum payments under the Company's lease agreements are $361,823 in 1995; $295,276 in 1996; $111,041 in 1997; $31,800 in 1998; $33,400 in 1999 and $96,000 thereafter.
G. LONG-TERM DEBT
The outstanding long-term debt, net of current maturities is as follows:
The Series G bonds are subject to an interest rate equal to seventy-three percent (73%) of the prime rate (8.5% and 6.00% at December 31, 1994 and 1993, respectively).
The convertible debentures may be converted, at the option of the holder, into shares of the Company's common stock at a conversion price of $17.01 per share. During 1994, $5,000 in debentures were converted. The debentures are redeemable at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000 in the aggregate. As of December 31, 1994, $113,000 of the debentures have been accepted for redemption. At the Company's option, the debentures may be redeemed at the stated amounts.
On February 9, 1993, the Company issued $10,000,000 of 7.97% senior notes due on February 1, 2008. The Company used a portion of the proceeds to repay $8,700,000 in short-term borrowings. On April 1, 1993, the Company repayed $3,600,000 of the 10.45% Series H bonds. These bonds were originally due April 1, 2001.
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 times and 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, 1994, the amounts available for future dividends permitted by the Series I covenant approximated $5,669,300.
Substantially all of the natural gas distribution plant assets owned by the Company are subject to a lien under the mortgage pursuant to which the Company's first mortgage sinking fund bonds are issued.
Annual maturities of consolidated long-term debt are as follows:
H. COMMON STOCK, ADDITIONAL PAID-IN CAPITAL AND TREASURY STOCK
The following is a schedule of changes in the Company's shares of common stock:
-------- * 12,000,000 shares authorized at a par value $.4867 per share.
As part of the USI acquisition, certain key USI employees entered into restricted stock award agreements under which shares of Chesapeake common stock can be issued. The issuance of these shares is treated as a non-cash transaction on the consolidated statements of cash flow. Shares are awarded over a five year period beginning in 1992, and restrictions lapse over a five to ten year period from the award date, if certain financial targets are met. Based on 1994 USI earnings, 14,138 shares of Chesapeake common stock will be issued in 1995. Of these shares, 2,828 will have no restrictions, other than those that may be imposed by federal or state securities laws.
In addition, 48,716 shares from the previous awards, originally valued at $696,679, remain restricted and are shown as a reduction of stockholders' equity at December 31, 1994. As of December 31, 1993, 47,638 shares, valued at $663,557, remained restricted and were shown as a reduction of stockholders' equity.
The Performance Incentive Plan, which was adopted in 1992, provides for the granting of stock options to certain officers of the Company over a 10 year period. Changes in outstanding options were as follows:
I. SHORT-TERM BORROWING
The Board of Directors has authorized the Company to borrow up to $14,000,000 from various banks and trust companies. As of December 31, 1994, the Company had four $8,000,000 unsecured bank lines of credit, none of which required compensating balances.
A detail of short-term borrowings for 1994 and 1993 is as follows:
J. EMPLOYEE BENEFIT PLANS
Retirement Savings Plan
The Company offers a Retirement Savings Plan, a 401(k) plan, which provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions based upon eligible compensation. The Company makes a contribution equal to 60% of each participant's pre-tax contributions not to exceed 3.6% of the participant's compensation for the plan year. The Company's contributions totalled $240,103, $227,577 and $181,165 for the years ended December 31, 1994, 1993 and 1992, respectively.
Pension
The Company has a defined benefit pension plan covering substantially all of its employees. Benefits under the plan are based on each participant's years of service and highest average compensation. The Company's funding policy provides that payments to the trustee shall be equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974.
Total pension expense for the Company for 1994, 1993 and 1992 was approximately $387,700, $741,300 and $763,200, respectively. Pension expense decreased in 1994 because of a combination of factors including the (1) increase in the discount rate to 7% from 6.5%; (2) decrease in the rate used for average increase in future compensation levels to 5.5% from 6%; and (3) increase in the expected long-term rate of return on assets to 8.5% from 7.5%.
Total Net Pension Cost
The following schedule sets forth the funding status of the pension plan at December 31, 1994 and 1993:
Accrued Pension Cost
Other Postretirement Benefits
The Company sponsors a defined benefit postretirement health care and life insurance plan which covers substantially all natural gas and corporate employees. Effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions", which requires that the expected cost of these future benefits be included in the financial statements during the years employees render service. The implementation of SFAS No. 106 resulted in an accumulated postretirement benefit obligation (transition obligation) related to past employee service of $2,215,000. As permitted, the Company elected to amortize this cost over 20 years instead of expensing the total benefit obligation in 1993. The Company's 1993 cost under SFAS No. 106, including the amortization of the transition obligation, was $400,000. In the first quarter of 1994, the Company increased the amount that future retirees would be required to contribute to participate in the Company's health care program. The effect of the change in future employee contributions reduced the Company's transition obligation and annual costs to $357,000 and $70,000, respectively. The change also resulted in a one-time curtailment loss of $64,000 in 1994.
The health care inflation rate for 1994 and 1993 is assumed to be 12.0%. This rate is projected to gradually decrease to an ultimate rate of 5.5% by the year 2007. A one percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $61,000 as of January 1, 1995, and would increase the aggregate of the service cost and interest cost components of net periodic other postretirement benefit cost for 1995 by approximately $6,000.
The Company deferred approximately $35,000 and $92,000 in 1994 and 1993, respectively. These amounts represent the difference between the Maryland divisions' SFAS No. 106 expense and its actual pay-as-you-go cost. The Company expects the amount deferred would ultimately be recovered, since the Maryland Public Service Commission has allowed rate recovery for the accrual treatment of SFAS No. 106 costs in rate case decisions rendered for other utilities.
The following tables set forth the status of the plan at December 31, 1994 and 1993:
Accrued Postretirement Benefit Liability
Other Post Employment Benefits
In 1994, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 112, "Employers' Accounting for Postemployment Benefits", as required. SFAS No. 112 establishes standards of financial accounting and reporting for the estimated cost of benefits provided by an employer to former or inactive employees after employment but before retirement. The adoption of SFAS No. 112 did not have a material effect on the Company's results of operations.
K. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES
The Company currently is participating in the investigation, assessment, or remediation of several former gas manufacturing plant sites, located in different jurisdictions, including the exploration of corrective action options to remove environmental contaminants. The Company has accrued liabilities for two of these sites, the Dover Gas Light and Salisbury Town Gas Light sites.
The Dover site has been listed by the Environmental Protection Agency Region III ("EPA") on the Superfund National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"). In 1993, both the Company and EPA proposed remedial action plans for the site. In the fourth quarter of 1993, the Company recorded a liability of $700,000, representing the estimated liability for future environmental expenditures associated with the Company's proposed plan, which was the least extensive remedial alternative set forth in the two plans. The EPA plan proposed a more extensive remediation, estimated to cost $4.9 million. On August 19, 1994, the EPA issued the Record of Decision ("ROD") for the site. The ROD selected a remedial plan that differed from both proposals, and estimated the costs of the selected remedy at $2.7 million for groundwater remediation and $3.3 million for soil remediation. In January 1995, Chesapeake submitted to the EPA a good faith proposal to perform a substantial portion of the work set forth in the ROD, which was subsequently rejected. It is unknown whether any other potentially responsible party ("PRP") will submit good faith proposals, what such proposals might include, and whether EPA would accept such proposals. Under CERCLA, EPA may reject any of the proposals, and seek an administrative or court order to require any or all of the PRPs to implement the work. EPA may also do the work itself and seek recovery of its costs in court.
In the third quarter of 1994, the Company increased its liability recorded with respect to the Dover site to $6.0 million. This amount reflects EPA's present estimate, as stated in the ROD, for remediation of the site according to the ROD. The Company and EPA are each attempting to secure voluntary performance of part of the remediation by other parties. These parties include the State of Delaware, which is the owner of the property and was identified in the ROD as a PRP, and a local business identified in the ROD as a PRP for having contributed to groundwater contamination. On March 6, 1995, in order to protect its interests, the Company filed suit in federal court for the determination that the State of Delaware is a liable party and for recovery from the State of costs of compliance with the ROD. The Company is also considering a suit against other potentially responsible parties. In addition, EPA has stated that it will take steps to secure prompt commencement of the remedial design phase needed to implement the ROD. The Company therefore anticipates further negotiations to resolve these matters among the parties and with the government. Management is also evaluating the ROD to determine the most economic approach to implementation of the remedies selected in the ROD. Favorable developments in these matters would be accompanied by appropriate reductions to the liability recorded as they occur.
The Company also increased the corresponding regulatory asset to $6.0 million. If the Company incurs expenses of that amount in connection with undertaking the remedies selected in the ROD, management believes that the Company will be equitably entitled to contribution from other responsible parties for the greater part of these expenses. Management also believes that any amounts not so contributed will be recoverable in the Company's rates.
The Company has accrued a liability with respect to the Salisbury site of $642,092 as of December 31, 1994. This amount is based on the estimated capital and operating cost as set forth in the Company's remedial action plan submitted to the Maryland Department of the Environment ("MDE"). A corresponding regulatory asset has been recorded, reflecting the Company's belief that costs incurred will be recoverable in rates. The Company has begun preliminary remediation procedures at the site and continues discussions with MDE to finalize the remedial plan. The current liability has been reduced from the liability of $975,000 recorded in the fourth quarter of 1993, reflecting revised estimates of the scope of remediation, as determined by MDE.
Portions of the liability payouts for the Dover and Salisbury sites are expected to be over a thirty year and five year period, respectively. In addition, the Company has two other sites currently being evaluated for which no estimate of liability can be made at this time. It is management's opinion that any current costs not currently recovered and any future costs incurred will be recoverable through future rates or sharing arrangements with other responsible parties.
The following table summarizes total environmental liabilities and associated regulatory assets:
Environmental Liabilities and Regulatory Assets
The following table summarizes the total costs incurred related to environmental testing and remedial action:
Environmental Costs Incurred
Of the total costs incurred and regulatory assets above, the following table summarizes the balances of environmental costs which have not been recovered through insurance proceeds or ratemaking:
Environmental Costs Not Recovered
L. COMMITMENTS AND CONTINGENCIES
Delaware Public Service Commission Order Asserting Jurisdiction Over Eastern Shore Natural Gas Company
On February 11, 1992, the Delaware Public Service Commission ("Commission") issued an Order that declared Eastern Shore to be a "public utility" under Delaware law subject to the Commission's jurisdiction in connection with Eastern Shore's direct retail sales of natural gas to end users in the State of Delaware. The Order initiated a proceeding to consider the extent to which public utility regulatory supervision should be imposed upon the direct sales of Eastern Shore within the State of Delaware. On May 17, 1994 the
Company filed with the commission a proposal for a limited level of regulation. On October 4, 1994, the Commission issued an Order essentially agreeing with a level of regulation limited to the following: accepting and considering complaints from customers, requiring Eastern Shore to file annual and other periodic reports and requiring Eastern Shore to pay the annual public utility tax. The Order will not have a material effect on Eastern Shore's financial position or results of operations.
FERC Order No. 636
The Company is served by three direct natural gas pipelines: Columbia Gas Transmission ("Columbia"), Transcontinental Gas Pipe Line Corporation ("Transco") and Florida Gas Transmission Company ("FGT"). Columbia and Transco serve the Company's natural gas transmission subsidiary, Eastern Shore, which in turn serves the Company's local distribution companies ("LDC") located in Delaware and Maryland. FGT serves the Company's LDC in Central Florida. In connection with the issuance of Order No. 636 ("Order") by the FERC in April 1992, pipelines will incur four types of transition costs in implementing the unbundled service requirement of the Order: (1) gas supply realignment costs (the cost of renegotiating existing gas supply contracts with producers); (2) unrecovered purchased gas adjustment ("PGA") costs (gas costs remaining in the pipelines' PGA account at the time they cease the merchant function); (3) stranded costs (unrecovered costs of assets that cannot be assigned to customers of unbundled services); and (4) new facilities costs (costs of new facilities required to physically implement the Order). In order to recover prudently incurred transition costs from its customers, each pipeline is required to file for and obtain FERC approval. Eastern Shore, based on FERC proceedings involving the recovery of gas purchased and related costs, believes that transition costs passed on from pipelines will be similarly recoverable through the Eastern Shore PGA mechanism for their FERC regulated sales. Eastern Shore also has direct sales customers whose rates are currently not regulated. All transition costs allocated to these non-regulated sales would be required to be expensed when known and measurable. Eastern Shore has received notification that FERC has approved Columbia's request for recovery of transition costs related to PGA costs. Eastern Shore's portion of these costs is $180,924. On April 1, 1994, Columbia started to invoice the amount in equal installments of $15,077 over the next twelve months. Accordingly, in the second quarter, the jurisdictional amount of $150,514 was recorded as a liability and a regulatory asset. The liability is reduced each month as payment is made and the asset is reduced as the costs are recorded to the PGA. The balance for both accounts at December 31, 1994 is $38,000. The remaining amount assigned to the non-regulated sales was expensed in 1994. The Company is unable to estimate Eastern Shore's portion of any additional future transition costs that may be assigned by Transco and Columbia until FERC approves their request for recovery. In the opinion of management, it is not possible to determine the effect, if any, that any transition costs incurred in the future would have on Eastern Shore's financial position or results of operations. FGT has incurred transition costs in the form of gas supply realignment costs and the FERC has approved recovery of prudently incurred costs from FGT's customers, such as the Company's LDC in Central Florida, through a demand charge beginning November 1, 1993 and extending for five years. The Company estimates that its portion of the transition costs on December 31, 1994 and 1993 are $1,983,000 and $2,503,000, respectively, of which $520,000 is due within one year. During 1994 the Company received approval of the PGA rate which includes recovery of the transition costs. Accordingly, the Company has recorded a regulatory asset equivalent to the liability established for transition costs at December 31, 1994 and 1993.
FERC PGA
On May 19, 1994, the FERC issued an Order directing Eastern Shore to refund, with interest, what the FERC characterized as overcharges from November 1, 1992 to the current billing month. The Order also directed Eastern Shore to file a report showing how the refund was calculated, and to revise tariff language clarifying the PGA provisions of its tariff.
Eastern Shore filed a request for rehearing of the Order on June 20, 1994 based on what Eastern Shore believes is the FERC's erroneous interpretation of Eastern Shore's tariff. It is Eastern Shore's position that
the FERC's Order essentially requires a retroactive change to the FERC approved PGA procedures which Eastern Shore has consistently applied over the last six years. Such retroactive application is a violation of Sections 4 and 5 of the Natural Gas Act.
On June 21, 1994, in compliance with the FERC's Order, Eastern Shore filed: (1) revised tariff sheets clarifying its PGA methodology and (2) two alternative refund calculations based on the FERC's Order. The two alternatives were filed due to what Eastern Shore believes to be an inconsistency or contradiction with respect to the FERC's language in its Order. On July 18, 1994 the FERC issued an "Order Granting Rehearing Solely for the Purpose of Further Consideration." Such Order was issued only to afford the FERC additional time for consideration of the issues raised in Eastern Shore's request for rehearing. As of the date of this report, the FERC has not approved either of the alternative refund calculations submitted by Eastern Shore and has not made a final determination as to Eastern Shore's request for rehearing. Accordingly, Eastern Shore accrued $412,000 in the second quarter of 1994, relating to prior periods. Eastern Shore has also accrued an amount each month in 1994 to insure fully funding the potential refund. The total accrued liability at December 31, 1994 is $1,239,000.
Other Commitments and Contingencies
The Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on the consolidated financial position of the Company.
M. 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.
Effective January 1, 1993, the Company adopted SFAS No. 109 as discussed in Note A to the Consolidated Financial Statements. The first quarter of 1993 includes an increase in net income of $57,467 ($0.02 per share) for the one- time cumulative effect of the accounting change.
OPERATING STATISTICS
-------- * Excludes revenue of $2,895,000, which resulted from the sale of 9 million gallons of propane to one large wholesale customer in 1994.
**Includes transportation customers.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information pertaining to the Directors of the Company is incorporated herein by reference to the Proxy Statement, under "Information Regarding the Board of Directors and Nominees", dated and to be filed on or before April 13, 1995 in connection with the Company's Annual Meeting to be held on May 16, 1995.
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.
ITEM 11. EXECUTIVE COMPENSATION
This information is incorporated herein by reference to the Proxy Statement, under "Management Compensation", dated and to be filed on or before April 13, 1995 in connection with the Company's Annual Meeting to be held on May 16, 1995.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is incorporated herein by reference to the Proxy Statement, under "Beneficial Ownership of the Company's Securities", dated and to be filed on or before April 13, 1995 in connection with the Company's Annual Meeting to be held on May 16, 1995.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is incorporated herein by reference to the Proxy Statement, under "Beneficial Ownership of the Company's Securities", dated and to be filed on or before April 13, 1995 in connection with the Company's Annual Meeting to be held on May 16, 1995.
PART IV
ITEM 14.
ITEM 14. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, AND EXHIBITS AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report: 1. Financial Statements: --Auditors' Report dated February 10, 1995 of Coopers & Lybrand, L.L.P., Independent Auditors --Consolidated Statements of Income for each of the three years ended December 31, 1994, 1993 and 1992 --Consolidated Balance Sheets at December 31, 1994 and December 31, --Consolidated Statements of Cash Flows for each of the three years ended December 31, 1994 --Consolidated Statements of Common Shareholders' Equity for each of the three years ended December 31, 1994 --Consolidated Statements of Income Taxes for each of the three years ended December 31, 1994 --Notes to Consolidated Financial Statements
2. The following additional information for the years 1994, 1993 and 1992 is submitted herewith: --Schedule II--Valuation and Qualifying Account
All other schedules are omitted because they are not required, inapplicable, or the information is otherwise shown in the financial statements or notes thereto.
(b) No reports on Form 8-K were required to be filed during the fourth quarter of 1994.
(c) Exhibits
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934, CHESAPEAKE UTILITIES CORPORATION HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Chesapeake Utilities Corporation
By /s/ Ralph J. Adkins ---------------------------------- RALPH J. ADKINS PRESIDENT AND CHIEF EXECUTIVE OFFICER
Date: March 30, 1995 -------------------------------
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURES TITLE DATE ---------- ----- ----
/s/ John W. Jardine, Jr. Chairman of the March 30, 1995 ------------------------------------- Board and Director JOHN W. JARDINE, JR.
/s/ Ralph J. Adkins President, Chief March 30, 1995 ------------------------------------- Executive Officer RALPH J. ADKINS
/s/ John R. Schimkaitis Senior Vice March 30, 1995 ------------------------------------- President & JOHN R. SCHIMKAITIS Assistant Treasurer (Principal Financial Officer and Principal Accounting Officer)
/s/ Richard Bernstein Director March 30, 1995 ------------------------------------- RICHARD BERNSTEIN
/s/ Walter J. Coleman Director March 30, 1995 ------------------------------------- WALTER J. COLEMAN
/s/ Rudolph M. Peins, Jr. Director March 30, 1995 ------------------------------------- RUDOLPH M. PEINS, JR.
/s/ Robert F. Rider Director March 30, 1995 ------------------------------------- ROBERT F. RIDER
/s/ Jeremiah P. Shea Director March 30, 1995 ------------------------------------- JEREMIAH P. SHEA
/s/ William G. Warden, III Director March 30, 1995 ------------------------------------- WILLIAM G. WARDEN, III
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
-------- Notes: (A) Uncollectible accounts charged off. (B) Recoveries. (C) Recovery of propane accounts previously considered to be uncollectible ($315,500).