-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ku0SLZlAb5UZtPSlffOi+SmbAsKlbT3khO/869UyhNhYYzvdg2aUGiGDLvBeljKs JpYzzyr/mFBWJZc43NdcXQ== 0000927016-99-003995.txt : 19991223 0000927016-99-003995.hdr.sgml : 19991223 ACCESSION NUMBER: 0000927016-99-003995 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991222 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PROVIDENCE ENERGY CORP CENTRAL INDEX KEY: 0000319651 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 050389170 STATE OF INCORPORATION: RI FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-10032 FILM NUMBER: 99778576 BUSINESS ADDRESS: STREET 1: 100 WEYBOSSET ST CITY: PROVIDENCE STATE: RI ZIP: 02903 BUSINESS PHONE: 4012725040 MAIL ADDRESS: STREET 1: 100 WEYBOSSET STREET CITY: PROVIDENCE STATE: RI ZIP: 02903 10-K 1 FORM 10-K FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended September 30, 1999 ------------------- OR [_] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ________________________ to ___________________ Commission file number 1-10032 ------- PROVIDENCE ENERGY CORPORATION - ------------------------------------------------------------------------------ (Exact name of registrant as specified in its charter) Rhode Island 05-0389170 - ------------------------------------------------------------------------------ (State or other jurisdiction of (I . R. S. Employer incorporation or organization) Identification No.) 100 Weybosset Street, Providence, Rhode Island 02903 - ------------------------------------------------------------------------------ (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 401-272-9191 ------------ Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which - ------------------- -------------------------------- registered ---------- Common Stock, $1.00 Par Value NEW YORK STOCK EXCHANGE - ------------------------------------------------------------------------------ Securities registered pursuant to Section 12(g) of the Act: NONE - ------------------------------------------------------------------------------ (Title of Class) Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO ___ --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] State the aggregate market value of the voting stock held by non-affiliates of the Registrant, as of November 30, 1999: $229,620,264 Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date. Common Stock, $1.00 Par Value: 6,140,771 shares outstanding at - -------------------------------------------------------------- November 30, 1999. - ----------------- DOCUMENTS INCORPORATED BY REFERENCE - ----------------------------------- Portions of the annual report to shareholders for the fiscal year ended September 30, 1999 are incorporated by reference into Part II. TABLE OF CONTENTS
PART I PAGE Item 1 - Business General I-1 Operations of the Gas Companies I-2 Nonregulated Businesses I-7 Special Factors Affecting the Natural Gas Industry I-8 Environmental Regulations I-8 Other Standards I-10 Item 2 - Properties I-10 Item 3 - Legal Proceedings I-10 Item 4 - Submission of Matters to a Vote of Security Holders I-10 PART II Item 5 - Market for Registrant's Common Equity and Related Stockholders' Matters II-1 Item 6 - Selected Financial Data II-1 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations II-1 Item 8 - Financial Statements and Supplementary Data II-1 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure II-1 PART III Item 10 - Directors and Executive Officers of the Registrant III-1 Item 11 - Executive Compensation III-4 Item 12 - Security Ownership of Certain Beneficial Owners and Management III-4 Item 13 - Certain Relationships and Related Transactions III-4 PART IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K IV-1 Experts Consent IV-6 Supplemental Schedule IV-7 Signatures IV-11
For definitions of industry terms, defined terms, acronyms, and abbreviations, reference is made to the Glossary and Defined Terms, which is pages 43 through 44 of the Registrant's Annual Report to Shareholders (pages 37 through 41 of this form 10-K) for the fiscal year ended September 30, 1999, which is filed herewith under Part IV as Exhibit 13. PART I - ------ ITEM 1. BUSINESS - ---------------- The Providence Energy Corporation and its subsidiaries and their representatives may from time to time make written or oral statements, including statements contained in the Registrant's filings with the Securities and Exchange Commission and in its reports to shareholders, which constitute or contain "forward-looking" statements as that term is defined in the Private Securities Litigation Reform Act of 1995 or by the SEC in its rules, regulations, and releases. All statements other than statements of historical facts included in this Form 10-K including without limitation statements regarding the Registrant's financial position, strategic initiatives, the effect of its proposed merger with Southern Union Company, and statements addressing industry developments are forward-looking statements. Where, in any forward looking statement, the Registrant, or its management expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. The following are some of the factors which could cause actual results to differ materially from those anticipated: general economic, financial, and business conditions; changes in government regulations, the actions taken or decisions rendered by any regulatory body, and the impact such changes, actions, or decisions might have on the Registrant, including the regulatory approvals or the timeliness of such approvals on the Registrant's proposed merger with Southern Union Company; competition in the energy services sector; regional weather conditions; the availability and cost of natural gas and oil; development and operating costs; the success and costs of advertising and promotional efforts; the availability and terms of capital; the business abilities and judgment of personnel; the ability of the Registrant and its suppliers and customers to modify or redesign their computer systems to work properly in the Year 2000; unanticipated environmental liabilities; the Registrant's ability to grow its business through acquisitions and/or significant customer growth; the costs and effects of unanticipated legal proceedings; the impacts of unusual items resulting from ongoing evaluations of business strategies and asset valuations; and changes in business strategy. General - ------- The Registrant was organized in 1981 as a Rhode Island business corporation. The Registrant's outstanding common shares are listed on the New York Stock Exchange under the ticker symbol "PVY". The Registrant is the parent of two wholly-owned natural gas distribution utilities, The Providence Gas Company and North Attleboro Gas Company, together referred to as the Gas Companies. In August 1996, the Registrant incorporated Providence Energy Services, Inc. to market natural gas and energy services and to grow its natural gas, oil, and electricity business to retail accounts in New England. In November 1997, the Registrant acquired all of the outstanding common stock of the Super Service Companies, which marked the Registrant's entrance into the full service oil heating business. The business has grown through acquisition and internal growth to approximately 7,000 customers at September 30, 1999. ProvGas, Rhode Island's largest natural gas distributor, was founded in 1847 and serves approximately 168,000 customers in Providence, Newport and 23 other cities and towns in Rhode Island. North Attleboro Gas serves approximately 4,000 customers in North Attleboro and Plainville, Massachusetts, towns adjacent to the northeastern Rhode Island border. The total natural gas service territory of the Gas Companies encompasses 760 square miles and has a population of approximately 853,000. I-1 The corporate offices of the Registrant are located at 100 Weybosset Street, Providence, Rhode Island 02903 (Telephone 401-272-5040). On November 15, 1999, ProvEnergy and Southern Union announced that their Boards of Directors had unanimously approved a definitive merger agreement. See Note 2 in the accompanying Consolidated Financial Statements for additional information. Operations of the Gas Companies - ------------------------------- Customers - --------- The Gas Companies served an average of 172,000 customers for the twelve months ended September 30, 1999, of which approximately 90% were residential and 10% were commercial and industrial. The net increase in the average number of customers during fiscal 1999 over fiscal 1998 was approximately 2,300 or 1.4%. A portion of this increase was the result of new housing construction and conversions from other energy sources. This increase was achieved in a local economy which is now beginning to improve. Seasonally adjusted unemployment stood at 3.8 percent in September 1999, down from 4.8 percent twelve months earlier, and slightly below the national average of 4.2 percent. New construction contracts in Rhode Island through September 1999 have increased by 17% on an annual basis compared to 1998's annual average. Recent economic forecasts by the New England Economic Project predict economic stability in the state for the immediate future. Gas Service - ----------- The gas services provided by the Gas Companies can be grouped into four categories -- firm sales, firm transportation, non-firm sales and non-firm transportation. Firm service is provided to those residential, commercial and industrial customers that use natural gas throughout the year. Non-firm service is provided to those commercial and industrial customers that do not require assured gas service because they can utilize an alternative fuel or otherwise operate without gas service. Transportation service is a service where the Gas Companies transport to certain large customers gas owned by those customers or by third parties selling gas to those customers. The following table shows the distribution of gas to various customer classes, and the total gas sold and transported by year since 1995:
1999 1998 1997 1996 1995 ----- ----- ----- ----- ----- Firm Sales 69.2% 73.9% 80.4% 85.8% 76.4% Firm Transportation 21.2 16.6 6.7 1.3 0.7 Non-Firm Sales 3.3 5.6 9.6 9.3 17.6 Non-Firm Transportation 6.3 3.9 3.3 3.6 5.3 ----- ----- ----- ----- ----- 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ===== ===== =====
Total Gas Sold and Transported - ------------------------------ 1999 1998 1997 1996 1995 ----- ----- ----- ----- ----- BCF(*) 25.4 25.4 27.3 28.1 28.1 ===== ===== ===== ===== ===== (*) Gas sales are denominated in billions of cubic feet of natural gas. Total gas sales include gas sold and transported by the Gas Companies. I-2 The following table shows the difference between actual and normal degree days since 1995:
1999 1998 1997 1996 1995 ----- ----- ----- ----- ----- Actual calendar degree days 5,139 5,206 5,657 5,967 5,111 Normal calendar degree days 5,652 5,652 5,652 5,682 5,709 Colder (warmer) than normal (9.1%) (7.9%) 0.1% 5.0% (10.5%)
Firm Sales - ---------- In the recent year, the distribution of the Gas Companies' firm sales was approximately 57% to residential and 43% to commercial and industrial and transportation customers. Firm sales represent the highest percentage of operating margin and represent the core of the Gas Companies' business. Non-Firm - -------- The non-firm customer base consists of seasonal customers that typically use gas only during the nonwinter months and dual-fuel customers that contract for gas service on a year round basis, but agree to service interruption during certain peak periods. By retaining the right to interrupt service to the dual- fuel customers, the Gas Companies can balance daily demand from firm customers with available gas supply and pipeline capacity. Non-firm customers may interrupt their gas service, as well, when it is more economical to utilize an alternative fuel. Accordingly, the amount of the Gas Companies' non-firm sales fluctuates depending upon the relative price of natural gas to alternative fuels. Non-firm sales produce substantially less margin to the Gas Companies than firm sales due to the more competitive nature of non-firm sales. Service rates charged to dual-fuel customers are based on the price that the customer would otherwise pay for its alternative fuel. In fiscal year 1999, under the terms of the Price Stabilization Plan Settlement Agreement, any margin earned from these non-firm customers was retained by the Registrant - See "Rates and Regulation" -------------------- and "Competition and Marketing". ------------------------- Transportation Service - ---------------------- The Registrant provides both firm and non-firm transportation of gas. Margin from the firm transportation of gas purchased by certain large customers from third parties is likely to represent an increasing percentage of the Gas Companies' future total margin due to the continuing developments affecting the natural gas industry - see "Competition and Marketing". In general, these -------------------------- developments now allow customers to buy gas directly from the producer-supplier rather than solely from the local gas distribution company. Customer-owned gas is transported to the customer's premises through a combination of the interstate pipelines and the Gas Companies' distribution systems. For a given quantity of gas, the Gas Companies' margin from firm transportation service is comparable to the margin from firm sales. Margin from nonfirm transportation service is less than the margin from firm sales, but is generally comparable to the margin from interruptible sales, depending on the price of alternative fuels. To the extent that the Gas Companies' existing customers buy gas directly from producer-suppliers, the Gas Companies' revenue will decrease although firm margin will not be materially impacted. I-3 Gas Supply - ---------- The Registrant's principal subsidiary, ProvGas, entered into a full requirements gas supply contract with DETM, a joint venture of Duke Energy Corporation and Mobil Corporation, for a term of three years commencing October 1, 1997. Under the contract, DETM guarantees to meet ProvGas' supply requirements; however, ProvGas must purchase all of its gas supply exclusively from DETM. In addition, under the contract, ProvGas transferred responsibility for its pipeline capacity resources, storage contracts, and LNG capacity to DETM. As a result, ProvGas' gas inventories of approximately $18 million at September 30, 1997 were sold at book value to DETM on October 1, 1997. In addition to providing supply for firm customers at a fixed price, DETM will provide gas at market prices to cover ProvGas' non-firm sales customers' needs and to make up the supply imbalances of transportation customers. DETM will also provide various other services to ProvGas' transportation service customers including enhanced balancing, standby, and the storage and peaking services available under ProvGas' approved FT-2 storage service effective December 1, 1997. DETM will receive the supply-related revenues from these services in exchange for providing the supply management inherent in these services. Included in the DETM contract are a number of other important features. ProvGas has retained the right to continue to make gas supply portfolio changes to reduce supply costs. To the extent ProvGas makes such changes, ProvGas must keep DETM whole for the value lost over the remainder of the contract period. The outsourcing of day-to-day supply management relieves ProvGas of the need to perform certain upstream supply management functions. This will make it possible for ProvGas to take on the additional supply management workload required by the further unbundling of firm sales customers without major staffing additions. ProvGas has entered into an agreement replacing its existing service contract with Algonquin, a subsidiary of Duke Energy Corporation. Algonquin is the owner and operator of a LNG tank located in Providence, Rhode Island. ProvGas relies upon this service to provide gas supply into its distribution system during the winter period. The service provided for in the agreement, subject to the successful completion of construction, is expected to begin in the first quarter of fiscal 2000. Under the terms of the agreement, Algonquin replaced and expanded the vaporization capability at the tank. ProvGas will receive approximately $2.6 million from Algonquin. Of the $2.6 million, approximately $.9 million represents reimbursement received by ProvGas in 1999 for costs incurred related to the project including labor, engineering, and legal expenses. The remaining portion of the payment, or approximately $1.7 million, will be paid to DETM under ProvGas' contract with DETM as reimbursement for the additional costs that DETM will incur when the Algonquin storage capacity is released to DETM as provided for in the gas supply contract described above. This payment is expected 60 days after the in-service date of the project. In June 1999, the FERC issued an order in Docket Number CP99-113 approving Algonquin's project described above. In that order FERC also approved the new 10-year contract between Algonquin and ProvGas for service from the tank. Also approved was ProvGas' parallel filing, PR99-8, requesting regulatory authorization to charge Algonquin for transportation of gas vaporized for other Algonquin customers and transported by ProvGas to the Algonquin pipeline on behalf of those customers. I-4 As a result of FERC Order 636 and other related orders, pipeline transportation companies have incurred significant costs, collectively known as transition costs. The majority of these costs will be reimbursed by the pipeline's customers, including ProvGas. ProvGas estimates its transition costs to be approximately $21.7 million, of which $16.2 million has been included in the GCC and collected from customers through September 30, 1997. As part of the above supply contract, DETM assumed liability for these transition costs during the contract's three-year term. At the end of the three-year term of the contract, the Registrant will assume any remaining liability, which is not expected to be material. Rates and Regulation - -------------------- ProvGas is subject to the regulatory jurisdiction of the Rhode Island Public Utilities Commission and North Attleboro Gas is subject to the jurisdiction of the Massachusetts Department of Telecommunications and Energy with respect to rates and charges, standards of service, accounting and other matters. In August 1997, the RIPUC approved a rate stabilization plan called Energize RI. The parties to the plan were ProvGas, the Division, the Energy Council of Rhode Island, and the George Wiley Center. Effective October 1, 1997 through September 30, 2000, Energize RI provides firm customers with a three- year price freeze and an initial price decrease of approximately 4.0 percent. Under Energize RI, the GCC mechanism has been suspended for the entire term. Also, in connection with the Plan, ProvGas wrote off approximately $1.5 million of previously deferred gas costs in October 1997. Energize RI also provides funds which allow ProvGas to make significant capital investments to improve its distribution system and support economic development. It is anticipated that Energize RI will provide approximately $26 million over its three-year term to fund specific capital improvements. In addition, under Energize RI, ProvGas provides funding for the Low-Income Assistance Program at an annual level of $1.0 million, the Demand Side Management Rebate Program at an annual level of $.5 million and the Low-Income Weatherization Program at an annual level of $.2 million. Energize RI also continues the process of unbundling by allowing ProvGas to provide unbundled service offerings for up to 10 percent per year of firm deliveries. As part of Energize RI, ProvGas has reclassified and is amortizing approximately $4.0 million of prior environmental costs. These costs and all environmental costs incurred during the term of the Plan will be amortized over a 10-year period, in accordance with the levels authorized in Energize RI. Under Energize RI, ProvGas may earn up to 10.9 percent, but not less than 7.0 percent, annually on its average common equity, which is capped at $81.0 million, $86.2 million, and $92.0 million in fiscal 1998, 1999, and 2000, respectively. In the event that ProvGas earns in excess of 10.9 percent or less than 7.0 percent, ProvGas will defer revenues or costs through a deferred revenue account over the term of the Plan. Any balance in the deferred revenue account at the end of the Plan will be refunded to or recovered from customers in a manner to be determined by all parties to the Plan and approved by the RIPUC. As part of Energize RI, ProvGas is permitted to file annually with the Division for the recovery of exogenous changes which may occur during the three- year term of the Plan. Exogenous changes are defined as "...significant increases or decreases in ProvGas' costs or revenues which are beyond ProvGas' reasonable control." Any disputes between ProvGas and the Division regarding either the nature or quantification of the exogenous changes are to be resolved by the RIPUC. The impact of any such exogenous changes will be debited or credited to a regulatory asset or liability account throughout the term of Energize RI and will be recovered or refunded at the expiration of the Plan through a method to be determined. I-5 In fiscal 1998, ProvGas did not earn its allowed rate of return primarily as a result of the extremely warm winter weather and the loss of non-firm margin. ProvGas believed the causes of these two events were beyond its reasonable control and thus deemed them to be exogenous changes. In March 1999, ProvGas reached an agreement with the Division, which allowed it to recover $2.45 million in revenue losses attributable to exogenous changes experienced by ProvGas in fiscal 1998. The RIPUC reviewed the exogenous changes agreement to ensure consistency with the terms of Energize RI and affirmed the agreement at its May 28, 1999 open meeting. During fiscal 1999, ProvGas recognized into revenue $2.45 million for the exogenous changes recovery, and at year-end has deferred approximately $.5 million of revenue under the provisions of the earnings cap of Energize RI. ProvGas intends to file for recovery of exogenous changes experienced in 1999 which resulted from factors similar to 1998. Absent further exogenous recovery and/or other factors such as colder than normal weather, ProvGas' ability to earn a 10.9 percent return on average common equity in the final year of Energize RI is substantially impaired. In a decision issued September 1, 1998, the Division rejected allegations made in a complaint brought by Aurora Natural Gas that ProvGas provided advance information and undue preference in pricing to its marketing affiliate, ProvEnergy Services in violation of the Division's regulations. As part of its investigation, the Division ordered marketer refunds of approximately $.3 million. The Division ordered this refund based on its belief that an unfair rate was charged to customers who did not have operational telemeters in place when they began service under the transportation tariff. ProvGas filed a Request for Reconsideration and Rehearing, and on December 15, 1998 the Division issued a Reconsideration Order that rescinded the fines stemming from five of the original 23 violations of the Regulations for Utility Interaction with Gas Marketers. The Division further offered the Registrant an opportunity to demonstrate its claim that the ordered refunds would place FT-2 marketers in a better position than marketers who served FT-1 customers. On May 6, 1999, ProvGas and Aurora jointly submitted a Stipulation and Settlement to the Division that: (i) Aurora's complaint in this proceeding is dismissed; (ii) the prior orders of the Division in the proceeding are dismissed; (iii) no refunds by ProvGas are required or appropriate in connection with the proceeding; and (iv) ProvGas does not contest the payment of $18,000 to the Division in connection with this proceeding. Following a June 16, 1999 hearing on the Stipulation, the Division issued an order on September 23, 1999 approving the Stipulation and Settlement provided that ProvGas ratepayers are held harmless from the financial transactions stemming from the settlement, that ProvGas withdraw its appeal in Providence County Superior Court, and that the Division's prior orders be vacated as described in the order. ProvGas and Aurora accepted the Division's order. This decision resulted in the reversal of the reserve established under the original order. Competition and Marketing - ------------------------- Energize RI provides opportunities for ProvGas to expand sales. For example, high pressure service to Quonset/Davisville Industrial Port & Commerce Park, a key area for State economic development, provides opportunities for sales growth as commercial and industrial businesses locate within the park. In addition, Demand Side Management, an equipment rebate program, provides opportunities to expand sales to non-traditional applications, such as air conditioning and fuel cells. ProvGas has redirected its sales and marketing efforts to leverage Energize RI, as well as other opportunities to promote sales growth within its service territory. I-6 In response to the large increase of both state-owned and private fleet vehicles powered by natural gas, ProvGas invested approximately $.3 million to renovate its Providence "quick-fill" station for natural gas vehicles - one of three stations ProvGas operates in the state. Fleet operators throughout the region are expressing greater interest in alternative-fuel vehicles. One of these operators is the Rhode Island Public Transit Authority, which recently launched a major program to replace a large number of its 200 diesel buses with buses that operate solely on natural gas. A new Rhode Island law provides substantial tax incentives which, along with the Federal Department of Energy's designation of Providence as a "clean city" should increase use and awareness of the benefits of natural gas vehicles. On August 31, 1999, ProvGas' settlement agreement for enhancements to its Business Choice program was approved in Docket 2902 and became effective September 1, 1999. Specifically, there will now be rolling enrollment for transportation service, which will allow customers to execute transportation agreements throughout the year, rather than during limited enrollment periods. The program now has approximately 1,700 firm transportation customers with annual deliveries of over 5 billion cubic feet per year, which is approximately 25 percent of ProvGas' total annual firm deliveries. There are 14 marketers serving ProvGas' customers and transporting on the system. Additional enhancements to the Business Choice program were filed with the RIPUC under a supplemental settlement agreement in Docket 2902 on October 8, 1999 and were approved on October 27, 1999. These enhancements do not generate additional revenue. In 1996, ProvGas implemented a Demand Side Management Program, which furnishes rebates to customers installing new technologies, such as gas fired air conditioning, cogeneration and gas motors. These technologies use proportionately more natural gas during the summer months, when the distribution system has available capacity. The DSM Program also allows for the utilization of existing resources, such as mains, services and year-round supply contracts. This DSM Program will continue to be funded under Energize RI. The discussion of Competition and Marketing for the Registrant's non- regulated businesses can be found in the "Non-regulated Businesses" section. ----------------------- Employees - --------- As of September 30, 1998, the Registrant had 615 full-time employees. Approximately 274 of ProvGas' distribution and customer service employees are covered by a collective bargaining agreement with Local 12431-01 of the United Steelworkers of America, which became effective in January 1996. The bargaining agreement was developed by a labor-management negotiations committee and contains a provision allowing the agreement to be reopened for any reason at any time in order for the committee to deal with new issues as they arise. The provision results in increased flexibility in the use of employees. The original agreement called for a general wage increase of 3.25 percent each year from 1997 to 2000. In April 1998 the contract with Local 12431-01 was renegotiated and extended to January 2002. This negotiation provides for a 3.5 percent wage increase in January 1999, January 2000, and January 2001. Additionally, in March 1996, a 38 month Labor Agreement was ratified by Local 12431-02 of the United Steelworkers of America, which represents 83 office and clerical employees of ProvGas. The agreement called for an average general wage increase of 2.9 percent in 1998. In April 1998 the contract with Local 12431-02 was renegotiated and extended to May 2002. This negotiation provides for a 3.5 percent wage increase in June 1999, June 2000, and June 2001. I-7 Gas Distribution Systems - ------------------------ The Gas Companies' distribution systems consist of approximately 2,400 miles of gas mains ranging in size from 2 to 36 inches in diameter, approximately 146,000 services (a "service" meaning a pipe connecting a gas main with piping on a customer's premises), and approximately 173,000 active gas meters together with related facilities and equipment. The Gas Companies have regulating and metering facilities at nine points of delivery from Algonquin Gas Transmission Company and one point of delivery from Tennessee Gas Pipeline Company, which the Gas Companies presently believe to be adequate for receiving gas into their distribution systems. Non-regulated Businesses - ------------------------ The Registrant's non-regulated operation continues to increase its contribution to operating margin by adding customers and sales volume, although it continues to generate a net loss consistent with the start-up of new businesses. The Registrant intends to continue to grow its residential oil customer base through future customer acquisitions to build the operational scale needed to compete effectively in the marketplace. Furthermore, as New England gas utilities continue to unbundle the sale of the gas commodity from the distribution of that gas, the opportunity for increased non-regulated natural gas sales will expand. The Registrant's joint venture to provide electricity, HVAC, and related services for most of the Mall began with the Mall's August 1999 opening. Special Factors Affecting the Natural Gas Industry - -------------------------------------------------- General - ------- The natural gas industry is subject to numerous legislative and regulatory requirements, standards and restrictions that are subject to change and that affect the Gas Companies to varying degrees. Significant industry factors that have affected or may affect the Gas Companies from time to time include lack of assurance that rate increases can be obtained from regulatory authorities in adequate amounts on a timely basis; changes in the regulations governing the Gas Companies' operations; ability to adapt to FERC regulatory changes; reductions in the prices of oil and propane, which can make those fuels less costly than natural gas in some markets; and increases in the price of natural gas. FERC Regulations - ---------------- In recent years, FERC has been attempting to increase competition with regard to the transportation and sale of natural gas in interstate commerce. Beginning in late 1985, FERC began promulgating orders that allow all industry participants access to pipeline transportation on an open, nondiscriminatory basis to the extent of available capacity. Recent FERC orders are in furtherance of its policy to make gas transportation and alternate supply sources more accessible to all parties, including local distribution companies and their customers. Such open access allows the Gas Companies to obtain their supply through a more competitive national gas pipeline system, where and when capacity is available. FERC Order 636 and other related orders have significantly changed the structure and types of services offered by pipeline transportation companies. The most significant components of the restructuring occurred in November 1993. In response to these changes, the Gas Companies have negotiated new pipeline transportation and gas storage contracts. To meet the requirements of the orders, pipeline transportation companies have incurred significant costs, collectively known as transition costs. The majority of these costs will be reimbursed by the pipelines' customers including ProvGas as discussed in the "Gas Supply" section. ---------- I-8 Environmental Regulations - ------------------------- Federal, state, and local laws and regulations establishing standards and requirements for the protection of the environment have increased in number and in scope within recent years. The Registrant cannot predict the future impact of such standards and requirements, which are subject to change and can take effect retroactively. The Registrant continues to monitor the status of these laws and regulations. Such monitoring involves the review of past activities and current operations, and may include expending funds to investigate or clean up certain sites. To the best of its knowledge, subject to the following, the Registrant believes it is in substantial compliance with such laws and regulations. At September 30, 1999, the Registrant was aware of five sites at which future costs may be incurred. Plympton Sites (2) The Registrant has been designated as a PRP under the Comprehensive Environmental Response Compensation and Liability Act of 1980 at two sites in Plympton, Massachusetts on which waste material is alleged to have been deposited by disposal contractors employed in the past either directly or indirectly by the Registrant and other PRPs. With respect to one of the Plympton sites, the Registrant has joined with other PRPs in entering into an Administrative Consent Order with the Massachusetts Department of Environmental Protection. The costs to be borne by the Registrant, in connection with both Plympton sites, are not anticipated to be material to the financial condition of the Registrant. Providence Site During 1995, the Registrant began a study at its primary gas distribution facility located in Providence, Rhode Island. This site formerly contained a manufactured gas plant operated by the Registrant. As of September 30, 1999, approximately $3.0 million had been spent primarily on studies and the formulation of remediation work plans at this site. In accordance with state laws, such a study is monitored by the DEM. The purpose of this study was to determine the extent of environmental contamination at the site. The Registrant has completed the study which indicated that remediation will be required for two-thirds of the property. The remediation began in June 1999 and is anticipated to be completed during the next fiscal year. During this remediation period, the remaining one-third of the property will also be investigated and remediated if necessary. The Registrant has compiled a preliminary range of costs, based on removal and off-site disposal of contaminated soil, ranging from $7.0 million to in excess of $9.0 million. However, because of the uncertainties associated with environmental assessment and remediation activities, the future cost of remediation could be higher than the range noted. Based on the proposals for remediation work, the Registrant has a net accrual of $6.1 million at September 30, 1999 for anticipated future remediation costs at this site. Westerly Site Tests conducted following the discovery of an abandoned underground oil storage tank at the Registrant's Westerly, Rhode Island operations center in 1996 confirmed the existence of coal tar waste at this site. As a result, the Registrant completed a site characterization test. Based on the findings of that test, the Registrant concluded that remediation would be required. As of September 30, 1999, the Registrant had removed an underground oil storage tank and regulators containing mercury disposed of on the site, as well as some localized contamination. The costs associated with the site characterization I-9 test and partial removal of soil contaminants were shared equally with the former owner of the property. The Registrant is currently engaged in negotiations to transfer the property back to the previous owner, who would continue to remediate the site. The purchase and sale agreement is anticipated to be signed during fiscal 2000, at which time the previous owner will assume responsibility for removal of coal tar waste on the site. The Registrant remains responsible for cleanup of any mercury released into adjacent water. Contamination from scrapped meters and regulators, which was discovered in 1997, was reported to the DEM and the Rhode Island Department of Health and the Registrant has completed the necessary remediation. Costs incurred by the Registrant to remediate this site were approximately $.1 million. Allens Avenue Site In November 1998, the Registrant received a letter of responsibility from DEM relating to possible contamination on previously-owned property on Allens Avenue in Providence. The current operator of the property has been similarly notified. Both parties have been designated as PRPs. A work plan has been created and approved by DEM. An investigation has begun in order to determine the extent of the problem and the Registrant's responsibility. The Registrant has entered into a cost sharing agreement with the current operator of the property, under which the Registrant will be held responsible for approximately 20 percent of the costs related to the investigation. Total estimated costs of testing at this site are anticipated to be approximately $.2 million. Until the results of the investigation are known, the Registrant cannot offer any conclusions as to its responsibility. General In prior rate cases filed with the RIPUC, ProvGas requested that environmental investigation and remediation costs be recovered by inclusion in its depreciation factors consistent with the rate recovery treatment for all types of cost of removal. Due to the magnitude of ProvGas' environmental investigation and remediation expenditures, ProvGas sought current recovery for these amounts. As a result, in accordance with the Price Stabilization Plan Settlement Agreement described in Note 10, effective October 1, 1997, all environmental investigation and remediation costs incurred through September 30, 1997, as well as all costs incurred during the three-year term of the Plan, will be amortized over a 10-year period, in accordance with the levels authorized in Energize RI. Additionally, it is ProvGas' practice to consult with the RIPUC on a periodic basis when, in management's opinion, significant amounts might be expended for environmental-related costs. As of September 30, 1999, ProvGas has incurred environmental assessment and remediation costs of $4.7 million and has a net accrual of $6.1 million for future costs. Management has begun discussions with other parties who may assist ProvGas in paying the costs associated with the remediation of the above sites. Management believes that its program for managing environmental issues, combined with rate recovery and financial contributions from others, will likely avoid any material adverse effect on its results of operations or its financial condition as a result of the ultimate resolution of the above sites. Other Standards - --------------- The Gas Companies are also subject to standards prescribed by the Secretary of Transportation under the Natural Gas Pipeline Safety Act of 1968 with respect to the design, installation, testing, construction and maintenance of pipeline facilities. The enforcement of these standards has been delegated to the RIPUC and MDTE and management believes that the Gas Companies are in substantial compliance with all present requirements imposed by these agencies. I-10 ITEM 2. PROPERTIES - ------------------ In addition to the Registrant's gas distribution system and storage facilities, which constitute the principal properties of the Registrant, the Registrant owns several buildings and other facilities in Newport, Warwick, Providence, and Westerly that house its offices and provide floor space for its energy distribution and maintenance facilities. Substantially all the foregoing properties are mortgaged as collateral for the outstanding First Mortgage Bonds of ProvGas. ITEM 3. LEGAL PROCEEDINGS - ------------------------- The Registrant is involved in legal and administrative proceedings in the normal course of business, including certain proceedings involving material amounts in which claims have been or may be made. However, management believes, after review of insurance coverage and consultation with legal counsel, that the ultimate resolution of the legal proceedings to which it is or can at the present time be reasonably expected to be a party, will not have a materially adverse effect on the Registrant's results of operations or financial condition. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ----------------------------------------------------------- Not Applicable I-11 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDERS' - --------------------------------------------------------------------------- MATTERS ------- The Registrant's common stock is listed on the New York Stock Exchange and trades under the symbol "PVY". As of November 30, 1999, there were 6,338 registered holders of record of the Registrant's outstanding common stock. For the balance of the information called for by this item, reference is made to the materials under 'Common stock information' in the Registrant's Annual Report to Shareholders for the fiscal year ended September 30, 1999, which is filed herewith under Part IV as Exhibit 13. ITEM 6. SELECTED FINANCIAL DATA - ------------------------------- For the information called for by this item, reference is made to pages 38 through 41 of the Registrant's Annual Report to Shareholders (pages 35 through 36 of this Form 10-K) for the fiscal year ended September 30, 1999, which is filed herewith under Part IV as Exhibit 13. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS - ------------------------------------------------------------------------------- OF OPERATIONS ------------- Regarding the information that relates to this item, reference is made to pages 15 through 18 of the Registrant's Annual Report to Shareholders (pages 1 through 8 of this Form 10-K) for the fiscal year ended September 30, 1999, which is filed herewith under Part IV as Exhibit 13. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - --------------------------------------------------- For the information called for by this item, reference is made to pages 19 through 34 of the Registrant's Annual Report to Shareholders (pages 9 through 33 of this Form 10-K) for the fiscal year ended September 30, 1999, which is filed herewith under Part IV as Exhibit 13. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND - ----------------------------------------------------------------------- FINANCIAL DISCLOSURE -------------------- Not applicable II-1 PART III -------- ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - ------------------------------------------------------------ The following information is furnished with respect to the executive officers of the Registrant:
Year Office Name and Age Office First Held - ------------ ------ ---------- James H. Dodge (59) Chairman, President and Chief Executive Officer 1992 James DeMetro (51) Executive Vice President 1999 Kenneth W. Hogan (54) Vice President, Chief Financial Officer, and Treasurer 1999 James A. Grasso (45) Vice President, Public and Government Affairs 1997 Royalynne J. Hourihan (55) Vice President, Human Resources 1998 Susann G. Mark (52) Vice President, General Counsel, and Secretary 1998 Gerald A. Yurkevicz (42) Vice President, Marketing 1996 Harry J. Bishop (53) Assistant Treasurer 1998
Mr. Dodge was elected President and Chief Executive Officer of the Registrant and ProvGas in August 1990 and subsequently became Chairman of the Board in January 1992. Mr. Dodge currently serves as a member of the Board of Capital Properties, Inc., a non-affiliated real estate leasing company. Mr. DeMetro was elected Executive Vice President of the Registrant and ProvGas in February 1999. Mr. DeMetro served the Registrant and ProvGas as Senior Vice President and for more than four years prior thereto, Vice President, Energy Services. Mr. Hogan was elected Vice President, Chief Financial Officer, and Treasurer of the Registrant and ProvGas in April 1999. For more than five years prior thereto, Mr. Hogan served as Senior Vice President, Chief Financial Officer, and Secretary of Valley Resources, Inc., a diversified energy company. Mr. Grasso was elected Vice President, Public and Government Affairs in May 1997. For three years prior thereto, Mr. Grasso served as Director of Public and Government Relations of the Eastern Region of Pan Energy Corporation and Manager of Public and Government Relations of Algonquin Gas Transmission Company. For ten years prior thereto, Mr. Grasso served as Manager of Land, Public and Government Relations of Algonquin Gas Transmission Company. Mrs. Hourihan was elected Vice President, Human Resources effective November 1998. For two years prior thereto, Mrs. Hourihan served as the senior human resources professional of the Boston Public Schools District, Boston, Massachusetts. For two years prior thereto, Mrs. Hourihan served as Vice President, Human Resources of the Philadelphia Inquirer & Daily News. For four --------------------- years prior thereto, Mrs. Hourihan served as Director, Human Resources - Eastern Region of Wang Laboratories, Inc. III-1 Ms. Mark was elected Vice President, General Counsel and Secretary of the Registrant in April 1998. For one year prior to that, Ms. Mark was a partner in the Business Law Group at Brown, Rudnick, Freed & Gesmer and for eight years prior to that was a partner in the Corporate Law Practice Group at Licht and Seminoff. Mr. Yurkevicz was elected Vice President, Marketing of the Registrant in August 1996. For ten years prior thereto, Mr. Yurkevicz served as Principal in the Energy Practice at Mercer Management Consulting. Mr. Bishop was elected Assistant Treasurer effective October 1, 1998. For four years prior thereto, Mr. Bishop served as Director of Finance and Revenue Requirements for ProvGas. III-2 DIRECTORS OF THE REGISTRANT - --------------------------- For information called for by this item, reference is made to pages 2 through 6 of the Registrant's proxy statement filed December 21, 1999 with the Securities and Exchange Commission for the annual meeting of shareholders to be held January 20, 2000. III-3 ITEM 11. EXECUTIVE COMPENSATION - -------------------------------- For the information called for by this item, reference is made to pages 7 through 18 of the Registrant's proxy statement filed December 21, 1999 with the Securities and Exchange Commission for the annual meeting of shareholders to be held January 20, 2000. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND - ------------------------------------------------------------ MANAGEMENT ---------- For the information called for by this item, reference is made to page 19 of the Registrant's proxy statement filed December 21, 1999 with the Securities and Exchange Commission for the annual meeting of shareholders to be held January 20, 2000. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - ------------------------------------------------------- For the information called for by this item, reference is made to pages 6 through 7 of the Registrant's proxy statement filed December 21, 1999 with the Securities and Exchange Commission for the annual meeting of shareholders to be held January 20, 2000. III-4 PART IV ------- ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K - ------------------------------------------------------------------------ PROVIDENCE ENERGY CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES (a) Financial Statements and Schedules ---------------------------------- Consolidated Balance Sheets--September 30, 1999 and 1998 Consolidated Statements of Income for the years ended September 30, 1999, 1998 and 1997 Consolidated Statements of Cash Flows for the years ended September 30, 1999, 1998 and 1997 Consolidated Statements of Capitalization--September 30, 1999 and 1998 Consolidated Statements of Changes in Common Stockholders' Investment for the years ended September 30, 1999, 1998 and 1997 Notes to Consolidated Financial Statements Report of Independent Public Accountants Consent of Independent Public Accountants The financial statements and related notes listed above are incorporated by reference from Providence Energy Corporation's Annual Report to Shareholders (see pages 9 through 33 of this Form 10-K) for the year ended September 30, 1999, filed herewith as Exhibit 13. Schedule II. Reserves for the years ended September 30, 1999, 1998 and 1997. Schedules I to XIII not listed above are omitted as not applicable or not required under Regulation S-X. (b) Reports on Form 8-K ------------------- Although no reports on Form 8-K have been filed by the Registrant during the last quarter, on November 15, 1999, the Registrant filed a report on Form 8-K regarding the Registrant's Agreement and Plan of Merger with Southern Union. IV-1 (c) Exhibits -------- The following exhibits are filed as part of this report: 3.1 Articles of Incorporation, as amended (incorporated by reference to Exhibit 4(e) to the Registration Statement of the Registrant on Form S-2 (Registration No. 33-24125)). 3.2 Bylaws (incorporated by reference to Exhibit C to the Proxy Statement/Prospectus forming a part of the Registrant's Registration Statement on Form S-14 (Registration No. 2-69473), as amended at the annual meetings of the shareholders held January 14, 1985 and January 14, 1991, the text of such amendments being set forth in each case as Exhibit A to the proxy statement for such annual meeting, heretofore filed with the Securities and Exchange Commission and being incorporated herein by this reference). 4.1 First Mortgage Indenture of The Providence Gas Company dated as of January 1, 1922, as supplemented by First through Twelfth Supplemental Indentures (incorporated by reference to Exhibit 10.10 to the Registration Statement of The Providence Gas Company on Form S-1 (Registration No. 2-72726)). 4.2 Fourteenth, Fifteenth and Sixteenth Supplemental Indentures of The Providence Gas Company dated as of August 1, 1988, June 1, 1990 and November 1, 1992, respectively (incorporated by reference to Exhibit 4 to the report of the Registrant to the Securities and Exchange Commission on Form 10-Q for the quarter ended March 31, 1993). 4.3 Seventeenth Supplemental Indenture of The Providence Gas Company dated as of November 1, 1993. (Filed as Exhibit 4.5 to the report of the Registrant on Form 10-K for the year ended September 30, 1993 incorporated herein by this reference.) 4.4 Eighteenth Supplemental Indenture of The Providence Gas Company dated as of December 1, 1995. (Filed as Exhibit 4.6 to the report of the Registrant on Form 10-K for the year ended September 30, 1995 incorporated herein by this reference.) 4.5 Nineteenth Supplemental Indenture of The Providence Gas Company dated as of April 1, 1998. (Filed as Exhibit 4.5 to the report of The Providence Gas Company on Form 10-K for the year ended September 30, 1998, incorporated herein by this reference.) 4.6 Stock Rights Agreement (Filed as Exhibit 4.1 to the report of the Registrant on Form 8-K File No. 001-10632 dated July 29, 1998, incorporated herein by this reference.) 4.7 Twentieth Supplemental Indenture dated as of February 1, 1999. (Filed as Exhibit 4.6 to the report of The Providence Gas Company on Form 10-K for the year ended September 30, 1999, incorporated herein by this reference.) 4.8 Twenty-first Supplemental Indenture dated as of October 12, 1999. (Filed as Exhibit 4.7 to the report of The Providence Gas Company on Form 10-K for the year ended September 30, 1999, incorporated herein by this reference.) 10.1 Material contracts filed as Exhibit 10 (a) through 10 (ff) to Registration Statement of the Registrant on Form S-2 (Registration No. 33-24125), incorporated herein by this reference. IV-2 10.2 Employment Agreement dated October 29, 1997 between James H. Dodge, Chairman, President and Chief Executive Officer of the Registrant. (Filed as Exhibit 10.2 to the report of The Registrant in Form 10-K for the year ended September 30, 1997, incorporated herein by this reference.) 10.3 Employment Agreement dated October 29, 1997 between James DeMetro, Senior Vice President of The Registrant. (Filed as Exhibit 10.3 to the report of The Registrant in Form 10-K for the year ended September 30, 1997, incorporated herein by this reference.) 10.4 Employment Agreement dated October 29, 1997 between Robert W. Owens, Senior Vice President of the Registrant. (Filed as Exhibit 10.4 to the report of The Registrant in Form 10-K for the year ended September 30, 1997, incorporated herein by this reference.) 10.5 Change of control agreement dated May 10, 1999 between Kenneth W. Hogan, Vice President, Chief Financial Officer, and Treasurer and the Registrant. (Filed as Exhibit 10c to the report of the Registrant in Form 10-Q for the quarter ended June 30, 1999, incorporated herein by this reference.) 10.6 Employment Agreement dated July 23, 1998 between James A. Grasso, Vice President, Public and Government Affairs and the Registrant. (Filed as Exhibit 10.6 to the report of the Registrant in Form 10-K for the year ended September 30, 1998 incorporated herein by this reference.) 10.7 Employment agreement dated May 27, 1999 between Susann G. Mark, Vice President, General Counsel, and Corporate Secretary and the Registrant. (Filed as Exhibit 10a to Form 10-Q for the quarter ended June 30, 1999, incorporated herein by this reference.) 10.8 Employment Agreement dated October 29, 1997 between Gerald A. Yurkevicz, Vice President, Marketing and the Registrant. (Filed as Exhibit 10.9 to the report of the Registrant in Form 10-K for the year ended September 30 1997, incorporated herein by this reference.) 10.9 Employment Agreement date May 2, 1999 between James M. Stephens, President and Providence Energy Services, Inc. (Filed as Exhibit 10b to the report of the Registrant in Form 10-Q for the quarter ended June 30, 1999, incorporated herein by this reference.) 10.10 Employment Agreement dated October 1, 1998 between Peter J. Gill, Vice President of Information Technology and The Providence Gas Company. (Filed as Exhibit 10d to the report of the Registrant in Form 10-Q for the quarter ended June 30, 1999, incorporated herein by this reference.) 10.11 Employment Agreement dated July 9, 1999 between Royalynne J. Hourihan, Vice President of Human Resources and the Registrant. 10.12 Redacted gas supply contract dated October 1, 1997 between Duke Energy Trading and Marketing, L.L.C. and The Providence Gas Company. (Filed as Exhibit 10 to the report of The Providence Gas Company on Form 10-Q for the quarter ended June 30, 1998, incorporated herein by this reference.) 10.13 1989 Non-Employee Director Stock Option Plan (incorporated by reference to Exhibit A to the Registrant's proxy statement for the annual meeting of shareholders held January 9, 1989, heretofore filed with the Securities and Exchange Commission). 10.14 1989 Stock Option Plan (incorporated by reference to Exhibit B to the Registrant's proxy statement for the annual meeting of shareholders held January 9, 1989, heretofore filed with the Securities and Exchange Commission). IV-3 10.15 Non-Employee Director Stock Plan (incorporated by reference to Exhibit 4.3 to Form S-8 (Registration No. 333-25415). 10.16 1998 Performance Share Plan. (Filed as Exhibit 10.13 to the report of the Registrant on Form 10-K for the year ended September 30, 1998, incorporated herein by this reference.) 10.17 Performance Share Award Agreement dated January 1, 1999 between James H. Dodge, Chairman, President, and Chief Executive Officer and the Registrant. (Filed as Exhibit 10a to the report of the Registrant on Form 10-Q for the quarter ended December 31, 1998, incorporated herein by this reference.) 10.18 Performance Share Award Agreement dated January 1, 1999 between James DeMetro, Senior Vice President and the Registrant. (Filed as Exhibit 10b to the report of the Registrant on Form 10-Q for the quarter ended December 31, 1998, incorporated herein by this reference.) 10.19 Performance Share Award Agreement dated January 1, 1999 between Gary S. Gillheeney, Senior Vice President, Chief Financial Officer, Treasurer and Assistant Secretary and the Registrant. (Filed as Exhibit 10c to the report of the Registrant on Form 10-Q for the quarter ended December 31, 1998, incorporated herein by this reference.) 10.20 Performance Share Award Agreement dated January 1, 1999 between Robert W. Owens, Senior Vice President and the Registrant. (Filed as Exhibit 10d to the report of the Registrant on Form 10-Q for the quarter ended December 31, 1998, incorporated herein by this reference.) 10.21 Performance Share Award Agreement dated January 1, 1999 between Susann G. Mark, Vice President, General Counsel, and Secretary and the Registrant. (Filed as Exhibit 10e to the report of the Registrant on Form 10-Q for the quarter ended December 31, 1998, incorporated herein by this reference.) 10.22 Liquified Natural Gas Service Precedent Agreement dated December 11, 1998 between Algonquin LNG, Inc. and the Registrant. (Filed as exhibit 10a to the report of The Providence Gas Company in Form 10-Q for the quarter ended December 31, 1998, incorporated herein by this reference.) 13 Portions of the Annual Report to Shareholders for the fiscal year ended September 30, 1999. (Pages 1 through 41) 21 Subsidiaries of the Registrant. IV-4 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To The Board of Directors of Providence Energy Corporation: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Providence Energy Corporation's annual report to shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated November 2, 1999. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed in the accompanying index to the financial statements is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein, in relation to the basic financial statements taken as a whole. Arthur Andersen LLP Boston, Massachusetts November 2, 1999 (except for the information discussed in Note 2, as to which the date is November 16, 1999) IV-5 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS To The Board of Directors of Providence Energy Corporation: As independent public accountants, we hereby consent to the incorporation by reference of our report dated November 2, 1999 (except for the information discussed in Note 2, as to which the date is November 16, 1999), included in this Form 10-K, into the Company's previously filed Registration Statements on Forms S-3, Registration No. 33-62318; S-3, Registration No. 33-70086; S-3, Registration No. 33-31768; S-3, Registration No. 333-70997; S-3, Registration No. 333-84379; S-8, Registration No. 33-31769; S-8, Registration No. 33-31770; S-8, Registration No. 33-43031; S-8, Registration No. 33-04209; S-8, Registration No. 333-25415; S-8, Registration No. 333-84311; S-8, Registration No. 333-84301; and S-8, Registration No. 333-84383. It should be noted that we have not audited any financial statements of the Company subsequent to September 30, 1999, or performed any audit procedures subsequent to the date of our report. Arthur Andersen LLP /s/ Arthur Andersen LLP - ----------------------- Boston, Massachusetts December 21,1999 IV-6 Supplemental Schedule PROVIDENCE ENERGY CORPORATION Schedule II ----------------------------- RESERVES FOR THE YEARS ENDED ---------------------------- SEPTEMBER 30, 1999, SEPTEMBER 30, 1998 AND SEPTEMBER 30, 1997 ------------------------------------------------------------- (Thousands of Dollars)
Charge for Which Additions Reserves Balance Charged Other Were Balance 9/30/98 to Operations Add (Deduct) Created 9/30/99 ------- ------------- ------------ ------- ------- RESERVES DEDUCTED FROM ASSETS: Accounts receivable Allowance for doubtful accounts $ 2,604 $ 4,756 $ 150 (D) $ 4,654 $ 2,856 Allowance for lease receivables - current 26 - - - 26 other 90 3 (90)(D) 2 1 ------- ----------- ------- -------- ------- Total $ 2,720 $ 4,759 $ 60 $ 4,656 $ 2,883 ======= =========== ======= ======== ======= Allowance for lease receivables - long-term $ 372 $ 72 $ (183)(D) $ 75 $ 186 ======= =========== ======= ======== ======= DEFERRED CREDITS AND RESERVES: Accumulated deferred income taxes $22,292 $ 888 $ 971 (F) $ - $24,151 ------- ----------- -------- -------- ------- Unamortized investment tax credit 2,217 - - 158 2,059 ------- ----------- -------- -------- ------- Accrued pension 5,812 427 796 (A) 53 6,982 ------- ----------- -------- -------- ------- Accrued environmental 1,750 - (1,750)(C) - - ------- ----------- -------- -------- ------- Other- Liability and damage reserve 479 126 74 (E) 185 494 Other 52 - - 7 45 ------- ----------- -------- -------- ------- Total other 531 126 74 192 539 ------- ----------- -------- -------- ------- Total deferred credits and reserves $32,602 $ 1,441 $ 91 $ 403 $33,731 ======= =========== ======== ======== =======
IV-7 Schedule II (cont'd)
Charge for Which Additions Reserves Balance Charged Other Were Balance 9/30/97 to Operations Add (Deduct) Created 9/30/98 ------- ------------- ------------ ------- ------- RESERVES DEDUCTED FROM ASSETS: Accounts receivable Allowance for doubtful accounts $ 1,811 $ 5,063 $ 47 $ 4,317 $ 2,604 Allowance for lease receivables - current 27 - - 1 26 other 48 42 - - 90 ------- ------- ------- ------- ------- Total $ 1,886 $ 5,105 $ 47 $ 4,318 $ 2,720 ======= ======= ======= ======= ======= Allowance for lease receivables - long-term $ 401 $ 72 $ - $ 101 $ 372 ======= ======= ======= ======= ======= DEFERRED CREDITS AND RESERVES: Accumulated deferred income taxes $21,495 $ 1,131 $ (334)(E) $ - $22,292 ------- ------- ------- ------- ------- Unamortized investment tax credit 2,375 - - 158 2,217 ------- ------- ------- ------- ------- Accrued pension 6,740 84 (961)(A) 51 5,812 ------- ------- ------- ------- ------- Accrued environmental 1,750 - - - 1,750 ------- ------- ------- ------- ------- Other- Liability and damage reserve 621 (21) - 121 479 Other 58 - - 6 52 ------- ------- ------- ------- ------- Total other 679 (21) - 127 531 ------- ------- ------- ------- ------- Total deferred credits and reserves $33,039 $ 1,194 $(1,295) $ 336 $32,602 ======= ======= ======= ======= =======
IV-8 Schedule II (cont'd)
Charge for Which Additions Reserves Balance Charged Other Were Balance 9/30/96 to Operations Add (Deduct) Created 9/30/97 ------- ------------- ------------ ------- ------- RESERVES DEDUCTED FROM ASSETS: Accounts receivable Allowance for doubtful accounts $ 3,195 $ 5,200 $ - $ 6,584 $ 1,811 Allowance for lease receivables - current 27 1 - 1 27 other 9 94 - 55 48 ------- ------- ------- ------- ------- Total $ 3,231 $ 5,295 $ - $ 6,640 $ 1,886 ======= ======= ======= ======= ======= Allowance for lease receivables - long-term $ 403 $ 138 $ - $ 140 $ 401 ======= ======= ======= ======= ======= DEFERRED CREDITS AND RESERVES: Accumulated deferred income taxes $20,713 $ 703 $ 79 (E) $ - $21,495 ------- ------- ------- ------- ------- Unamortized investment tax credit 2,533 - - 158 2,375 ------- ------- ------- ------- ------- Accrued pension 5,670 634 475 (A) 39 6,740 ------- ------- ------- ------- ------- Accrued environmental 1,300 - 450 (B) - 1,750 ------- ------- ------- ------- ------- Other- Liability and damage reserve 561 281 - 221 621 Other 80 (3) - 19 58 ------- ------- ------- ------- ------- Total other 641 278 - 240 679 ------- ------- ------- ------- ------- Total deferred credits and reserves $30,857 $ 1,615 $ 1,004 $ 437 $33,039 ======= ======= ======= ======= =======
(A) Adjustment to the regulatory pension liability. (B) Accrual for environmental investigation and remediation costs. (C) A reclassification of environmental liabilities from long-term to short-term. (D) Account reclassifications during system conversion. (E) Reclassify amounts due to the Registrant to a receivable account. (F) Represents offset for certain SFAS No. 109 activity in the regulatory asset and liability accounts, as well as reclassifications among tax accounts based on tax return as filed and estimated current year tax activity. IV-9 INCORPORATION BY REFERENCE INTO REGISTRATION STATEMENTS ON FORM S-8 For the purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the Registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into Part II of Registrant's Registration Statements on Form S-8 Nos. 33-31769, 33-31770, 33-43031, 33-04209, 333-25415, 333-84311, 333-84301, and 333-84383. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the Securities being registered, the Registrant will, unless in the opinion of its counsel that matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act, will be governed by the final adjudication of such issue. IV-10 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PROVIDENCE ENERGY CORPORATION By: /s/ JAMES H. DODGE ---------------------------------------- James H. Dodge, Chairman, President and CEO Date: December 21, 1999 ---------------------------------------- Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date - --------- ----- ---- /s/ JAMES H. DODGE Chairman, President and CEO 12/21/99 - -------------------------- -------- James H. Dodge (Principal Executive Officer) /s/ KENNETH W. HOGAN Vice President, Chief Financial 12/21/99 - -------------------------- -------- Kenneth W. Hogan Officer, and Treasurer /s/ GILBERT R. BODELL, JR. Director 12/21/99 - -------------------------- -------- Gilbert R. Bodell, Jr. /s/ JOHN H. HOWLAND Director 12/21/99 - -------------------------- -------- John H. Howland /s/ DOUGLAS H. JOHNSON Director 12/21/99 - -------------------------- -------- Douglas H. Johnson /s/ WILLIAM KREYKES Director 12/21/99 - -------------------------- -------- William Kreykes /s/ PAUL F. LEVY Director 12/21/99 - -------------------------- -------- Paul F. Levy /s/ M. ANNE SZOSTAK Director 12/21/99 - -------------------------- -------- M. Anne Szostak /s/ KENNETH W. WASHBURN Director 12/21/99 - -------------------------- -------- Kenneth W. Washburn /s/ W. EDWARD WOOD Director 12/21/99 - -------------------------- -------- W. Edward Wood
IV-11 EX-10.11 2 CHANGE OF CONTROL AGREEMENT Exhibit 10.11 Providence Energy Corporation Change of Control Agreement This AGREEMENT is made, entered into, and is effective as of this 9th day of July, 1999 (hereinafter referred to as the "Effective Date"), by and between Providence Energy Corporation, together with its subsidiaries and affiliates (hereinafter referred to as the "Company"), a Rhode Island corporation having its principal offices at Providence Rhode Island and Royalynne J. Hourihan (hereinafter referred to as the "Executive"). WHEREAS, the Executive has been offered employment by the Company in the capacity of Vice President of Human Resources of the Company; WHEREAS, the Executive possesses considerable experience and knowledge of business affairs and operations and, as such, the Executive has unique qualifications to act in an executive capacity for the Company; and WHEREAS, the Company is desirous of encouraging the full attention by the Executive to his/her duties in his/her capacity aforesaid and wishes to make provisions for certain protections of the Executive in the event of the termination of his/her employment under specified conditions. NOW THEREFORE, in consideration of the foregoing and of the mutual covenants and agreements of the parties set forth in this Agreement, and of other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, agree as follows: Section 1 Termination for Good Reason. At any time during the six (6) full calendar month period prior to the effective date of a Change in Control (as defined in Section 2.2) or the twenty four (24) month period following the effective date of a Change in Control (as defined in Section 2.2), the Executive may terminate this Agreement for Good Reason (as defined below) by giving the Board of Directors of the Company thirty (30) calendar days written notice of intent to terminate, which notice sets forth in reasonable detail the facts and circumstances claimed to provide a basis for such termination. Upon the expiration of the thirty (30) day notice period, the Good Reason termination shall become effective, and the Company shall pay and provide to the Executive the benefits set forth in Section 2.1 herein. Good Reason shall mean, without the Executive's express written consent, the occurrence of any one or more of the following: (a) The assignment of the Executive to duties materially inconsistent with the Executive's authorities, duties, responsibilities, and status as an officer of the Company, or a reduction or alteration in the nature or status of the Executive's authorities, duties, or responsibilities from those in effect during the immediately preceding fiscal year; (b) The Company's requiring the Executive to be based at a location which is at least fifty (50) miles further from the Executive's current primary residence than is such residence from the Company's current headquarters, except for required travel on the Company's business to an extent substantially consistent with the Executive's business obligations as of the Effective Date; (c) A reduction by the Company in the Executive's Base Salary as in effect on the Effective Date, which Base Salary is One Hundred Fifteen Thousand Dollars ($115,000.00) as of the Effective Date, or a reduction from any subsequent increase to the Base Salary as of the Effective Date; (d) A material reduction in the Executive's level of participation in any of the Company's short- and/or long-term incentive compensation plans, or employee benefit or retirement plans, policies, practices, or arrangements in which the Executive participates as of the Effective Date; provided, however, that reductions in the levels of participation in any such plans shall not be deemed to be "Good Reason" if the Executive's reduced level of participation in each such program remains substantially consistent with the average level of participation of other executives who have positions commensurate with the Executive's position; or (e) The failure of the Company to obtain a satisfactory agreement from any successor to the Company to assume and agree to perform this Agreement, as contemplated in Section 5.1 herein. Upon a termination for Good Reason within the six (6) full calendar month period prior to the effective date of a Change in Control, or within the twenty-four (24) months following the effective date of a Change in Control, the Executive shall be entitled to receive the payments and benefits set forth in Section 2.1 herein. The Executive's right to terminate employment for Good Reason shall not be affected by the Executive's incapacity due to physical or mental illness. The Executive's continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting Good Reason herein. 2 Section 2 Change in Control 2.1 Employment Terminations in Connection with a Change in Control. In the event of a Qualifying Termination (as defined below) within six (6) full calendar months prior to the effective date of a Change in Control, or within twenty-four (24) months following the effective date of a Change in Control, then in lieu of all other benefits provided to the Executive under the provisions of this Agreement, the Company shall pay to the Executive in a lump sum payment and provide him/her with the following severance benefits (hereinafter referred to as the "Severance Benefits"): (a) An amount equal to two (2) times the highest rate of the Executive's annualized Base Salary rate in effect at any time up to and including the effective date of termination; (b) An amount equal to two (2) times the Executive's target incentive award (both cash and long-term) established for the fiscal year in which the Executive's effective date of termination occurs; (c) An amount equal to the Executive's unpaid Base Salary and accrued vacation pay through the effective date of termination; (d) An amount equal to the Executive's unpaid targeted annual bonus, established for the plan year in which the Executive's effective date of termination occurs, multiplied by a fraction, the numerator of which is the number of completed days in the then-existing fiscal year through the effective date of termination, and the denominator of which is three hundred sixty-five (365); (e) A continuation of the welfare benefits of medical insurance, dental insurance, and group term life insurance for two (2) full years after the effective date of termination. These benefits shall be provided to the Executive at the same premium cost, and at the same coverage level, as in effect as of the Executive's effective date of termination. However, in the event the premium cost and/or level of coverage shall change for all employees of the Company, the cost and/or coverage level, likewise, shall change for the Executive in a corresponding manner. The continuation of these welfare benefits shall be discontinued prior to the end of the two (2) year period in the event the Executive has available substantially similar benefits from a subsequent employer, as determined by the Company's Board of Directors or the Board's designee. 3 (f) A lump-sum cash payment of the actuarial present value equivalent of the aggregate benefits accrued by the Executive as of the effective date of termination under the terms of any and all supplemental retirement plans in which the Executive participates. For purposes of determining "final average pay" under such programs, the Executive's actual pay history as of the effective date of termination shall be used. For purposes of this Section 2, a Qualifying Termination shall mean any termination of the Executive's employment other than: (1) by the Company for Cause; (2) by reason of death, Disability, or Retirement (as such term is then defined in the Company's tax qualified defined benefit retirement plan; provided that a termination which qualifies as a Retirement and which would otherwise qualify as a termination for Good Reason under Section 1 herein will be deemed to be a Qualifying Termination). 2.2 Definition of "Change in Control." A Change in Control of the Company shall be deemed to have occurred as of the first day any one or more of the following conditions shall have been satisfied: (a) Any individual, corporation (other than the Company), partnership, trust, association, pool, syndicate, or any other entity or any group of persons acting in concert becomes the beneficial owner, as that concept is defined in Rule 13d-3 promulgated by the Securities and Exchange Commission under the Securities Exchange Act of 1934, of securities of the Company possessing twenty percent (20%) or more of the voting power for the election of directors of the Company; (b) There shall be consummated any consolidation, merger, or other business combination involving the Company or the securities of the Company in which holders of voting securities of the Company immediately prior to such consummation own, as a group, immediately after such consummation, voting securities of the Company (or, if the Company does not survive such transaction, voting securities of the corporation surviving such transaction) having less than sixty percent (60%) of the total voting power in an election of directors of the Company (or such other surviving corporation); (c) During any period of two (2) consecutive years, individuals who at the beginning of such period constitute the directors of the Company cease for any reason to constitute at least a majority thereof unless the election, or the nomination for election by the Company's shareholders, of each new director of the Company was approved by a vote of at least two-thirds (2/3) of the directors of the Company then still in office who were directors of the Company at the beginning of any such period; or 4 (d) There shall be consummated any sale, lease, exchange, or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of the Company (on a consolidated basis) to a party which is not controlled by or under common control with the Company. 2.3 Excise Tax Equalization Payment. In the event that the Executive becomes entitled to Severance Benefits or any other payment or benefit under this Plan, or under any other agreement with or plan of the Company (in the aggregate, the "Total Payments"), if any of the Total Payments will be subject to the tax (the "Excise Tax") imposed by Section 4999 of the Code (or any similar tax that may hereafter be imposed), the Company shall pay to the Executive in cash an additional amount (the "Gross-Up Payment") such that the net amount retained by the Executive after deduction of any Excise Tax upon the Total Payments and any Federal, state and local income tax and Excise Tax upon the Gross-Up Payment provided for by this Section 7.3 (including FICA and FUTA), shall be equal to the Total Payments. Such payment shall be made by the Company to the Executive as soon as practical following the effective date of termination, but in no event beyond thirty (30) days from such date. 2.4 Tax Computation. For purposes of determining whether any of the Total Payments will be subject to the Excise Tax and the amounts of such Excise Tax: (a) Any other payments or benefits received or to be received by the Executive in connection with a Change in Control of the Company or the Executive's termination of employment (whether pursuant to the terms of this Plan or any other plan, arrangement, or agreement with the Company, or with any person (which shall have the meaning set forth in Section 3(a)(9) of the Securities Exchange Act of 1934, including a "group" as defined in Section 13(d) therein) whose actions result in a Change in Control of the Company or any person affiliated with the Company or such persons) shall be treated as "parachute payments" within the meaning of Section 280G(b)(2) of the Code, and all "excess parachute payments" within the meaning of Section 280G(b)(1) shall be treated as subject to the Excise Tax, unless in the opinion of tax counsel as supported by the Company's independent auditors and acceptable to the Executive, such other payments or benefits (in whole or in part) do not constitute parachute payments, or unless such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered within the meaning of Section 280G(b)(4) of the Code in excess of the base amount within the meaning of Section 280G(b)(3) of the Code, or are otherwise not subject to the Excise Tax; (b) The amount of the Total Payments which shall be treated as subject to the Excise Tax shall be equal to the lesser of: (i) the total amount of the Total Payments; or (ii) the amount of excess parachute payments within the meaning of Section 280G(b)(1) (after applying clause (a) above); and 5 (c) The value of any noncash benefits or any deferred payment or benefit shall be determined by the Company's independent auditors in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. For purposes of determining the amount of the Gross-Up Payment, the Executive shall be deemed to pay federal income taxes at the highest marginal rate of Federal income taxation in the calendar year in which the Gross-Up Payment is to be made, and state and local income taxes at the highest marginal rate of taxation in the state and locality of the Executive's residence on the effective date of termination, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. 2.5 Subsequent Recalculation. In the event the Internal Revenue Service adjusts the computation of the Company under Section 2.4 herein so that the Executive did not receive the greatest net benefit, the Company shall reimburse the Executive for the full amount necessary to make the Executive whole, plus a market rate of interest, as determined by the Human Resources and Planning Committee. 2.6 Payment of Legal Fees. To the extent permitted by law, the Company shall pay all legal fees, costs of litigation, prejudgment interest, and other expenses incurred in good faith by the Executive as a result of the Company's refusal to provide the severance benefits under this Section 2 to which the Executive becomes entitled under this Agreement, or as a result of the Company's contesting the validity, enforceability, or interpretation of this Agreement, or as a result of any conflict (including conflicts related to the calculation of parachute payments) between the parties pertaining to their Agreement. Section 3. Indemnification The Company hereby covenants and agrees to indemnify and hold harmless the Executive fully, completely, and absolutely against and in respect to any and all actions, suits, proceedings, claims, demands, judgments, costs, expenses (including attorney's fees), losses, and damages resulting from the Executive's good faith performance of his/her duties and obligations under the terms of this Agreement. Section 4. Outplacement Assistance Following a termination of the Executive's employment as described in Sections 1 or 2 herein, the Executive shall be reimbursed by the Company for the costs of all outplacement services obtained by the Executive within the six (6) months prior and two (2) year periods after the effective date of termination; provided, however, that the total reimbursement shall be limited to an amount equal to fifteen percent (15%) of the Executive's Base Salary as of the effective date of termination. 6 Section 5. Assignment 5.1 Assignment by Company. This Agreement may and shall be assigned or transferred to, and shall be binding upon and shall inure to the benefit of, any successor of the Company, and any such successor shall be deemed substituted for all purposes of the "Company" under the terms of this Agreement. As used in this Agreement, the term "successor" shall mean any person, firm, corporation, or business entity which at any time, whether by merger, purchase, or otherwise, acquires all or essentially all of the assets of business of the Company. Notwithstanding such assignment, the Company shall remain, with such successor, jointly and severally liable for all its obligations hereunder. Failure of the Company to obtain such agreement prior to the effectiveness of any such succession shall be a breach of this Agreement and shall immediately entitle the Executive to compensation from the Company in the same amount and on the same terms as the Executive would be entitled in the event of a termination by the Company, as provided in Section 2.1 herein. Except as herein provided, this Agreement may not otherwise be assigned by the Company. 5.2 Assignment by Executive. This Agreement shall inure to the benefit of and be enforceable by the Executive's personal or legal representatives, executors, and administrators, successors, heirs, distributees, devisees, and legatees. If the Executive should die while any amounts payable to the Executive hereunder remain outstanding, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Executive's devisee, legatee, or other designee or, in the absence of such designee, to the Executive's estate. Section 6. Dispute Resolution and Notice 6.1 Arbitration. Any dispute or controversy arising under or in connection with this Agreement shall be settled by arbitration, conducted before a panel of three (3) arbitrators sitting in a location selected by the Executive within fifty (50) miles from the location of his/her employment with the Company, in accordance with the rules of the American Arbitration Association then in effect. Judgment may be entered on the award of the arbitrator in any court having proper jurisdiction. All expenses of such arbitration, including the fees and expenses of the counsel for the Executive, shall be borne by the Company. 6.2 Notice. Any notices, requests, demands, or other communications provided for by this Agreement shall be sufficient if in writing and if sent by registered or certified mail to the Executive at the last address she has filed in writing with the Company or, in the case of the Company, at its principal offices. 7 Section 7. Miscellaneous 7.1 Entire Agreement. This Agreement supersedes any prior agreements or understandings, oral or written, between the parties hereto or between the Executive and the Company, with respect to the subject matter hereof and constitutes the entire Agreement of the parties with respect thereto. 7.2 Modification. This Agreement shall not be varied, altered, modified, canceled, changed, or in any way amended except by mutual agreement of the parties in a written instrument executed by the parties hereto or their legal representatives. 7.3 Severability. In the event that any provision or portion of this Agreement shall be determined to be invalid or unenforceable for any reason, the remaining provisions of this Agreement shall be unaffected thereby and shall remain in full force and effect. 7.4 Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement. 7.5 Tax Withholding. The Company may withhold from any benefits payable under this Agreement all federal, state, city, or other taxes as may be required pursuant to any law or govern-mental regulation or ruling. 7.6 Beneficiaries. The Executive may designate one or more persons or entities as the primary and/or contingent beneficiaries of any amounts to be received under this Agreement. Such designation must be in the form of a signed writing acceptable to the Board or the Board's designee. The Executive may make or change such designation at any time. Section 8. Governing Law To the extent not preempted by federal law, the provisions of this Agreement shall be construed and enforced in accordance with the laws of the state of Rhode Island. IN WITNESS WHEREOF, the Executive and the Company (pursuant to a resolution adopted at a duly constituted meeting of its Board of Directors) have executed this Agreement, as of the day and year first above written. Executive: _____________________________________ ATTEST Providence Energy Corporation By:______________________ By:__________________________________ Corporate Secretary Chairman, President and CEO 8 EX-13 3 ANALYSIS OF FINANCIAL CONDITION Exhibit 13 Management's Discussion and Analysis of Financial Condition and Results of Operations Summary The Company's energy revenues, operating margin, and net income for the twelve months ended September 30 are as follows: (000's) Percent 1999 1998 Change Change - ---------------------------------------------------------------- Energy Revenues $225,029 $222,112 $2,917 1.3 Operating Margin 105,986 99,121 6,865 6.9 Net Income 8,425 6,442 1,983 30.8 Results of Operations - 1999 Versus 1998 Operating Margin During the current year, weather was 1.3 percent warmer than last year. The warmer temperatures served to decrease margin by approximately $.3 million compared to last year. Despite warmer than normal weather for the year, margin earned increased as a result of a one-time write-off of $1.5 million in 1998 of previously deferred gas costs in connection with Energize RI, which became effective October 1, 1997. Offsetting the warmer weather for the year was $2.0 million of the $2.45 million 1998 exogenous changes recovery, as discussed in Note 10 in the accompanying Consolidated Financial Statements. Also, ProvGas' customer growth has resulted in approximately $.6 million of additional margin, and non-firm margin increased $.4 million when compared with last year. During April and May 1999, the Algonquin LNG, Inc. tank in Providence was completely emptied in order to allow access for internal inspection and repairs, which were completed in September 1999. As a result, 335 million cubic feet of LNG was vaporized from the tank into the ProvGas distribution system. Since the vaporized gas had a heat energy content approximately 30 percent higher than the pipeline supplies normally used, ProvGas' customers' metered volumes were lower because a smaller volume of gas produced the same quantity of energy. This in turn adversely impacted margin. Non-regulated operating margin increased by $2.7 million compared to last year. The margin earned from oil sales increased by approximately $1.4 million in 1999 due primarily to the market price of oil and to customer growth. Natural gas business volumes increased by approximately 50 percent. This increase was a result of 43 percent customer growth as well as an increase in dual fuel sales volumes. The receipt of contractually-determined developer fees related to the Providence Place Mall also contributed to the increase in non- regulated operating margin. Operating and Maintenance Expenses Overall, the Company's operating and maintenance expenses increased approximately $1.1 million or 2.0 percent versus last year. ProvGas' operating and maintenance expenses decreased by approximately $.3 million. This decrease was partially attributable to cost control measures which were implemented in response to warmer weather. These cost control measures were able to offset a substantial portion of the cost of living and negotiated union contract salary increases of approximately $.9 million, as well as inflationary increases in general expenses of approximately $.5 million. Also contributing to the decrease was a one-time reimbursement of approximately $.9 million for costs incurred under a FERC-approved contract with Algonquin. The Company's operating and maintenance expenses have increased primarily due to the acquisition of oil companies and the expansion of the energy marketing business. The Company continually reviews its operating expenses in order to keep expenses as low as possible; however, expenses can vary from year to year. Page 1 Depreciation and Amortization Depreciation and amortization expense increased approximately $3.0 million or 20.8 percent versus last year. This increase is the result of increased capital spending for Energize RI commitments; technology projects; Year 2000 costs, which were capitalized as authorized under the provisions of Energize RI; and the amortization of environmental costs. Effective October 1, 1997, ProvGas began amortizing environmental and Year 2000 costs over 10-year and 5-year periods, respectively, in accordance with the levels authorized in Energize RI. ProvGas will have increased environmental amortization expense in future years as its planned environmental remediation program continues. Also, amortization expense for Year 2000 costs will increase in the future as higher levels of costs have been incurred from those originally anticipated. Taxes Taxes increased approximately $.6 million or 4.1 percent versus last year. The increase in taxes is primarily due to local property taxes which have increased as a result of capital spending. Other Income (Loss) Other income has increased approximately $1.1 million versus last year. Since February 1999, ProvGas has provided monitoring and communication services to the PNGTS. Under its contract, ProvGas hosts PNGTS' Supervisory Control and Data Acquisition System, continually monitoring system operations and receiving and forwarding emergency phone calls. ProvGas has recognized as other income approximately $.2 million in fees for the performance of these services. The contract is a one year renewable contract, subject to termination by either party upon six months prior written notice. PNGTS has notified ProvGas that they will put the contract to bid for the contract year beginning February 17, 2000. In a decision issued September 1, 1998, the Division rejected allegations made in a complaint brought by Aurora Natural Gas that ProvGas provided advance information and undue preference in pricing to its marketing affiliate, ProvEnergy Services, in violation of the Division's regulations. As part of its investigation, the Division ordered marketer refunds of approximately $.3 million. The Division ordered this refund based on its belief that an unfair rate was charged to customers who did not have operational telemeters in place when they began service under the transportation tariff. ProvGas filed a Request for Reconsideration and Rehearing, and on December 15, 1998, the Division issued a Reconsideration Order that rescinded the fines stemming from five of the original 23 violations of the Regulations for Utility Interaction with Gas Marketers. The Division further offered the Company an opportunity to demonstrate its claim that the ordered refunds would place FT-2 marketers in a better position than marketers who served FT-1 customers. On May 6, 1999, ProvGas and Aurora jointly submitted a Stipulation and Settlement to the Division that: (i) Aurora's complaint in this proceeding is dismissed; (ii) the prior orders of the Division in the proceeding are dismissed; (iii) no refunds by ProvGas are required or appropriate in connection with the proceeding; and (iv) ProvGas does not contest the payment of $18,000 to the Division in connection with this proceeding. Following a June 16, 1999 hearing on the Stipulation, the Division issued an order on September 23, 1999, approving the Stipulation and Settlement provided that ProvGas ratepayers are held harmless from the financial transactions stemming from the settlement, that ProvGas withdraw its appeal in Providence County Superior Court, and that the Division's prior orders are vacated as described in the order. ProvGas and Aurora accepted the Division's order. This decision resulted in the reversal of the reserve established under the original order, which contributed to the increase in other income this year. Interest Expense Interest expense increased approximately $.6 million or 7.0 percent over last year. Long-term interest expense increased as a result of ProvGas' Series T First Mortgage Bond issuance in February 1999, which refinanced short-term borrowings. The Series T issuance enabled the Company to secure a favorable long-term financing rate. However, this increase was partially offset by the Series S First Mortgage Bond issuance in April 1998, which refinanced higher cost long-term debt. Page 2 Future Outlook A) Regulatory Under Energize RI, ProvGas may earn up to 10.9 percent, but not less than 7.0 percent, annually on its average common equity, which is capped at $81.0 million, $86.2 million, and $92.0 million in fiscal 1998, 1999, and 2000, respectively. In the event that ProvGas earns in excess of 10.9 percent or less than 7.0 percent, ProvGas will defer revenues or costs through a deferred revenue account over the term of the Plan. Any balance in the deferred revenue account at the end of the Plan will be refunded to or recovered from customers in a manner to be determined by all parties to the Plan and approved by the RIPUC. As part of Energize RI, ProvGas is permitted to file annually with the Division for the recovery of exogenous changes which may occur during the three- year term of the Plan. Exogenous changes are defined as "...significant increases or decreases in ProvGas' costs or revenues which are beyond ProvGas' reasonable control." Any disputes between ProvGas and the Division regarding either the nature or quantification of the exogenous changes are to be resolved by the RIPUC. The impact of any exogenous changes will be debited or credited to a regulatory asset or liability account throughout the term of Energize RI and will be recovered or refunded at the expiration of the Plan through a method to be determined. In fiscal 1998, ProvGas did not earn its allowed rate of return primarily as a result of the extremely warm winter weather and the loss of non-firm margin resulting from the competitive price of oil in the industrial market. ProvGas believed the causes of these two events were beyond its reasonable control and thus deemed them to be exogenous changes. In March 1999, ProvGas reached an agreement with the Division which allowed it to recover $2.45 million in revenue losses attributable to exogenous changes experienced by ProvGas in fiscal 1998. The RIPUC reviewed the exogenous changes agreement to ensure consistency with the terms of Energize RI and affirmed the agreement at its May 28, 1999 open meeting. During fiscal 1999, ProvGas recognized into revenue $2.45 million for the exogenous changes recovery, and at year-end has deferred approximately $.5 million of revenue under the provisions of the earnings cap of Energize RI. ProvGas intends to file for recovery of exogenous changes experienced in 1999 which resulted from factors similar to 1998. Absent further exogenous recovery and/or other factors such as colder than normal weather, ProvGas' ability to earn a 10.9 percent return on average common equity in the final year of Energize RI is substantially impaired. On August 31, 1999, ProvGas' settlement agreement for enhancements to its Business Choice program was approved by the RIPUC in Docket 2902 and became effective September 1, 1999. Specifically, there will now be rolling enrollment for transportation service, which will allow customers to execute transportation agreements throughout the year, rather than during limited enrollment periods. The program now has approximately 1,700 firm transportation customers with annual deliveries of over 5 billion cubic feet per year, which is approximately 25 percent of ProvGas' total annual firm deliveries. There are 14 marketers serving ProvGas' customers and transporting on the system. Additional enhancements to the Business Choice program were filed with the RIPUC under a supplemental settlement agreement in Docket 2902 on October 8, 1999 and were approved on October 27, 1999. These enhancements do not generate additional revenue. B) Business Opportunities The Company's non-regulated operation continues to increase its contribution to operating margin by adding customers and sales volume, although it continues to generate a net loss consistent with the start-up of new businesses. The Company intends to continue to grow its residential oil customer base through future customer acquisitions to build the operational scale needed to compete effectively in the marketplace. Furthermore, the New England gas utilities continue to unbundle the sale of the gas commodity from the distribution of that gas, which will also enable future growth. The Company's joint venture to provide electricity, HVAC, and related services for most of the Mall began with the Mall's August 1999 opening. Page 3 Energize RI provides opportunities for ProvGas to expand sales. For example, high pressure service to Quonset/Davisville Industrial Port & Commerce Park, a key area for State economic development, provides opportunities for sales growth as commercial and industrial businesses locate within the park. In addition, Demand Side Management, an equipment rebate program, provides opportunities to expand sales to non-traditional applications, such as air conditioning and fuel cells. ProvGas has redirected its sales and marketing efforts to leverage Energize RI, as well as other opportunities to promote sales growth within its service territory. C) Merger Agreement On November 15, 1999, the Company and Southern Union announced that their Boards of Directors had unanimously approved a definitive merger agreement. See Note 2 in the accompanying Consolidated Financial Statements for additional information. D) New Accounting Pronouncements Please refer to Note 18 of the accompanying Consolidated Financial Statements. Results of Operations - 1998 versus 1997 Operating Margin During 1998, ProvGas experienced weather that was 8.0 percent warmer than 1997. The warmer temperatures resulted in decreased margin of approximately $4.0 million compared to 1997. Offsetting the warmer than normal weather was $7.2 million of margin generated under Energize RI. The components of this additional margin included $10.4 million associated with adjusting the GCC offset by the funding of the Low-Income and Demand Side Management programs of $1.7 million and the write-off of $1.5 million of previously deferred gas costs. In 1997, ProvGas funded the Demand Side Management and Low-Income Weatherization programs under the IRP for $.7 million. Additionally, non-firm margin decreased $2.2 million when compared with 1997 due to an unfavorable pricing difference between natural gas and alternate fuels. As part of Energize RI, the Mechanism under the IRP was terminated in September 1997. In 1997, ProvGas recorded $1.5 million in additional margin as a result of this Mechanism. Thus, a decrease in margin from 1997 to 1998 occurred because this Mechanism was no longer available in 1998. Non-regulated operating margin increased by $3.7 million compared to the same period in 1997. The Company's acquisition of oil distribution companies during 1998 contributed to the majority of this increase. However, the margin earned from oil sales was lower than expected due to warmer than normal weather, lower than anticipated commercial margins, and costs associated with liquidating fixed-purchase commitments and option contracts for oil when market prices declined significantly. Other increases in non-regulated operating margin were attributable to increased natural gas business volumes and approximately $.2 million of fees earned for providing energy management services. Natural gas sales volume grew 150 percent and a fifteen-fold increase in the number of natural gas customers was achieved. Operating and Maintenance Expenses Overall, operating and maintenance expenses increased approximately $3.2 million or 6.6 percent versus 1997. The increase was primarily attributable to the Company's acquisition of oil companies during 1998 resulting in a $4.1 million increase. This increase was partially offset by decreases in ProvGas' expenses, primarily bad debts. The decrease in bad debts was attributable to improved collection experience and the implementation of new credit policies, as well as decreased operating revenues from warmer than normal weather. ProvGas' other operating and maintenance expenses were essentially flat as a result of additional cost management due to the warmer weather. Depreciation and Amortization Depreciation and amortization expense increased approximately $1.6 million or 12.5 percent versus 1997. This increase was the result of increased capital spending for Energize RI commitments as well as the amortization of previously deferred environmental costs. Effective October 1, 1997, ProvGas began amortizing environmental costs over a 10-year period in accordance with the levels approved in Energize RI. Page 4 Taxes Taxes increased approximately $.2 million or 1.8 percent versus 1997. The overall change in taxes was primarily due to local property and other taxes which increased as a result of capital spending. Other Income (Loss) Other income increased approximately $.3 million versus 1997, primarily consisting of approximately $.2 million of interest income earned on Federal income tax refunds resulting from amended tax returns. Interest Expense Interest expense increased approximately $.5 million or 7.0 percent versus 1997. ProvGas' interest expense increased by approximately $.3 million as a result of the Series S First Mortgage Bond issuance in April 1998. The Company's acquisition of oil distribution companies in November 1997 resulted in increased interest expense of approximately $.5 million. Offsetting the increases was a decrease in weighted average short-term borrowings as a result of the Series S First Mortgage Bond issuance. Liquidity and Capital Resources - ------------------------------- The Company's cash flow from operating activities decreased approximately $17.3 million for the fiscal year ended September 30, 1999 compared to 1998. On a comparative basis, the current year cash flow decreased as a result of the prior year reflecting receipt of funds in the first quarter of fiscal 1998 from the sale of ProvGas' working gas in storage to Duke Energy Trading and Marketing, L.L.C. under the terms of the parties' gas supply agreement. This decrease in operating cash flow was offset by a temporary increase in accounts payable this year related to the timing of such gas supply payments. Capital expenditures for the fiscal year ended September 30, 1999 of $39.5 million reflect an increase of $8.4 million or 26.9 percent when compared to $31.1 million last year. This spending increase was due primarily to ProvGas' technology expenditures related to Year 2000, system enhancements and environmental remediation expenditures. Capital expenditures for fiscal years 2000 and 2001 are expected to be approximately $54.5 million in total. During the current fiscal year, the Company's cash provided by financing activities increased $29.7 million. ProvGas issued $15 million in Series T First Mortgage Bonds on February 8, 1999. The Series T bonds are for a 30 year term at an interest rate of 6.5 percent. ProvGas has received an order from the Division which permits the amortization of the Series M bond repurchase premium over the life of the Series T bonds. The proceeds were used to reduce borrowings under its lines of credit as well as for general corporate purposes. This reduction in borrowings was more than offset by an increase in short-term notes payable of approximately $18.2 million, which was used primarily as bridge financing for the Company's investment in the Mall. The Company anticipates obtaining permanent financing for the Mall during the first quarter of fiscal 2000. In September 1999, the Company made a capital contribution of $4.8 million to ProvGas in order to fund working capital requirements. Hedging The Company's strategy is to use financial instruments for hedging purposes to manage the impact of market fluctuations on non-regulated contractual sales commitments. Financial instruments manage market risks and reduce exposure to fluctuations in the market prices of home heating oil, diesel, heavy oil, and natural gas. At September 30, 1999 and 1998, the non-regulated operation held oil futures and option contracts with fair market values of approximately $.1 million and $.2 million, respectively. The estimated fair market value of these contracts is based on quoted market prices. The contracts have maturities of one year or less. Net unrealized gains related to these instruments of approximately $40,000 have been deferred on the Page 5 accompanying Consolidated Balance Sheets as a component of common stockholders' equity at both September 30, 1999 and 1998. During 1998, the non-regulated operation incurred approximately $.5 million of costs associated with liquidating fixed purchase commitments and option contracts for oil when market prices dropped. At September 30, 1999 and 1998, the non-regulated operation held forward purchase commitments for its supply needs with fair market values of approximately $13.8 million and $15.2 million, which were acquired at costs of approximately $12.2 million and $15.6 million, respectively. The fair market values of these forward contracts are based on quoted market prices and the contracts have maturities of less than one year. Year 2000 Update The Company's Year 2000 Project is substantially complete. The Project addresses the problem arising from the use in software programs and computing infrastructures of two-digit years to define the applicable year, rather than four-digit years, and from time-sensitive software that may recognize a date using "00" as the last two digits of the year 1900, rather than the year 2000. Readiness The Company recognizes that the products and services that the Company provides to its customers are essential, and senior management has made Year 2000 readiness a top priority. The Company's Year 2000 Project Office has been working with two international consulting firms to ensure the continuity of mission critical business systems and processes before and beyond the Year 2000. The Company has organized the Project around the following four major areas: 1. Information Technology Systems The Company continues to implement its technology plan, which includes the migration from a mainframe centric to a client server centric environment. The migration includes the replacement of CIS which supports the business functions of customer inquiry, service orders, and billing. The migration also includes the replacement of business applications such as financial, human resources, and procurement with a new client server based financial system. These new business applications have been represented to be Year 2000 ready by their respective vendors. Validation testing of these systems for Year 2000 readiness has been completed. Both the CIS and client server based financial system have been successfully placed into operation. The Company completed an inventory and assessment of its existing IT systems and IT infrastructure in March 1999. All mission critical and important systems have been remediated and tested for Year 2000 readiness. The Company has implemented procurement policies as part of its efforts to ensure Year 2000 readiness. These policies address any future changes to the Company's IT systems environment and its future acquisitions of IT systems. 2. Embedded Systems Embedded microprocessors are found in equipment deployed in the Company's distribution and facility operations. The distribution area includes, but is not limited to, the monitoring, storage, measurement, and control of the flow of natural gas. The facility area includes, but is not limited to, back-up power supply, HVAC, and security at the Company's offices. The Company has successfully completed the assessment, remediation, and testing of all mission critical and important embedded systems including ProvGas' Supervisory Control and Data Acquisition gas distribution system. 3. Upstream/Downstream The Company has contacted all of its major suppliers, and none has indicated concern for potential business disruption. The Company's major suppliers critical to the delivery of natural gas to its system include interstate pipelines, Duke Energy Trading and Marketing, New England Electric System, and Bell Atlantic, which have indicated that they are following comprehensive programs on a timely schedule designed to achieve Year 2000 readiness. Page 6 While the Company cannot guarantee Year 2000 readiness of these and other suppliers, the information received from them indicates that they expect to fulfill their obligations to the Company on and after January 1, 2000. The Company will continue to monitor the status of all critical suppliers throughout 1999. Any risk areas that surface as a result of these assessments are being addressed in contingency planning. The Company is actively participating with the Rhode Island Y2K Association which acts as a communication forum for key customers as well as the other essential suppliers of services such as telecommunications, water, and electricity. The Company is also communicating its Year 2000 readiness to customers in bill stuffers, on its website and in state-sponsored "town meetings" throughout its service territory. On February 17, 1999, ProvGas provided testimony to the RIPUC regarding ProvGas' Year 2000 readiness and since then has filed quarterly updates with the RIPUC. 4. Contingency Planning The Company has contingency plans in place for response to certain emergency operational situations. In addition, the Company has completed over 50 workshops to develop actionable contingency plans which will specifically address risks to the top 72 business processes related to the Year 2000 computer problem. Such contingency plans include using manual procedures and arranging for alternative suppliers. The Company has developed Year 2000 contingency plans for all mission critical and important business processes. The Company participated in a Year 2000 communications drill with other New England Gas Association local distribution companies and its pipeline supplier, Tennessee Pipeline Company. This planning will help provide mutual aid and assistance if necessary. Year 2000 Costs The Company is capitalizing Year 2000 costs for ProvGas and will amortize these costs over a five-year amortization period consistent with the regulatory levels as authorized by the RIPUC under the Energize RI program. As of September 30, 1999, the Company has deferred Year 2000 costs of approximately $7.6 million and has amortized $.3 million of these costs. In addition, approximately $.1 million of additional costs, which have been expensed, have been incurred by the non-regulated operation. Total costs for Year 2000 are expected to range from $7.7 million to $8.1 million. These estimated costs include external contractors and service providers and the balance of the unrecovered legacy CIS system that has been replaced, as well as other costs associated with the discontinuance of the operation of the mainframe. These estimates do not include Year 2000 costs which may be incurred by joint ventures or partnerships for which the Company does not have primary operating responsibility or for the costs of implementing the new CIS and client server based financial system pursuant to ProvGas' ongoing technology plan. Additionally, the Company does not separately track the internal costs incurred for the Year 2000 project. Such costs are principally the related payroll costs for the information systems group. Internal costs, except for the Year 2000 project manager, have been expensed as incurred. These cost estimates are based on management's best current estimates which were derived utilizing numerous assumptions of future events, including the continued availability of technological and certain other resources, the accuracy of third party assurances and other factors. There can be no guarantee that these estimates will be achieved, and actual results may differ from those discussed above. Risk Assessment No amount of preparation and testing can guarantee Year 2000 readiness. However, the Company believes that it has taken and will take appropriate preventative measures designed to minimize disruption before, during, and after January 1, 2000. A disruption in the extraction or processing, transmission or storage of gas, or its distribution due to Year 2000 problems experienced by the Company's gas suppliers could prevent those suppliers from delivering a sufficient amount of gas to enable the Company to serve certain customer segments. Even if the flow of gas is not disrupted, customers may not be able to receive gas if electrical service is disrupted. In the event that the Company is unable to obtain supplies of oil from third parties, its customers may not be able to receive oil necessary to heat their facilities or residences. Page 7 Because of the difficulty of assessing Year 2000 readiness of these suppliers and others outside the control of the Company, the Company considers potential disruptions by these third parties to present the "reasonably likely worst case scenario." The Company's inability to serve its customers could result in increased costs, loss of revenue, and potential claims. This Year 2000 update contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These forward- looking statements are subject to risks and uncertainties and actual results may differ materially from those described herein. Common Stock Information Dividend Paid Quarter Ended High Low Per Share - -------------------------------------------------------------------------- September 30, 1999 $30 1/8 $26 1/16 $.27 June 30, 1999 27 18 .27 March 31, 1999 22 7/16 18 3/8 .27 December 31, 1998 21 1/2 19 1/16 .27 September 30, 1998 $21 3/8 $19 3/16 $.27 June 30, 1998 21 3/8 19 1/2 .27 March 31, 1998 22 1/8 20 1/2 .27 December 31, 1997 22 3/8 17 5/8 .27 Page 8 Consolidated Balance Sheets September 30
(thousands of dollars) 1999 1998 - --------------------------------------------------------------------------------------------------------- Assets Current assets: Cash and temporary cash investments (notes 1 and 9) $ 2,804 $ 2,006 Accounts receivable, less allowance of $2,883 in 1999 and $2,720 in 1998 (notes 1 and 4) 13,684 14,067 Unbilled revenues (note 1) 2,821 1,665 Inventories, at average cost- Fuel oil and underground gas storage 558 656 Materials and supplies 1,283 1,433 Prepaid and refundable taxes (note 3) 4,215 5,355 Prepayments 2,214 1,853 --------- ---------- 27,579 27,035 --------- ---------- Gas plant, at original cost (notes 1, 5, 8, and 10) 345,671 $ 324,502 Less accumulated depreciation and plant acquisition adjustments (notes 1 and 10) 127,481 125,976 --------- ---------- 218,190 198,526 --------- ---------- Other assets: Other property, net 2,628 2,692 Investments (notes 12 and 14) 11,186 2,169 Deferred environmental costs (notes 8 and 10) 9,719 3,969 Deferred charges and other assets (notes 1, 4, 5, and 7) 28,731 18,997 --------- ---------- 52,264 27,827 --------- ---------- Total assets $ 298,033 $ 253,388 ========= ========== Capitalization and Liabilities Capitalization (see accompanying statement) $ 187,628 $ 173,232 --------- ---------- Current liabilities: Notes payable (notes 6 and 9) 38,250 20,079 Current portion of long-term debt (note 5) 3,515 3,233 Accounts payable (notes 7 and 9) 12,199 9,310 Accrued compensation 1,634 1,337 Accrued environmental costs (notes 8 and 10) 6,145 - Accrued interest 1,647 1,496 Accrued taxes 3,557 2,714 Accrued vacation 1,807 1,706 Accrued workers compensation 595 530 Customer deposits 2,973 3,034 Deferred revenue (note 10) 315 - Energy conservation liablility 1,261 742 Other 2,776 3,373 --------- ---------- 76,674 47,554 --------- ---------- Deferred credits, reserves, and other liabilities: Accumulated deferred Federal income taxes (note 3) 24,151 22,292 Unamortized investment tax credits (note 3) 2,059 2,217 Accrued environmental costs (notes 8 and 10) - 1,750 Accrued pension (note 7) 6,982 5,812 Other 539 531 --------- ---------- 33,731 32,602 --------- ---------- Commitments and contingencies (notes 8 and 10) --------- ---------- Total capitalization and liabilities $ 298,033 $ 253,388 ========= ==========
The accompanying notes are an integral part of these consolidated financial statements. Page 9 Consolidated Statements of Income For the Years Ended September 30
(thousands, except per share amounts) 1999 1998 1997 - ---------------------------------------------------------------------------------------------------------------------- Energy revenues $ 225,029 $ 222,112 $ 220,420 Cost of energy 119,043 122,991 124,376 --------- --------- --------- Operating margin 105,986 99,121 96,044 --------- --------- --------- Operating expenses: Operation and maintenance 53,047 51,993 48,768 Depreciation and amortization 17,496 14,485 12,874 Taxes: State gross earnings 5,673 5,618 6,045 Local property and other 8,880 8,363 7,687 --------- --------- --------- Total operating expenses 85,096 80,459 75,374 --------- --------- --------- Operating income 20,890 18,662 20,670 --------- --------- --------- Other income (loss) (note 1) 1,123 57 (219) --------- --------- --------- Interest expense: Long-term debt 6,827 6,391 6,042 Other 2,262 1,998 1,786 Interest capitalized (389) (256) (225) --------- --------- --------- 8,700 8,133 7,603 --------- --------- --------- Income before Federal income taxes 13,313 10,586 12,848 Provision for Federal income taxes (note 3) 4,540 3,657 4,391 --------- --------- --------- Income before preferred dividends of subsidiary 8,773 6,929 8,457 Preferred dividends of subsidiary (note 5) 348 487 626 --------- --------- --------- Net income $ 8,425 $ 6,442 $ 7,831 ========= ========= ========= Earnings per common share - basic $ 1.40 $ 1.09 $ 1.35 ========= ========= ========= Earnings per common share - diluted $ 1.40 $ 1.09 $ 1.35 ========= ========= ========= Weighted average common shares outstanding (note 13): Basic 6,015.7 5,919.7 5,790.1 ========= ========= ========= Diluted 6,034.1 5,929.7 5,794.3 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. Page 10 Consolidated Statements of Cash Flows For the Years Ended September 30
(thousands of dollars) 1999 1998 1997 - -------------------------------------------------------------------------------------------------------------- Cash provided by - Operating Activities: Income before preferred dividends of subsidiary $ 8,773 $ 6,929 $ 8,457 Items not requiring cash: Depreciation and amortization 17,496 14,485 12,874 Changes as a result of regulatory action (2,357) 1,500 - Gain on sale of financial instruments (note 1) (355) - - Deferred Federal income taxes 888 1,131 703 Loss on sale of real estate - 37 - Amortization of investment tax credits (158) (158) (158) Changes in assets and liabilities which provided (used) cash: Accounts receivable 549 21,504 (187) Unbilled revenues (1,156) 1,018 (326) Deferred gas costs - 78 6,041 Inventories 302 (169) (2,222) Prepaid and refundable taxes 1,731 (1,646) 14 Prepayments (361) (800) 501 Accounts payable 1,529 (3,495) (617) Accrued compensation 297 (607) 323 Accrued interest 151 298 (80) Accrued taxes 1,107 202 526 Accrued vacation, accrued workers compensation, customer deposits, and other (354) 1,105 (631) Accrued pension 1,170 (928) 1,070 Deferred charges and other (2,388) 3,638 1,149 -------- -------- -------- Net cash provided by operating activities 26,864 44,122 27,437 -------- -------- -------- Investment Activities: Expenditures for property, plant, and equipment, net (39,542) (31,150) (20,425) Expenditures for business acquisitions, net of cash acquired (note 15) 275 (2,744) - Investment in joint venture (note 14) (9,071) (2,000) - Proceeds from sale of real estate - 698 - Proceeds from (cash paid for) financial instruments (note 12) 403 (104) - -------- -------- -------- Net cash used in investing activities (47,935) (35,300) (20,425) -------- -------- -------- Financing Activities: Issuance of common stock 23 - 44 Proceeds from exercise of stock options 14 115 34 Issuance of mortgage bonds (note 5) 15,000 15,000 - Repurchase of mortgage bonds - (6,363) - Premium payment on bonds - (1,392) - Redemption of preferred stock (1,600) (1,600) (1,600) Issuance of long-term debt - - 1,345 Payments on long-term debt (4,132) (3,799) (2,164) Increase (decrease) in notes payable 18,171 (4,462) 405 Cash dividends on preferred shares (note 5) (348) (487) (626) Cash dividends on common shares (5,259) (4,891) (4,811) -------- -------- -------- Net cash provided (used) by financing activities 21,869 (7,879) (7,373) -------- -------- -------- Increase (decrease) in cash and temporary cash investments 798 943 (361) Cash and temporary cash investments at beginning of year 2,006 1,063 1,424 -------- -------- -------- Cash and temporary cash investments at the end of year $ 2,804 $ 2,006 $ 1,063 ======== ======== ========
Page 11
Consolidated Statements of Cash Flows For the Years Ended September 30 (continued) (thousands of dollars) 1999 1998 1997 - ------------------------------------------------------------------------------------------ Supplemental disclosure of cash flow information: Cash paid during the year for- Interest (net of amount capitalized) $ 8,283 $ 7,606 $ 7,476 Income taxes (net of refunds) $ 2,821 $ 3,750 $ 2,036 Schedule of non-cash investing activities: Capital lease obligations for equipment $ 131 $ - $ 437 Other long-term debt for equipment $ - $ - $ 1,983 Stock issuance for business acquisition $ 1,548 $ - $ -
The accompanying notes are an integral part of these consolidated financial statements. Page 12 Consolidated Statements of Capitalization September 30
(thousands of dollars) 1999 1998 - ----------------------------------------------------------------------------------------------------- Common stockholders' investment (notes 5, 7, and 11): Common stock, $1 Par Authorized - 20,000 shares Outstanding - 6,102 shares in 1999 and 5,969 shares in 1998 $ 6,102 $ 5,969 Amount paid in excess of par 61,966 59,198 Retained earnings 25,000 23,067 ---------- ---------- 93,068 88,234 Accumulated other comprehensive earnings: Unrealized gain on financial instruments (notes 12 and 17) 39 43 ---------- ---------- Total common equity 93,107 88,277 ---------- ---------- Cumulative preferred stock of subsidiary (notes 5 and 9): Redeemable 8.7% Series, $100 Par Authorized - 80 shares Outstanding - 32 shares as of 1999 and 48 shares as of 1998 3,200 4,800 ---------- ---------- Long-term debt (notes 5, 8, and 9): First Mortgage Bonds, secured by property Series M, 10.25%, due July 31, 2008 1,819 2,728 Series N, 9.63%, due May 30, 2020 10,000 10,000 Series O, 8.46%, due September 30, 2022 12,500 12,500 Series P, 8.09%, due September 30, 2022 12,500 12,500 Series Q, 5.62%, due November 30, 2003 8,000 9,600 Series R, 7.50%, due December 15, 2025 15,000 15,000 Series S, 6.82%, due April 1, 2018 15,000 15,000 Series T, 6.50%, due February 1, 2029 15,000 - Other long-term debt 4,461 4,890 Capital leases 556 1,170 ---------- ---------- 94,836 83,388 Less-current portion 3,515 3,233 ---------- ---------- Long-term debt, net 91,321 80,155 ---------- ---------- Total capitalization $ 187,628 $ 173,232 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. Page 13 Consolidated Statements of Changes in Common Stockholders' Equity For the Three Years Ended September 30
Shares Amount Paid Other Issued and Outstanding In Excess Retained Comprehensive (thousands of dollars) Number Amount of Par Earnings Income (Loss) - -------------------------------------------------------------------------------------------------------------- Balance, September 30, 1996 5,748 $ 5,748 $55,404 $21,413 $ - Add (deduct): Net income - - - 7,831 - Dividends ($1.08 per share) - - - (6,242) - Dividend reinvestment, cash stock purchase plan, and employee benefit plans 82 82 1,392 - - Exercise of stock options 2 2 32 - - Accrual for stock compensation plan - - (110) - - Amortization of deferred compensation for stock compensation plans - - 109 - - ---------- ------------ ------------ ---------- -------------- Balance, September 30, 1997 5,832 5,832 56,827 23,002 - Add (deduct): Net income - - - 6,442 - Dividends ($1.08 per share) - - - (6,377) - Dividend reinvestment, cash stock purchase plan, and employee benefit plans 76 76 1,410 - - Exercise of stock options 7 7 108 - - Accrual for stock compensation plan - - (266) - - Amortization of deferred compensation for stock compensation plans - - 163 - - Unrealized gain on financial instruments - - - - 43 Shares issued for acquisition 54 54 956 - - ---------- ------------ ------------ ---------- -------------- Balance, September 30, 1998 5,969 5,969 59,198 23,067 43 Add (deduct): Net income - - - 8,425 - Dividends ($1.08 per share) - - - (6,492) - Dividend reinvestment, cash stock purchase plan, and employee benefit plans 63 63 1,170 - - Exercise of stock options 1 1 13 - - Accrual for stock compensation plan - - (98) - - Amortization of deferred compensation for stock compensation plans - - 181 - - Unrealized (loss) on financial instruments - - - - (4) Shares issued for acquisition 68 68 1,480 - - Shares issued for employee stock purchase plan 1 1 22 - - ---------- ------------ ------------ ---------- -------------- Balance, September 30, 1999 6,102 $ 6,102 $61,966 $25,000 $ 39 ========== ============ ============ ========== ==============
The accompanying notes are an integral part of these consolidated financial statements. Page 14 Notes to Consolidated Financial Statements 1. Significant Accounting Policies Consolidation The consolidated financial statements include the accounts of Providence Energy Corporation and its wholly-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. The Company will account for its investment in the Capital Center Energy Company, LLC joint venture under the equity method of accounting at the conclusion of the construction period (also see Note 14). Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulation ProvGas is subject to regulation by the RIPUC. North Attleboro Gas is subject to regulation by the MDTE. The accounting policies of ProvGas and North Attleboro Gas conform to GAAP as applied in the case of regulated public utilities and are in accordance with the regulators' accounting requirements and rate-making practices. Energy Revenues Energy revenues are generated principally from natural gas and oil activities. The natural gas distribution companies record accrued natural gas distribution revenues based on estimates of gas volumes delivered but not billed at the end of an accounting period in order to match revenues with related costs. Also included in energy revenues are revenues earned from energy management services, including energy project development fees. Hedging The Company's non-regulated operation uses financial instruments to manage market risks and to reduce exposure to fluctuations in the market prices of home heating oil, diesel, heavy oil, and natural gas. The Company's policy is not to hold or issue financial instruments for trading purposes but to utilize such instruments to hedge the impact of market price fluctuations. These financial instruments qualify for hedge accounting. Hedge accounting is used in non-trading activities when there is a high degree of correlation between price movements in the instrument and the item designated as being hedged. Under hedge accounting, financial instruments with third parties are carried at market value with related unrealized gains and losses recorded as adjustments to equity in the Consolidated Statements of Capitalization. Realized gains and losses are recognized in the Consolidated Statements of Income when the hedge transaction occurs. Lease Accounting Previously, the Company leased water heaters and other appliances to customers under finance leases. These leases are recorded on the accompanying Consolidated Balance Sheets at the gross investment in the leases less unearned income. Unearned income is recognized in such a manner as to produce a constant periodic rate of return on the net investment in the finance leases. Gas Plant Gas plant is stated at the original cost of construction. In accordance with the uniform system of accounts prescribed by the RIPUC, the difference between the original cost of gas plant acquired and the cost to ProvGas is recorded as a Plant Acquisition Adjustment and is being amortized over periods ranging from 1 to 24 years. The Company also capitalizes the costs of all technology investments with the exception of system maintenance costs, which are expensed unless deferral is approved by regulators. Impairment Of Long-lived Assets SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" established accounting standards for the impairment of long-lived assets. SFAS No. 121 also required that regulatory assets which are no longer probable of recovery through future revenues be charged to earnings. SFAS No. 121 has not impacted the Company's financial position or results of operations for the years presented. Page 15 Depreciation For ProvGas and North Attleboro Gas, depreciation is provided on the straight-line basis at rates approved by the RIPUC and the MDTE which are designed to amortize the cost of depreciable plant over its estimated useful life. The composite depreciation rate expressed as a percentage of the average depreciable gas plant in service was approximately 3.85 percent for 1999, 1998, and 1997. For the non-regulated operation, depreciation is provided on the straight- line basis at rates which are designed to amortize asset costs over their useful lives. The Company retires property units for its regulated operation by charging original cost, cost of removal, including environmental investigation and remediation costs, and salvage value to accumulated depreciation. Due to the magnitude of environmental investigation and remediation costs, these amounts have been separately stated in the accompanying Consolidated Balance Sheets. Gains and losses on the disposition of assets for the non-regulated operation are reported in earnings in the period realized. Gas Charge Clauses In May 1996, the RIPUC approved a Rate Design Settlement Agreement. The Agreement included changes to ProvGas' gas cost recovery mechanism. Specifically, the Agreement replaced the previous CGA with the GCC effective June 2, 1996. In addition to the commodity and related pipeline transportation costs historically included in the CGA, the GCC provided for the recovery of: (1) inventory financing costs; (2) working capital associated with gas supply purchases; (3) bad debt expenses associated with the gas revenue portion of customer bills; and (4) a substantial portion of liquefied natural gas operating and maintenance expenses, all of which were previously recovered in base rates. Similar to the former CGA, the GCC provided for reconciliation of total gas costs billed with the actual cost of gas incurred. Any excess or deficiency in amounts billed as compared to costs incurred was deferred and either refunded to, or recovered from, customers over a subsequent period. As a result of the Price Stabilization Plan Settlement Agreement described in Note 10, the GCC has been suspended for the period from October 1, 1997 through September 30, 2000. Any excess or deficiency in amounts billed as compared to costs incurred will be retained or borne by ProvGas during this period. Allowance For Funds Used During Construction ProvGas and North Attleboro capitalize interest and an allowance for equity funds in accordance with established policies of the RIPUC and MDTE. The rates used are based on the actual cost of debt and the allowed equity return. Interest capitalized is shown as a reduction of interest expense and the equity allowance is included in other income (loss) in the accompanying Consolidated Statements of Income. Deferred Charges and Other Assets The Company defers and amortizes certain costs in a manner consistent with authorized or probable rate-making treatment. Deferred financing costs are amortized over the life of the related security while the remaining deferred regulatory charges and other assets are amortized over a recovery period specified by the respective regulatory commissions. Deferred Charges and Other Assets include the following: (thousands of dollars) 1999 1998 - ------------------------------------------------ Year 2000 costs $ 7,315 $ 2,518 Pension costs 7,177 6,401 Goodwill, net 4,624 2,839 Unamortized debt expense 3,888 3,204 Exogenous recovery (note 10) 2,450 - Other deferred charges 3,277 4,035 ------- ------- Total $28,731 $18,997 ======= ======= Temporary Cash Investments Temporary cash investments are short-term, highly liquid investments with original maturities to the Company of not more than 90 days. Stock-based Compensation Compensation expense associated with awards of stock or options to employees is measured using the intrinsic value method of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (see Note 11). Page 16 Intangibles All intangible assets are amortized on a straight-line basis over their estimated useful lives. The goodwill and customer list amortization periods associated with the recent oil acquisitions are 20 years and 10 years, respectively. Reclassifications Certain prior year amounts have been reclassified for consistent presentation with the current year. 2. Subsequent Event - Merger On November 15, 1999, the Company and Southern Union announced that their Boards of Directors unanimously approved a definitive merger agreement. ProvEnergy will serve as Southern Union's headquarters for its New England operations. The agreement calls for Southern Union to merge with the Company in a transaction valued at approximately $400 million, including assumption of debt. Under the terms of the agreement, the Company's shareholders will receive $42.50 per share of Company stock in cash. Upon completion of the merger, Southern Union will serve approximately 1.5 million gas, electric, oil, and propane customers in Rhode Island, Massachusetts, Pennsylvania, Texas, Missouri, Florida, Connecticut, and Mexico. The Company will operate as an autonomous division of Southern Union with the headquarters remaining in Rhode Island, and pursuant to terms of the merger agreement, there will be no material changes in the immediate future to the operations of the Company. Southern Union will honor all of the Company's union contracts and no layoffs are anticipated as a result of the transaction. The Company's Chairman and Chief Executive Officer, James H. Dodge, will also become a member of Southern Union's Board of Directors. The transaction may require certain legal approvals, including the approval of the holders of a majority of the outstanding Company shares, the Division, the RIPUC, the MDTE, the SEC, and FERC, as well as regulators in Texas, Missouri, Pennsylvania, and Florida, where Southern Union currently has operations. 3. Federal Income Taxes The Company records income taxes in accordance with the Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes", which requires deferred taxes to be provided for all temporary differences. The following is a summary of the provision for Federal income taxes for the three years ended September 30: (thousands of dollars) 1999 1998 1997 - -------------------------------------------------------------------- Current $3,652 $2,526 $3,688 Deferred 888 1,131 703 ------ ------ ------ Total Federal income tax provision $4,540 $3,657 $4,391 ====== ====== ====== The effective Federal income tax rates and the reasons for their differences from the statutory Federal income tax rates are as follows: 1999 1998 1997 - -------------------------------------------------------------------- Statutory Federal income tax rates 34.0% 34.0% 34.0% Reversing temporary differences (.8) (.1) (.3) Amortization of investment tax credits (.4) (.5) (.4) Non-deductible goodwill .6 .3 - Other .7 .8 .9 ------ ------ ------ Effective Federal income tax rates 34.1% 34.5% 34.2% ====== ====== ====== The Company's deferred tax assets and liabilities for each of the two years in the period ended September 30 are the result of the following temporary differences: Page 17 (thousands of dollars) 1999 1998 - -------------------------------------------------------------------- Long-term deferred taxes - ------------------------ Tax assets Unamortized ITC $ 719 $ 773 Other 222 413 Tax liabilities Property related (22,575) (22,730) Pension costs (125) (237) Deferred charges (2,392) (511) -------- -------- Net deferred tax liability included in accompanying Consolidated Balance Sheets $(24,151) $(22,292) ======== ======== Prepaid taxes - ------------- Tax assets Accounts receivable reserves $ 1,288 $ 970 Property tax reserves 61 (136) Other 1,358 927 Tax liabilities Employee severance 56 56 Other (139) (109) -------- -------- Net prepaid taxes 2,624 1,708 Prepaid gross earnings tax and other 1,591 3,647 -------- -------- Net prepaid and refundable taxes included in accompanying Consolidated Balance Sheets $ 4,215 $ 5,355 ======== ======== Investment tax credits are amortized through credits to other income (loss), over the estimated lives of related property. 4. Lease Receivables Previously, the Company financed the installation of water heaters and other appliances for its customers under one to three-year finance agreements. Additionally, the Company leased water heaters and appliances to customers under 10-year sales-type leases. Future minimum lease payments to be received are: (thousands of dollars) - ------------------------------------------------- 2000 $ 389 2001 295 ------- 684 Amount representing interest (99) ------- Amount representing principal $ 585 ======= 5. Capitalization A. First Mortgage Bonds In April 1998, ProvGas issued $15 million of Series S First Mortgage Bonds. These First Mortgage Bonds bear interest at the rate of 6.82 percent and mature in April 2018. The net proceeds provided by this indebtedness were used to finance capital expenditures and pay down short-term debt. In September 1998, ProvGas repurchased $6.4 million of Series M First Mortgage Bonds. The cost of repurchase was comprised of $6.4 million in principal and $1.4 million in premium. The premium will be amortized over 30 years, which is the life of the Series T First Mortgage Bonds, which ProvGas issued in February 1999. ProvGas has received an order from the Division which permits the amortization of the bond premium over the life of this new debt. ProvGas issued $15 million in Series T First Mortgage Bonds on February 8, 1999. These First Mortgage Bonds bear interest at the rate of 6.5 percent and mature in February 2029. The proceeds were used to reduce borrowings under lines of credit as well as for general corporate purposes. ProvGas' First Mortgage Bonds are secured by a lien on substantially all of the tangible and real property. Page 18 As of September 30, 1999, the annual sinking fund requirements and maturities of long-term debt are as follows: (thousands of dollars) - ------------------------ 2000 $ 2,509 2001 2,509 2002 1,601 2003 1,600 2004 and thereafter 81,600 -------- $ 89,819 ======== The Company's ability to pay dividends is largely dependent on the continuing operations of ProvGas. Approximately $20 million of ProvGas' retained earnings is available for dividends under the most restrictive terms of ProvGas' First Mortgage Bond Indenture. B. Other Long-term Debt During 1997, the Company financed equipment purchases of approximately $3,328,000 through the issuance of long-term notes to IBM Credit Corporation. The notes have five-year terms and interest rates ranging from 4.9 to 7.5 percent. As of September 30, 1999, the maturities of these long-term notes over the next five years are $663,000 in 2000, $704,000 in 2001, $480,000 in 2002, $69,000 in 2003, and $78,000 in 2004 and thereafter. The remainder of the other long-term debt consists primarily of an amount due to a former owner of an acquired company. C. Redeemable Preferred Stock ProvGas' preferred stock, which consists of 80,000 shares of $100 par value, has an 8.7 percent cumulative annual dividend rate payable on a quarterly basis, and has no voting power or privileges. The stock is subject to a cumulative annual sinking fund requirement of 16,000 shares per year at par ($1,600,000) plus accrued or unpaid dividends which commenced in February 1997. Accordingly, 16,000 shares were redeemed by ProvGas at par value in February 1999 and 1998. Under the agreement, in addition to the sinking fund redemptions required, the Company has the option to redeem the final 16,000 shares of preferred stock on March 1, 2000. 6. Notes Payable The Company meets seasonal cash requirements and finances capital expenditures on an interim basis through short-term bank borrowings. As of September 30, 1999, the Company had lines of credit totaling $74,000,000 with borrowings outstanding of $38,250,000. The Company pays a fee for its lines of credit rather than maintaining compensating balances. The weighted average short-term interest rate for borrowings outstanding at the end of the year was 5.52 percent in 1999, 5.86 percent in 1998, and 5.79 percent in 1997. 7. Employee Benefits A. Retirement Plans The Company has two pension plans providing retirement benefits for most of its employees. The benefits under the plans are based on years of service and the employee's final average compensation. It is the Company's policy to fund at least the minimum required contribution. The following table sets forth the funding status of the pension plans and amounts recognized in the Company's Consolidated Balance Sheets at September 30, 1999 and 1998: (thousands of dollars) 1999 1998 - ----------------------------------------------------------------------- Accumulated benefit obligation, including vested benefit obligation of $(47,881) as of September 30, 1999 and $(46,175) as of September 30, 1998 $ (57,017) $ (54,986) ========= ======== Projected benefit obligation for service rendered to date $ (72,366) $ (71,540) Plan assets at fair value (primarily listed stocks, corporate bonds, and U.S. bonds) 83,137 74,862 --------- ---------- Page 19 Excess of plan assets over projected benefit obligation 10,771 3,322 Unrecognized (gain) (19,749) (9,872) Unrecognized prior service cost 4,056 2,559 Unrecognized net transition asset being recognized over 15 years from October 1, 1985 (136) (272) ------- -------- Net accrued pension cost included in accrued pension and accounts payable at September 30, 1999 and 1998 $(5,058) $ (4,263) ======= ======== Net pension cost for fiscal years 1999, 1998, and 1997 included the following components: (thousands of dollars) 1999 1998 1997 - -------------------------------------------------------------------------------- Service cost $ 2,285 $ 1,989 $ 1,824 Interest cost on benefit obligations 4,993 4,904 4,583 Actual return on plan assets (11,605) (1,338) (16,458) Net amortization and deferral 5,123 (6,515) 10,526 -------- ------- -------- Net periodic pension cost 796 (960) 475 Adjustments due to regulatory action (796) 960 (475) -------- ------- -------- Net periodic pension cost recognized in earnings $ - $ - $ - ======== ======= ======== In 1999, the discount rate and rate of increase in future compensation levels used in determining the projected benefit obligation were 7.25 percent and 5 percent, respectively. The expected long-term rate of return on assets was 9 percent in 1999. In 1998, the discount rate and rate of increase in future compensation levels used in determining the projected benefit obligation were 6.75 percent and 5 percent, respectively. In 1997, the discount rate and rate of increase in future compensation levels used in determining the projected benefit obligation were 8 percent and 6 percent, respectively. The expected long-term rate of return on assets was 9 percent in 1998 and 1997. ProvGas recovers pension costs in rates when such costs are funded. Therefore, the amount by which funding differs from pension expense, determined in accordance with GAAP, is deferred and recorded as a regulatory asset or liability. B. Post-retirement Benefits Other Than Pensions ProvGas currently offers retirees who have attained age 55 and worked five years for ProvGas, healthcare and life insurance benefits during retirement. These benefits are similar to the benefits offered to active employees. Although retirees are not required to make contributions for healthcare and life insurance benefits currently, future contributions may be required if the cost of healthcare and life insurance benefits during retirement exceed certain limits. Since 1993, post-retirement benefit costs for active employees are recorded by ProvGas on an accrual basis, ratably over their service periods. Benefits of $10,526,000 earned prior to 1993 have been deferred as an unrecognized transition obligation, which ProvGas is amortizing over a 20-year period. ProvGas funds its post-retirement benefit obligation by contributions to a VEBA Trust. Total contributions of $1,177,000 in 1999, $1,308,000 in 1998, and $1,372,000 in 1997 were made to the VEBA Trust. ProvGas recovers its post-retirement benefit obligation in rates to the extent allowed by the RIPUC. The RIPUC generally allows such costs to be recovered if amounts are funded into tax-favored investment funds, such as the VEBA Trust. Accordingly, ProvGas fully recovered its 1999, 1998, and 1997 post- retirement obligations because such obligations were funded through the VEBA Trust. In addition, in September 1996, the RIPUC approved a ratable recovery of the cumulative unrecovered difference of $1,041,000 during 1997, 1998, and 1999. Of the total post-retirement benefit obligations, $1,523,000, $1,654,000, and $1,718,000, were included in rates during 1999, 1998, and 1997, respectively. The healthcare and life insurance benefits' costs and accumulated post- retirement benefit obligation for 1999, 1998, and 1997 are calculated by ProvGas' actuaries using assumptions and estimates which include: Page 20 1999 1998 1997 - --------------------------------------------------------------------- Healthcare cost annual growth rate 7.55% 9.0% 10.2% Healthcare cost annual growth rate - long-term 4.75 6.0 6.0 Expected long-term rate of return (union) 8.5 8.5 8.5 Expected long-term rate of return (non-union) 5.5 5.5 5.5 Discount rate 7.25 6.75 8.0 The healthcare cost annual growth rate significantly impacts the estimated benefit obligation and annual expense. For example, in 1999, a one percent increase in the above rates would increase the obligation by $745,000 and the annual expense by $77,000. Decreasing the assumed health care cost annual growth rate by one percent would decrease the obligation by $596,000 and the annual expense by $62,000. The obligations and assets for the healthcare and life insurance benefits at September 30, 1999 and 1998 are as follows: (thousands of dollars) 1999 1998 - ------------------------------------------------------------- Accumulated post-retirement benefit obligation as of the end of the prior fiscal year $(12,886) $(11,748) Service cost (273) (243) Interest cost (848) (945) Actuarial loss/(gain) and assumption change 872 (660) Expected benefits paid 724 710 -------- -------- Accumulated post-retirement benefit obligation as of the end of the fiscal year (12,411) (12,886) -------- -------- Fair value of plan assets as of the beginning of the year 5,684 4,704 Return on plan assets 627 377 Employer contributions 1,177 1,308 Expenses paid (13) (18) Benefits paid (590) (687) -------- -------- Fair value of plan assets as of the end of the year 6,885 5,684 -------- -------- Unfunded post-retirement benefit obligation (5,526) (7,202) Unrecognized transition obligation 7,368 7,895 Unrecognized net (gain) or loss (1,842) (693) -------- -------- Prepaid post-retirement benefit obligation included in the accompanying Consolidated Balance Sheets $ - $ - ======== ======== ProvGas' actuarially determined healthcare and life insurance benefits' costs for 1999, 1998, and 1997 include the following: (thousands of dollars) 1999 1998 1997 - ----------------------------------------------------------- Service cost $ 273 $ 243 $ 228 Interest cost 849 945 896 Actual return on plan assets (471) (406) (278) Amortization and deferral 526 526 526 ------ ------ ------ Total annual plan costs $1,177 $1,308 $1,372 ====== ====== ====== C. Supplemental Retirement Plans The Company provides certain supplemental retirement plans for key employees. The projected benefit obligation is approximately $2,111,000 which is being accrued over the service period of these key employees. The supplemental retirement plans are unfunded. ProvGas accrued and expensed $407,000, $61,000, and $612,000, related to these benefits in 1999, 1998, and 1997, respectively. Page 21 D. Performance and Equity Incentive Plan The Providence Energy Corporation Performance and Equity Incentive Plan provides that up to 225,000 shares of common stock, as well as cash awards, can be granted to key employees, including employees of ProvGas, at no cost to the employees. Key employees who receive common shares are entitled to receive dividends, but full beneficial ownership vests on the fifth anniversary of the date of the grant provided the participant is still employed by the Company. Vesting may be accelerated under certain circumstances, including a change in control. This plan also provides for cash compensation to key employees. The executive compensation incentive awards totaled approximately $715,000 for 1999, $459,000 for 1998, and $439,000 for 1997. Amounts paid in cash are charged to expense when earned. However, amounts paid in restricted stock are deferred and amortized to expense over the five-year vesting period. Of the $715,000 1999 award, $483,000 will be paid in cash during 2000. Of the $459,000 1998 award, $310,000 was paid in cash during 1999. Of the $439,000 1997 award, $297,000 was paid in cash during 1998. Grant shares totaling 7,566, 7,230, and 5,989, were purchased by the Company and reissued to key employees during 1999, 1998, and 1997, respectively. E. Restricted Stock Incentive Plan The Restricted Stock Incentive Plan, which was discontinued in 1998, provided that up to 60,000 shares of common stock may be granted to employees of the Company with at least three months of service, who were not officers or covered by a collective bargaining agreement, at no cost to the employee. All participants were entitled to receive dividends; however, full beneficial ownership vests on the third anniversary of the date of the grant provided that the participant is still employed by the Company. Vesting may be accelerated under certain circumstances. The purchase of 4,230 shares for the Restricted Stock Incentive Plan for the 1997 award occurred in 1998 at a cost of approximately $90,000. All amounts awarded under the Restricted Stock Incentive Plan are deferred and amortized to expense over a three-year period. F. 1998 Performance Share Plan Effective October 1, 1998, the Board of Directors adopted a Performance Share Plan to encourage executives' interest in longer-term performance by keying incentive payouts to the total return performance of the Company's common stock in relation to that of other companies in the Edward Jones & Company gas distribution group of approximately 30 companies and to the change in the Company's stock price over three-year performance periods. The number of shares earned will range from 50 percent to 150 percent of awarded shares, if based on the relative total shareholder return method, and 50 percent to 100 percent, if based on the increase in the Company's stock price during the three-year period. These levels were developed to bring total compensation levels at the Company more in line with survey data for the relevant labor market. No shares will be earned unless shareholders have earned a minimum annual return over the three- year period equal to the total annual return for 30-year Treasury notes during such period. Upon the occurrence of a change in control, unless otherwise prohibited, the opportunities under all outstanding awards shall be deemed to have been fully earned for the entire performance period as of the effective date of the change in control. Dividends will not be paid on the shares until they are earned. Awards will be paid half in cash and half in stock. During 1999, 38,000 shares were granted under this plan. 8. Commitments and Contingencies A. Legal Proceedings The Company is involved in legal and administrative proceedings in the normal course of business, including certain proceedings involving material amounts in which claims have been or may be made. However, management believes, after review of insurance coverage and consultation with legal counsel, that the ultimate resolution of the legal proceedings to which it is or can at the present time be reasonably expected to be a party, will not have a materially adverse effect on the Company's results of operations or financial condition. B. Capital Leases ProvGas has a capital lease with Algonquin for storage space in a LNG tank. The capital lease arrangement also provides that Algonquin lease from ProvGas, for a corresponding term at an annual amount of $150,000, the land on which the tank is situated. ProvGas also leases certain information systems and other equipment under capital leases. Page 22 Property under Capital Leases: - -----------------------------
(thousands of dollars) 1999 1998 - ------------------------------------------------------------ Gas Plant $ 6,116 $ 6,116 Computer and other equipment 568 1,988 Accumulated depreciation (6,067) (6,937) ------- ------- $ 617 $ 1,167 ======= =======
Commitments for Capital Leases are: - -----------------------------------
*LNG Computer (thousands of dollars) Storage Equipment Total - -------------------------------------------------------------------- 2000 $ 136 $ 144 $ 280 2001 136 144 280 2002 - 69 69 2003 - 34 34 2004 - 2 2 ------- ------- ------- $ 272 $ 393 $ 665 ------- ------- ------- Amount representing interest (109) ------- Amount representing principal $ 556 =======
* This capital lease will be terminated once the terms of the contract with Algonquin, which is described below, are met. C. Operating Leases The Company also leases facilities and equipment under operating leases with total future payments as of September 30, 1999 as follows: (thousands of dollars) - ---------------------- 2000 $ 205 2001 145 2002 61 ----- $ 411 ===== D. Gas Supply As part of the Price Stabilization Plan Settlement Agreement described in Note 10, ProvGas entered into a full requirements gas supply contract with DETM, a joint venture of Duke Energy Corporation and Mobil Corporation, for a term of three years commencing October 1, 1997. Under the contract, DETM guarantees to meet ProvGas' supply requirements; however, ProvGas must purchase all of its gas supply exclusively from DETM. In addition, under the contract, ProvGas transferred responsibility for its pipeline capacity resources, storage contracts, and LNG capacity to DETM. As a result, ProvGas' gas inventories of approximately $18 million at September 30, 1997 were sold at book value to DETM on October 1, 1997. In addition to providing supply for firm customers at a fixed price, DETM will provide gas at market prices to cover ProvGas' non-firm sales customers' needs and to make up the supply imbalances of transportation customers. DETM will also provide various other services to ProvGas' transportation service customers including enhanced balancing, standby, and the storage and peaking services available under ProvGas' approved FT-2 storage service effective December 1, 1997. DETM will receive the supply-related revenues from these services in exchange for providing the supply management inherent in these services. Included in the DETM contract are a number of other important features. ProvGas has retained the right to continue to make gas supply portfolio changes to reduce supply costs. To the extent ProvGas makes such changes, ProvGas must keep DETM whole for the value lost over the remainder of the contract period. The outsourcing of day-to-day supply management relieves ProvGas of the need to perform certain upstream supply management functions. This will make it possible for ProvGas to take on the additional supply management workload required by the further unbundling of firm sales customers without major staffing additions. ProvGas has entered into an agreement replacing its existing service contract with Algonquin, a subsidiary of Duke Energy Corporation. Algonquin is the owner and operator of a LNG tank located in Providence, Rhode Island. ProvGas relies upon this service to provide gas supply into its distribution system during the winter period. The service provided for in the agreement, subject to the successful completion of Page 23 construction, is expected to begin in the first quarter of fiscal 2000. Under the terms of the agreement, Algonquin replaced and expanded the vaporization capability at the tank. ProvGas will receive approximately $2.6 million from Algonquin. Of the $2.6 million, approximately $.9 million represents reimbursement received by ProvGas in 1999 for costs incurred related to the project including labor, engineering, and legal expenses. The remaining portion of the payment, or approximately $1.7 million, will be paid to DETM under ProvGas' contract with DETM as reimbursement for the additional costs that DETM will incur when the Algonquin storage capacity is released to DETM as provided for in the gas supply contract described above. This payment is expected 60 days after the in-service date of the project. In June 1999, the FERC issued an order in Docket Number CP99-113 approving Algonquin's project described above. In that order FERC also approved the new 10-year contract between Algonquin and ProvGas for service from the tank. Also approved was ProvGas' parallel filing, PR99-8, requesting regulatory authorization to charge Algonquin for transportation of gas vaporized for other Algonquin customers and transported by ProvGas to the Algonquin pipeline on behalf of those customers. As a result of FERC Order 636 and other related orders, pipeline transportation companies have incurred significant costs, collectively known as transition costs. The majority of these costs will be reimbursed by the pipeline's customers, including ProvGas. ProvGas estimates its transition costs to be approximately $21.7 million, of which $16.2 million has been included in the GCC and collected from customers through September 30, 1997. As part of the above supply contract, DETM assumed liability for these transition costs during the contract's three-year term. At the end of the three-year term of the contract, the Company will assume any remaining liability, which is not expected to be material. E. Environmental Matters Federal, state, and local laws and regulations establishing standards and requirements for the protection of the environment have increased in number and in scope within recent years. The Company cannot predict the future impact of such standards and requirements, which are subject to change and can take effect retroactively. The Company continues to monitor the status of these laws and regulations. Such monitoring involves the review of past activities and current operations, and may include expending funds to investigate or clean up certain sites. To the best of its knowledge, subject to the following, the Company believes it is in substantial compliance with such laws and regulations. At September 30, 1999, the Company was aware of five sites at which future costs may be incurred. Plympton Sites (2) - ------------------ The Company has been designated as a PRP under the Comprehensive Environmental Response Compensation and Liability Act of 1980 at two sites in Plympton, Massachusetts on which waste material is alleged to have been deposited by disposal contractors employed in the past either directly or indirectly by the Company and other PRPs. With respect to one of the Plympton sites, the Company has joined with other PRPs in entering into an Administrative Consent Order with the Massachusetts Department of Environmental Protection. The costs to be borne by the Company, in connection with both Plympton sites, are not anticipated to be material to the financial condition of the Company. Providence Site - --------------- During 1995, the Company began a study at its primary gas distribution facility located in Providence, Rhode Island. This site formerly contained a manufactured gas plant operated by the Company. As of September 30, 1999, approximately $3.0 million had been spent primarily on studies and the formulation of remediation work plans at this site. In accordance with state laws, such a study is monitored by the DEM. The purpose of this study was to determine the extent of environmental contamination at the site. The Company has completed the study which indicated that remediation will be required for two- thirds of the property. The remediation began in June 1999 and is anticipated to be completed during the next fiscal year. During this remediation period, the remaining one-third of the property will also be investigated and remediated if necessary. The Company has compiled a preliminary range of costs, based on removal and off-site disposal of contaminated soil, ranging from $7.0 million to in excess of $9.0 million. However, because of the uncertainties associated with environmental assessment and remediation activities, the future cost of remediation could be higher than the range noted. Based on the proposals for remediation work, the Company has a net accrual of $6.1 million at September 30, 1999 for anticipated future remediation costs at this site. Page 24 Westerly Site - ------------- Tests conducted following the discovery of an abandoned underground oil storage tank at the Company's Westerly, Rhode Island operations center in 1996 confirmed the existence of coal tar waste at this site. As a result, the Company completed a site characterization test. Based on the findings of that test, the Company concluded that remediation would be required. As of September 30, 1999, the Company had removed an underground oil storage tank and regulators containing mercury disposed of on the site, as well as some localized contamination. The costs associated with the site characterization test and partial removal of soil contaminants were shared equally with the former owner of the property. The Company is currently engaged in negotiations to transfer the property back to the previous owner, who would continue to remediate the site. The purchase and sale agreement is anticipated to be signed during fiscal 2000, at which time the previous owner will assume responsibility for removal of coal tar waste on the site. The Company remains responsible for cleanup of any mercury released into adjacent water. Contamination from scrapped meters and regulators, which was discovered in 1997, was reported to the DEM and the Rhode Island Department of Health and the Company has completed the necessary remediation. Costs incurred by the Company to remediate this site were approximately $.1 million. Allens Avenue Site - ------------------ In November 1998, the Company received a letter of responsibility from DEM relating to possible contamination on previously-owned property on Allens Avenue in Providence. The current operator of the property has been similarly notified. Both parties have been designated as PRPs. A work plan has been created and approved by DEM. An investigation has begun in order to determine the extent of the problem and the Company's responsibility. The Company has entered into a cost sharing agreement with the current operator of the property, under which the Company will be held responsible for approximately 20 percent of the costs related to the investigation. Total estimated costs of testing at this site are anticipated to be approximately $.2 million. Until the results of the investigation are known, the Company cannot offer any conclusions as to its responsibility. General - ------- In prior rate cases filed with the RIPUC, ProvGas requested that environmental investigation and remediation costs be recovered by inclusion in its depreciation factors consistent with the rate recovery treatment for all types of cost of removal. Due to the magnitude of ProvGas' environmental investigation and remediation expenditures, ProvGas sought current recovery for these amounts. As a result, in accordance with the Price Stabilization Plan Settlement Agreement described in Note 10, effective October 1, 1997, all environmental investigation and remediation costs incurred through September 30, 1997, as well as all costs incurred during the three-year term of the Plan, will be amortized over a 10-year period, in accordance with the levels authorized in Energize RI. Additionally, it is ProvGas' practice to consult with the RIPUC on a periodic basis when, in management's opinion, significant amounts might be expended for environmental-related costs. As of September 30, 1999, ProvGas has incurred environmental assessment and remediation costs of $4.7 million and has a net accrual of $6.1 million for future costs. Management has begun discussions with other parties who may assist ProvGas in paying the costs associated with the remediation of the above sites. Management believes that its program for managing environmental issues, combined with rate recovery and financial contributions from others, will likely avoid any material adverse effect on its results of operations or its financial condition as a result of the ultimate resolution of the above sites. F. Purchase Commitments At September 30, 1999 and 1998, the non-regulated operation had forward purchase commitments for its supply needs with market values of approximately $13.8 million and $15.2 million, respectively. These contracts were acquired at costs of approximately $12.2 million and $15.6 million, respectively, and have maturities of less than one year. All financial instruments held by the Company currently qualify as hedges due to either anticipated sales contracts or firm sales commitments. 9. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value disclosures for the following financial instruments: Page 25 Cash, Cash Equivalents, Accounts Payable, and Short-term Debt - ------------------------------------------------------------- The carrying amount approximates fair value due to the short-term maturity of these instruments. Financial Instruments for Hedging - --------------------------------- The fair value of financial instruments for hedging are the same as the carrying amount on the balance sheet as these instruments were marked to market at September 30, 1999 and 1998. Long-term Debt and Preferred Stock - ---------------------------------- The fair value of long-term debt and preferred stock is estimated based on currently quoted market prices for similar types of issues. The carrying amounts and estimated fair values of the Company's financial instruments at September 30 are as follows:
1999 1998 -------------------- ------------------ Carrying Fair Carrying Fair (thousands of dollars) Amount Value Amount Value - ----------------------------------------------------- ------------------ Cash and cash equivalents $ 2,804 $ 2,804 $ 2,006 $ 2,006 Financial instruments for hedging 114 114 169 169 Accounts payable 12,199 12,199 9,310 9,310 Short-term debt 38,250 38,250 20,079 20,079 Long-term debt 94,836 90,099 83,388 96,024 Preferred stock 3,200 3,223 4,800 5,040
The difference between the carrying amount and the fair value of ProvGas' preferred stock and 1998 long-term debt, if they were settled at amounts reflected above, would likely be recovered in ProvGas' rates over a prescribed amortization period. Accordingly, any settlement should not result in a material impact on ProvGas' financial position or results of operations. 10. Rate Changes A. Price Stabilization Plan Settlement Agreement In August 1997, the RIPUC approved Energize RI among ProvGas, the Division, the Energy Council of Rhode Island, and the George Wiley Center. Effective October 1, 1997 through September 30, 2000, Energize RI provides firm customers with a price decrease of approximately 4.0 percent in addition to a three-year price freeze. Under Energize RI, the GCC mechanism has been suspended for the entire term. Also, in connection with the Plan, ProvGas wrote off approximately $1.5 million of previously deferred gas costs in October 1997. Energize RI also provides for ProvGas to make significant capital investments to improve its distribution system and support economic development. Specific capital improvement projects funded under Energize RI are estimated to total approximately $26 million over its three-year term. In addition, under Energize RI, ProvGas provides funding for the Low-Income Assistance Program at an annual level of $1.0 million, the Demand Side Management Rebate Program at an annual level of $.5 million and the Low-Income Weatherization Program at an annual level of $.2 million. Energize RI also continues the process of unbundling by allowing ProvGas to provide unbundled service offerings for up to 10 percent per year of firm deliveries. As part of Energize RI, ProvGas has reclassified and is amortizing approximately $4.0 million of prior environmental costs. These costs and all environmental costs incurred during the term of the Plan will be amortized over a 10-year period, in accordance with the levels authorized Energize RI. Under Energize RI, ProvGas may earn up to 10.9 percent, but not less than 7.0 percent, annually on its average common equity, which is capped at $81.0 million, $86.2 million, and $92.0 million in fiscal 1998, 1999, and 2000, respectively. In the event that ProvGas earns in excess of 10.9 percent or less than 7.0 percent, ProvGas will defer revenues or costs through a deferred revenue account over the term of the Plan. Any balance in the deferred revenue account at the end of the Plan will be refunded to or recovered from customers in a manner to be determined by all parties to the Plan and approved by the RIPUC. Page 26 As part of Energize RI, ProvGas is permitted to file annually with the Division for the recovery of exogenous changes which may occur during the three- year term of the Plan. Exogenous changes are defined as "...significant increases or decreases in ProvGas' costs or revenues which are beyond ProvGas' reasonable control." Any disputes between ProvGas and the Division regarding either the nature or quantification of the exogenous changes are to be resolved by the RIPUC. The impact of any such exogenous changes will be debited or credited to a regulatory asset or liability account throughout the term of Energize RI and will be recovered or refunded at the expiration of the Plan through a method to be determined. In fiscal 1998, ProvGas did not earn its allowed rate of return primarily as a result of the extremely warm winter weather and the loss of non-firm margin. ProvGas believed the causes of these two events were beyond its reasonable control and thus deemed them to be exogenous changes. In March 1999, ProvGas reached an agreement with the Division, which allowed it to recover $2.45 million in revenue losses attributable to exogenous changes experienced by ProvGas in fiscal 1998. The RIPUC reviewed the exogenous changes agreement to ensure consistency with the terms of Energize RI and affirmed the agreement at its May 28, 1999 open meeting. During fiscal 1999, ProvGas recognized into revenue $2.45 million for the exogenous changes recovery, and at year-end has deferred approximately $.5 million of revenue under the provisions of the earnings cap of Energize RI. ProvGas intends to file for recovery of exogenous changes experienced in 1999 which resulted from factors similar to 1998. Absent further exogenous recovery and/or other factors such as colder than normal weather, ProvGas' ability to earn a 10.9 percent return on average common equity in the final year of Energize RI is substantially impaired. B. North Attleboro Gas Rate Increase In October 1991, the MDTE released its settlement order in regards to a rate request which included a qualified phase-in plan. The rate settlement required North Attleboro Gas to classify $545,000 of gas plant as plant held for future use. This plant is eligible to be included in future rates since North Attleboro Gas has met certain growth requirements which were required by the year 2000. North Attleboro Gas capitalized AFUDC and other costs of approximately $18,000 in 1998, and $37,000 in 1997 that related primarily to the gas plant not yet phased into North Attleboro Gas' rates under the plan. North Attleboro Gas amortized $76,000 in 1999, $214,000 in 1998, and $214,000 in 1997, of amounts previously deferred. 11. Stock Rights and Options Currently, one common stock purchase right is attached to each outstanding share of common stock. Each right entitles the holder to purchase one share of common stock at a price of $70 per share, subject to adjustment. In the event that certain transactions as defined in the common stock purchase rights agreement occur, each common stock purchase right will become exercisable for that number of shares of common stock of the acquiring company (or of the Company in certain circumstances) which at the time of the transaction has a market value of two times the exercise price. These rights expire on August 17, 2008 and may be redeemed by a vote of the Directors at a redemption price of $.01 per common stock purchase right. Due to the antidilutive characteristics of these rights, there is no assumed impact on earnings per share. The Company offered two stock option plans for officers, directors, and key employees which covered 250,000 shares of the Company's common stock. Options under the plans were granted at an exercise price equal to fair market value at the date of grant. The options expire 10 years from the date of grant and in the case of options granted to the directors, the options become exercisable after the first anniversary of the date of such grant. Pursuant to the provisions of the plans, each plan terminated on November 3, 1998 which was 10 years from the effective date of the plan. Any options outstanding under either of the plans shall remain in effect according to the plans' terms and conditions. In connection with the purchase of the oil distribution companies, the Company issued an option to purchase 100,000 shares of its common stock to a former owner of an acquired company in 1998. Stock option data are summarized as follows for the years ended September 30, 1999, 1998, and 1997: Page 27
Weighted Number Average of Shares Exercise Price - ---------------------------------------------------------------------------- Outstanding, September 30, 1996 62,238 $16.77 Granted 9,319 17.50 Exercised (2,130) 16.11 Expired (10,009) 17.71 -------- ------ Outstanding, September 30, 1997 59,418 16.75 Granted 100,000 23.00 Exercised (6,852) 16.79 Expired - - -------- ------ Outstanding, September 30, 1998 152,566 20.85 Granted - - Exercised (706) 19.00 Expired (1,206) 16.95 -------- ------ Outstanding, September 30, 1999 150,654 $20.62 ======== ======
The following table sets forth information regarding options outstanding at September 30, 1999: Number of Options 150,654 Range of Exercise Prices $ 13.875 - $23 Number Currently Exercisable 150,654 Weighted Average Exercise Price $ 20.62 Weighted Average Remaining Life 4.89 years Weighted Average Exercise Price for Currently Exercisable $ 20.62 At September 30, 1998 and 1997, 152,566 and 50,927 were currently exercisable, respectively. As described in Note 1, the Company uses the intrinsic method to measure compensation expense associated with grants of stock options or awards to employees. Had the Company used the fair value method to measure compensation, reported net income would have been $6,396,000 in 1998 and $7,822,000 in 1997. Earnings per share for fiscal year 1998 would have been $1.08. Earnings per share for fiscal 1997 remain unchanged. Earnings per share for fiscal 1999 remain unchanged as there were no options granted during the year. For purposes of determining the above disclosure required by Statement of Financial Accounting Standards No. 123, the fair value of options on their grant date was measured using the Black-Scholes option pricing model. Key assumptions used to apply this pricing model were as follows:
1998 1997 ----- ----- Risk-free interest rate 5.01% 5.43% Expected life of option grants (years) 4.0 7.0 Expected volatility of underlying stock 15% 15%
The pro-forma presentation only includes the effects of grants made subsequent to October 1, 1996. The estimated fair value of option grants made during 1998 and 1997 was $.70 and $1.41, respectively, per option. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. In January 1997, the shareholders of the Company adopted the Non-Employee Director Stock Plan, which provides that up to 50,000 shares of common stock may be granted to non-employee directors. The shares are granted, at no cost to the director, on the first day of each fiscal year based on each director's aggregate fees earned in the Page 28 prior fiscal year. All participants are entitled to vote the grant shares and receive dividends on the grant shares, however, full beneficial ownership vests on the third anniversary of the grant date provided the participant is still a director of the Company. Vesting may be accelerated under certain circumstances. The Company issued 1,963 and 2,131 shares under the Non-Employee Director Stock Plan in 1999 and 1998, respectively. 12. Hedging The Company's strategy is to use financial instruments for hedging purposes to manage the impact of market fluctuations on contractual commitments. The Company's non-regulated operation uses financial instruments to manage market risks and to reduce its exposure to fluctuations in the market prices of home heating oil, diesel, kerosene, and natural gas. The futures and option contracts, had net unrealized gains of approximately $40,000, which have been deferred on the accompanying Consolidated Balance Sheets at both September 30, 1999 and 1998. At September 30, 1999 and 1998, the estimated fair market value of the forward contracts totaled approximately $13.8 million and $15.2 million and were acquired at costs of approximately $12.2 million and $15.6 million. The fair market value of these forward contracts is based on quoted market prices and the contracts have maturities of less than one year. 13. Earnings per Share During 1998, the Company adopted the provisions of SFAS No. 128 "Earnings Per Share". Under the provisions of SFAS No. 128, basic earnings per share replaces primary earnings per share and the dilutive effect of stock options are excluded from the calculation. Fully diluted earnings per share are replaced by diluted earnings per share and include the dilutive effect of stock options and warrants, using the treasury stock method. All prior period earnings per share data have been restated to conform to the requirements of SFAS No. 128. A reconciliation of the weighted average number of shares outstanding used in the computation of basic and diluted earnings per share for the three years ended September 30, is as follows:
1999 1998 1997 --------- --------- --------- Weighted average shares 6,015,691 5,919,699 5,790,087 Effect of dilutive stock options 18,443 9,963 4,260 --------- --------- --------- Weighted average shares diluted 6,034,134 5,929,662 5,794,347 ========= ========= =========
The net income used in the calculation for basic and diluted earnings per share agrees with the net income appearing in the accompanying Consolidated Financial Statements. 14. Investments In July 1998, the Company and ERI Services, Inc. agreed to form CCEC. The joint venture is owned 50 percent by the Company's subsidiary, ProvEnergy Power Company, LLC and 50 percent by ERI Services' subsidiary, ERI Providence, LLC. CCEC's wholly-owned subsidiary DownCity Energy Company, LLC, was selected as the exclusive electric, heat, air conditioning, and related service provider for the next 30 years for most of the Providence Place Mall, which opened in August 1999. The Company had invested, primarily as bridge financing, $11.1 million of its total projected investment of $15 million at September 30, 1999. The Company anticipates obtaining permanent financing for the Mall during the first quarter of fiscal 2000, after which the Company projects its equity investment in the mall to approximate $3.0 million. 15. Acquisitions In July 1999, the Company acquired Keenan Oil Services, Inc. of Warwick, Rhode Island, which serves approximately 2,700 full-service residential customers. In November 1997, the Company acquired all of the outstanding stock of the Super Service Companies as well as all the assets of the Mohawk Companies. These acquisitions in Page 29 conjunction with the purchase of three small oil companies' customer lists in 1998 serve as a valuable market entry as a full service heating oil company. The amounts related to the purchases of these companies are not material to the financial position of the Company. These acquisitions have been accounted for as purchases and, accordingly, operating results of these businesses subsequent to the date of acquisition have been consolidated in the financial statements of the Company. Pro-forma results of operations, which include the operating results of these acquisitions, are not materially different than the operating results presented. On October 1, 1999, the Company acquired the customer list of one small oil company servicing approximately 600 customers in Northern Rhode Island. The Company continues to assess the energy market for potential acquisitions to fulfill its vision. 16. Operating Segments The Company's operations are classified into two principal reportable segments: Regulated Operations and Non-regulated Operations. The Regulated Operations consists primarily of natural gas sales and distribution to residential, commercial, and industrial customers. The Non- regulated Operations consists of heating oil, motor oil, and gas commodity sales to residential, commercial, and industrial customers and other energy management projects, which include project development fees. The accounting policies used to develop segment information correspond to those described in Note 1, "Significant Accounting Policies". The Company evaluates performance based on net income. (thousands of dollars) 1999 1998 1997 - ----------------------------------------------------------------------------- Energy Revenues - --------------- Regulated operation $ 183,373 $ 189,034 $ 215,258 Non-regulated operation 41,656 33,078 5,162 ----------- ---------- ---------- Total $ 225,029 $ 222,112 $ 220,420 =========== ========== ========== Interest Expense - ---------------- Regulated operation $ 7,660 $ 7,600 $ 7,570 Non-regulated operation 441 400 23 ----------- ---------- ---------- Total reportable segments 8,101 8,000 7,593 Parent company 599 133 10 ----------- ---------- ---------- Total $ 8,700 $ 8,133 $ 7,603 =========== ========== ========== Depreciation and amortization - ----------------------------- Regulated operation $ 16,925 $ 13,962 $ 12,869 Non-regulated operation 571 523 5 ----------- ---------- ---------- Total $ 17,496 $ 14,485 $ 12,874 =========== ========== ========== Income tax expense - ------------------ Regulated operation $ 5,083 $ 4,655 $ 4,785 Non-regulated operation (373) (966) (161) ----------- ---------- ---------- Total reportable segments 4,710 3,689 4,624 Parent company (170) (32) (233) ----------- ---------- ---------- Total $ 4,540 $ 3,657 $ 4,391 =========== ========== ========== Net income (loss) - ----------------- Regulated operation $ 9,837 $ 8,566 $ 8,546 Non-regulated operation (986) (1,692) (313) ----------- ---------- ---------- Total reportable segments 8,851 6,874 8,233 Parent company (426) (432) (402) ----------- ---------- ---------- Total $ 8,425 $ 6,442 $ 7,831 =========== ========== ========== Page 30 Total assets - ------------ Regulated operation $ 271,115 $ 238,493 $ 251,759 Non-regulated operation 13,870 11,593 1,360 ----------- ---------- ---------- Total reportable segments 284,985 250,086 253,119 Parent company 13,048 3,302 2,391 ----------- ---------- ---------- Total $ 298,033 $ 253,388 $ 255,510 =========== ========== ========== Capital expenditures - -------------------- Regulated operation $ 39,501 $ 30,783 $ 20,335 Non-regulated operation 41 367 90 ----------- ---------- ---------- Total $ 39,542 $ 31,150 $ 20,425 =========== ========== ========== Significant non-cash items - ------------------------- Deferred Federal income taxes and amortization of ITC Regulated operation $ 725 $ 970 $ 544 Non-regulated operation 4 2 - ----------- ---------- ---------- Total reportable segments 729 972 544 Parent company 1 1 1 ----------- ---------- ---------- Total $ 730 $ 973 $ 545 =========== ========== ========== Stock issuance for business acquisition Non-regulated operation $ 1,548 $ - $ - =========== ========== ========== All segment amounts reported above correspond to items reported in the Company's consolidated financial statements and are consistent with the presentation adopted in internal management reports. Under total assets, the Parent company amount consists primarily of the Company's investment in the Mall. 17. Comprehensive Income Effective October 1, 1998, the Company adopted the provisions of SFAS No. 130, "Reporting Comprehensive Income", which requires that an enterprise (a) classify items of other comprehensive income by their nature in a financial statement and (b) display the accumulated balance of other comprehensive income separately from retained earnings and additional paid-in capital in the equity section of a statement of financial position. A reconciliation of net income to other comprehensive income is as follows: (thousands of dollars) 1999 1998 1997 ------------------------------------- ------ ------ ------ Net Income $8,425 $6,442 $7,831 Unrealized holding gain (loss) on investments, net of tax (4) 43 - ------ ------ ------ Comprehensive Income $8,421 $6,485 $7,831 ====== ====== ====== The following is a summary of the reclassification adjustments and the income tax effects for the components of other comprehensive income (loss) for the year ended September 30:
Unrealized Holding Reclassification Gains on Adjustments for Investments Gains Other Arising During Included in Comprehensive (thousands of dollars) the Period Net Income Loss - ------------------------------------------------------------------------------------ 1999 Pretax income $ 78 $ (84) $ (6) Income tax expense 26 (28) (2) -------- -------- ------- Net change $ 52 $ (56) $ (4) ======== ======== =======
Page 31 18. New Accounting Pronouncements Effective for fiscal year 1999, the Company adopted the provisions of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information". SFAS No. 131 requires that a public business enterprise report financial and descriptive information about its reportable operating segments. This statement requires additional disclosure only and will not affect the financial position or results of operations of the Company. In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". This Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 is effective in the first fiscal quarter for the Company's fiscal year ending September 30, 2001. A company may also implement the Statement as of the beginning of any fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at a company's election, before January 1, 1998). The Company has not yet quantified the impact of adopting SFAS No. 133 on the financial statements and has not determined the timing of or method of adoption of SFAS No. 133. In March 1998, the American Institute of Certified Public Accountants issued SOP 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". It applies to all non-governmental entities and is effective for the Company's financial statements for the fiscal year ending September 30, 2000. The provisions of this SOP should be applied to internal-use software costs incurred in fiscal years subsequent to December 15, 1998 for all projects, including those projects in progress upon initial application of the SOP. The SOP establishes accounting standards for the determination of capital or expense treatment of expenditures for computer software developed or obtained for internal use based upon the stage of development. The SOP defines three stages as (1) Preliminary Project, (2) Application Development, and (3) Post- Implementation/Operation. As a general rule, the Preliminary Project and Post- Implementation/Operation phase expenditures are expensed and Application Development expenditures are capitalized. The Company will adopt the SOP in fiscal 2000 and does not expect it to have a material impact on the financial statements. 19. Unaudited Quarterly Financial Information The following is unaudited quarterly financial information for the two years ended September 30, 1999 and 1998. Quarterly variations between periods are caused primarily by the seasonal nature of energy sales and the availability of energy products.
(thousands of dollars, except per share amounts) Quarter Ended Dec. 31 Mar. 31 June 30 Sept. 30 --------------------------------------- Fiscal 1999 - ------------------------------------------------------------------ Energy revenues $64,585 $93,690 $38,714 $28,040 Operating income (loss) 8,105 17,976 658 (5,849) Net income (loss) 3,967 10,373 (376) (5,539) Net income (loss) per share* .66 1.73 (.06) (.90)
Page 32
FISCAL 1998 - ------------------------------------------------------------------ Energy revenues $67,942 $87,796 $39,968 $26,406 Operating income (loss) 8,620 16,611 (585) (5,984) Net income (loss) 4,403 9,535 (1,843) (5,653) Net income (loss) per share* .75 1.61 (.31) (.95)
* Calculated on the basis of the weighted average shares outstanding during the quarter. Page 33 11-Year Financial and Operational Summary For the Year Ended September 30
1999 1998 1997 1996 1995 1994 ----- ----- ---- ---- ---- ---- Natural gas distribution revenues (thousands of dollars): Residential $128,263 $126,479 $135,259 $128,875 $106,387 $130,888 Commercial/industrial 38,882 47,629 66,352 74,625 61,491 76,174 Firm transportation 11,440 7,982 2,251 330 171 - ------------------------------------------------------------------------------ Total firm 178,585 182,090 203,862 203,830 168,049 207,062 Interruptible and other 3,247 5,502 10,299 9,882 14,026 14,471 Non-firm transportation 863 792 504 411 633 287 Other 678 650 593 623 1,284 958 ------------------------------------------------------------------------------ Total natural gas distribution revenues $183,373 $189,034 $215,258 $214,746 $183,992 $222,778 ============================================================================== Natural gas distribution - gas sold and transported (MMcf): Residential 12,996 13,007 13,853 14,423 12,709 14,122 Commercial/industrial 4,563 5,727 8,086 9,694 8,772 9,360 Firm transportation 5,391 4,223 1,818 379 208 - ------------------------------------------------------------------------------ Total firm 22,950 22,957 23,757 24,496 21,689 23,482 Interruptible and other 848 1,409 2,633 2,610 4,950 4,547 Non-firm transportation 1,600 999 907 1,001 1,473 656 Company use and other 903 946 871 1,017 919 1,182 ------------------------------------------------------------------------------ Total gas sold and transported 26,301 26,311 28,168 29,124 29,031 29,867 Less: off-system sales - - 280 412 1,682 2,179 ------------------------------------------------------------------------------ Total gas delivered 26,301 26,311 27,888 28,712 27,349 27,688 ============================================================================== Natural gas distribution - gas purchased, produced, and transported (MMcf): Pipeline natural gas-contract 19,230 21,008 17,328 17,979 16,591 22,880 Pipeline natural gas-spot purchases - - 3,271 5,197 7,935 3,533 Pipeline natural gas-transportation 6,991 5,222 2,725 1,380 1,681 656 Underground storage 80 81 4,163 3,129 2,270 1,697 Liquefied natural gas and other - - 681 1,439 554 1,101 ------------------------------------------------------------------------------ Total gas sold and transported 26,301 26,311 28,168 29,124 29,031 29,867 ============================================================================== Average annual number of natural gas distribution customers: Residential: Heating 125,420 123,023 120,826 118,724 116,826 114,461 Non-heating 29,536 29,814 30,326 30,763 31,109 31,332 Commercial/industrial 15,484 15,981 16,656 16,645 16,509 16,337 Firm transportation 1,576 884 50 6 1 - ------------------------------------------------------------------------------ Total firm 172,016 169,702 167,858 166,138 164,445 162,130 Interruptible and non-firm transportation 112 123 125 138 142 141 ------------------------------------------------------------------------------ Total customers 172,128 169,825 167,983 166,276 164,587 162,271 ============================================================================== General: Average rate per Mcf residential heating $ 9.60 $ 9.51 $ 9.55 $ 8.77 $ 8.19 $ 9.10 Average rate per Mcf residential non-heating $ 13.99 $ 13.95 $ 14.06 $ 12.30 $ 11.76 $ 12.44 Maximum daily MMcf sendout 172 181 188 189 202 206 Actual calendar degree days 5,139 5,206 5,657 5,967 5,111 5,977 Normal calendar degree days 5,652 5,652 5,652 5,682 5,709 5,709 Colder (warmer) than normal -9.1% -7.9% 0.1% 5.0% -10.5% 4.7% Summary of operations (thousand of dollars): Natural gas distribution revenues $183,373 $189,034 $215,258 $214,745 $183,992 $222,778 Non-regulated operation revenues 41,656 33,078 5,162 407 - - ------------------------------------------------------------------------------ Total energy revenues 225,029 222,112 220,420 215,152 183,992 222,778 Cost of energy 119,043 122,991 124,376 120,246 100,944 135,104 ------------------------------------------------------------------------------ Operating margin 105,986 99,121 96,044 94,906 83,048 87,674 Operating and maintenance expense 53,047 51,993 48,768 49,033 44,368 46,223 Depreciation and amortization 17,496 14,485 12,874 11,997 10,470 9,615 Taxes other than income 14,553 13,981 13,732 13,007 11,769 12,540 Federal income taxes 4,540 3,657 4,391 4,932 3,442 4,446 Interest expense 8,700 8,133 7,603 7,465 7,379 6,247 Other income (loss) 1,123 57 (219) 1,194 1,203 182 Preferred dividend 348 487 626 696 696 696 Loss from discontinued operations, pre-tax - - - - - - ------------------------------------------------------------------------------ Net income (loss) $ 8,425 $ 6,442 $ 7,831 $ 8,970 $ 6,127 $ 8,089 ============================================================================== 1993 1992 1991 1990 1989 ----- ----- ----- ----- ----- Natural gas distribution revenues (thousands of dollars): Residential $120,997 $120,208 $105,809 $105,418 $ 96,899 Commercial/industrial 72,974 47,855 44,004 43,120 39,246 Firm transportation - - - - - ---------------------------------------------------------- Total firm 193,971 168,063 149,813 148,538 136,145 Interruptible and other 14,336 21,394 17,681 6,569 5,566 Non-firm transportation 54 74 735 833 1,182 Other 954 810 857 966 747 ---------------------------------------------------------- Total natural gas distribution revenues $209,315 $190,341 $169,086 $156,906 $143,640 ========================================================== Natural gas distribution - gas sold and transported (MMcf): Residential 13,783 13,166 11,534 14,452 13,948 Commercial/industrial 8,926 8,363 7,637 6,188 5,818 Firm transportation - - - - - ---------------------------------------------------------- Total firm 22,709 21,529 19,171 20,640 19,766 Interruptible and other 3,985 6,717 5,659 2,084 1,641 Non-firm transportation 386 869 4,127 5,026 3,287 Company use and other 1,187 1,264 1,445 985 977 ---------------------------------------------------------- Total gas sold and transported 28,267 30,379 30,402 28,735 25,671 Less: off-system sales 501 5 - 12 1 ---------------------------------------------------------- Total gas delivered 27,766 30,374 30,402 28,723 25,670 ========================================================== Natural gas distribution - gas purchased, produced, and transported (MMcf): Pipeline natural gas-contract 18,044 20,150 21,051 15,060 16,451 Pipeline natural gas-spot purchases 7,936 7,374 3,210 5,848 3,879 Pipeline natural gas-transportation 386 869 4,127 5,026 3,287 Underground storage 879 594 1,038 1,305 853 Liquefied natural gas and other 1,022 1,392 976 1,496 1,201 ---------------------------------------------------------- Total gas sold and transported 28,267 30,379 30,402 28,735 25,671 ========================================================== Average annual number of natural gas distribution customers: Residential: Heating 112,497 111,176 110,997 106,984 102,178 Non-heating 31,274 31,938 32,210 32,734 33,096 Commercial/industrial 16,264 15,889 15,114 13,179 12,654 Firm transportation - - - - - ---------------------------------------------------------- Total firm 160,035 159,003 158,321 152,897 147,928 Interruptible and non-firm transportation 123 115 79 65 65 ---------------------------------------------------------- Total customers 160,158 159,118 158,400 152,962 147,993 ========================================================== General: Average rate per Mcf residential heating $ 8.68 $ 7.80 $ 7.91 $ 7.21 $ 6.86 Average rate per Mcf residential non-heating $ 10.57 $ 10.37 $ 9.75 $ 8.68 $ 8.30 Maximum daily MMcf sendout 185 174 172 163 165 Actual calendar degree days 5,718 5,502 4,893 5,750 5,725 Normal calendar degree days 5,811 5,811 5,811 5,938 5,938 Colder (warmer) than normal -1.6% -5.3% -15.8% -3.2% -3.6% Summary of operations (thousands of dollars) Natural gas distribution revenues $209,315 $190,341 $169,086 $156,906 $143,640 Non-regulated operation revenues - (19) (14) 289 268 ---------------------------------------------------------- Total energy revenues 209,315 190,322 169,072 157,195 143,908 Cost of energy 126,314 111,568 101,707 91,306 83,947 ---------------------------------------------------------- Operating margin 83,001 78,754 67,365 65,889 59,961 Operating and maintenance expense 43,848 43,404 39,746 35,091 34,386 Depreciation and amortization 9,073 8,668 7,487 6,513 5,418 Taxes other than income 12,597 11,497 11,031 10,281 9,426 Federal income taxes 3,600 2,721 882 1,818 (2,690) Interest expense 6,653 6,837 7,764 7,721 6,686 Other income (loss) 83 203 2,236 500 (2,309) Preferred dividend 696 696 280 - - Loss from discontinued operations, pre-tax - - - - (7,740) ---------------------------------------------------------- Net income (loss) $ 6,617 $ 5,134 $ 2,411 $ 4,965 $ (3,314) ==========================================================
1 Mcf is one thousand cubic feet; 1 MMcf is one million cubic feet. Page 34 Selected Financial Data For the years ended September 30
1999 1998 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- ---- ---- Common share data: Earnings (loss) per share-basic $ 1.40 $ 1.09 $ 1.35 $ 1.57 $ 1.09 $ 1.46 $ 1.39 Earnings (loss) per share-diluted $ 1.40 $ 1.09 $ 1.35 $ 1.57 $ 1.09 $ 1.46 $ 1.39 Weighted average common shares outstanding-basic 6,015.7 5,919.7 5,790.1 5,709.2 5,624.2 5,534.1 4,761.8 Weighted average common shares outstanding-diluted 6,034.1 5,929.7 5,794.3 5,712.0 5,624.7 5,537.0 4,764.7 Actual common shares outstanding (year-end in thousands) 6,102 5,969 5,832 5,748 5,668 5,581 5,486 Dividends paid per share $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.06 $ 1.02 Common dividends (in thousands) $ 6,492 $ 6,377 $ 6,242 $ 6,155 $ 6,062 $ 5,856 $ 4,889 Earnings reinvested in the Corporation (in thousands) $ 1,933 $ 65 $ 1,589 $ 2,815 $ 65 $ 2,233 $ 1,728 Book value per share $ 15.27 $ 14.78 $ 14.69 $ 14.36 $ 13.85 $ 13.82 $ 13.37 Market data: Market price per share (year-end) $27 3/4 $19 1/2 $19 5/8 $17 1/2 $ 16 $17 1/4 $20 3/8 Market capitalization (year-end in thousands) $169,177 $116,394 $114,480 $100,593 $ 90,693 $ 96,267 $111,801 Average daily trading volume 8,530 4,954 9,885 4,533 3,867 4,194 5,771 High/low price range of common stock $30 1/8 $22 1/8 $20 1/2 $18 3/4 $17 1/2 $20 1/2 $21 1/4 to to to to to to to $ 18 $17 5/8 $16 1/2 $ 16 $14 5/8 $14 5/8 $15 1/8 Quarterly earnings per common share: December 31 $ 0.66 $ 0.75 $ 0.74 $ 0.90 $ 0.59 $ 0.68 $ 0.91 March 31 1.73 1.61 1.17 1.37 1.04 1.18 1.93 June 30 (0.06) (0.31) 0.02 (0.16) (0.15) (0.21) (0.52) September 30 (0.90) (0.95) (0.58) (0.54) (0.39) (0.17) (0.74) ----------------------------------------------------------------------------------- Annual earnings per share (1) $ 1.43 $ 1.10 $ 1.35 $ 1.57 $ 1.09 $ 1.48 $ 1.58 =================================================================================== (3) Capitalization (in thousands): Common stock, $1 Par, Authorized-20,000 shares $ 6,102 $ 5,969 $ 5,832 $ 5,748 $ 5,668 $ 5,581 $ 5,486 Amount paid in excess of par 61,966 59,198 56,827 55,404 54,258 53,042 51,582 Retained earnings 25,000 23,067 23,002 21,413 18,598 18,533 16,300 ----------------------------------------------------------------------------------- 93,068 88,234 85,661 82,565 78,524 77,156 73,368 Unrealized gain on financial instruments 39 43 - - - - - ----------------------------------------------------------------------------------- Total common equity 93,107 88,277 85,661 82,565 78,524 77,156 73,368 ----------------------------------------------------------------------------------- Preferred stock (4) 3,200 4,800 6,400 8,000 8,000 8,000 8,000 ----------------------------------------------------------------------------------- Long-term debt First Mortgage Bonds, secured by property 89,819 77,328 71,200 $ 72,800 74,400 61,000 61,000 Senior debentures - - - - - - - Other long-term debt 4,461 4,890 3,207 - - - - Capital leases 556 1,170 1,672 1,678 2,032 1,164 1,629 ----------------------------------------------------------------------------------- Subtotal 94,836 83,388 76,079 74,478 76,432 62,164 62,629 Less-current portion 3,515 3,233 3,707 2,022 1,950 2,085 466 ----------------------------------------------------------------------------------- Total long-term debt 91,321 80,155 72,372 72,456 74,482 60,079 62,163 ----------------------------------------------------------------------------------- Total capitalization $187,628 $173,232 $164,433 $163,021 $161,006 $145,235 $143,531 =================================================================================== Percentage of total capitalization: Common equity 50% 51% 52% 51% 49% 53% 51% Preferred stock 2% 3% 4% 5% 5% 6% 6% Long-term debt 48% 46% 44% 44% 46% 41% 43% Short term borrowings (in thousands): Balance outstanding at end of period $ 38,250 $ 20,079 $ 23,675 $ 23,270 $ 7,337 $ 27,700 $ 23,800 Average daily outstanding for the period $ 23,468 $ 18,342 $ 23,540 $ 13,955 $ 19,197 $ 27,020 $ 28,931 Total assets (in thousands) $298,033 $253,388 $255,510 $250,150 $227,127 $233,311 $224,550 1992 1991 1990 1989 ---- ---- ---- ---- Common share data: Earnings (loss) per share-basic $ 1.15 $ 0.56 $ 1.17 $ (0.80) Earnings (loss) per share-diluted $ 1.15 $ 0.56 $ 1.17 $ (0.80) Weighted average common shares outstanding-basic 4,478.4 4,337.9 4,235.8 4,127.1 Weighted average common shares outstanding-diluted 4,478.5 4,337.9 4,235.8 4,127.1 Actual common shares outstanding (year-end in thousands) 4,534 4,408 4,278 4,186 Dividends paid per share $ 1.10 $ 1.40 $ 1.40 $ 1.40 Common dividends (in thousands) $ 4,908 $ 6,057 $ 5,916 $ 5,761 Earnings reinvested in the Corporation (in thousands) $ 226 $ (3,646) $ (951) $ (9,075) Book value per share $ 12.02 $ 11.87 $ 12.62 $ 12.74 Market data: Market price per share (year-end) $ 16 $17 1/4 $15 1/4 $17 7/8 Market capitalization (year-end in thousands) $ 72,539 $ 76,031 $ 65,234 $ 74,839 Average daily trading volume 2,987 3,146 2,230 2,624 High/low price range of common stock $17 7/8 $17 1/4 $18 7/8 $19 1/8 to to to to $13 1/8 $14 1/8 $15 1/8 $16 1/4 Quarterly earnings per common share: December 31 $ 0.58 $ 0.62 $ 1.10 $ 0.61 March 31 1.67 1.33 1.25 1.40 June 30 (0.28) (0.32) (0.29) (1.53) September 30 (0.81) (1.04) (0.87) (1.25) -------------------------------------------- Annual earnings per share (1) $ 1.16 $ 0.59 $ 1.19 $ (0.77) ============================================ (2) Capitalization (in thousands): Common stock, $1 Par, Authorized-20,000 shares $ 4,534 $ 4,408 $ 4,278 $ 4,186 Amount paid in excess of par 35,385 33,548 31,705 30,204 Retained earnings 14,572 14,346 17,992 18,943 -------------------------------------------- 54,491 52,302 53,975 53,333 Unrealized gain on financial instruments - - - - -------------------------------------------- Total common equity 54,491 52,302 53,975 53,333 -------------------------------------------- Preferred stock (4) 8,000 8,000 - - -------------------------------------------- Long-term debt First Mortgage Bonds, secured 53,200 39,050 41,750 33,550 by property Senior debentures 7,533 8,033 8,491 8,962 Other long-term debt 66 132 488 595 Capital leases 2,089 2,549 2,029 2,331 -------------------------------------------- Subtotal 62,888 49,764 52,758 45,438 Less-current portion 1,930 6,879 3,610 2,708 -------------------------------------------- Total long-term debt 60,958 42,885 49,148 42,730 -------------------------------------------- Total capitalization $123,449 $103,187 $103,123 $ 96,063 ============================================ Percentage of total capitalization: Common equity 44% 51% 52% 56% Preferred stock 6% 8% 0% 0% Long-term debt 49% 42% 48% 44% Short term borrowings (in thousands): Balance outstanding at end of period $ 23,410 $ 38,214 $ 30,601 $ 28,996 Average daily borrowings outstanding for the period $ 38,877 $ 33,741 $ 27,077 $ 26,488 Total assets (in thousands) $197,459 $189,422 $182,258 $170,782
(1) Calculated on the basis of the weighted average shares outstanding during the quarter. Therefore this amount may not equal the earnings per common share for the year. (2) Included in the fiscal year 1989 earnings per share is a loss per common share on the discontinuance of the residential real estate operations of $1.23. (3) Includes the effect of the issuance of 850,000 shares of common stock on June 10, 1993. (4) This stock is subject to a cumulative annual sinking fund requirement of 16,000 shares per year at par ($1,600,000) plus accrued or unpaid dividends which commenced in February 1997. Page 35 Selected Income Statement and Balance Sheet Data For the years ended September 30
(in thousands, except where noted) 1999 1998 1997 1996 1995 1994 1993 - --------------------------------- ---- ---- ---- ---- ---- ---- ---- Federal income tax provision (benefit): Current $ 3,652 $ 2,526 $ 3,688 $ 2,989 $ 1,300 $ 3,211 $ 2,487 Deferred 888 1,131 703 1,943 2,142 1,235 1,113 Investment tax credits, net - - - - - - - ------------------------------------------------------------------------- Total Federal income tax provision (benefit) 4,540 3,657 4,391 4,932 3,442 4,446 3,600 Net income (loss) before preferred dividends of subsidiary 8,773 6,929 8,457 9,666 6,823 8,785 7,313 ------------------------------------------------------------------------- Income (loss) before income taxes $ 13,313 $ 10,586 $ 12,848 $ 14,598 $ 10,265 $ 13,231 $ 10,913 ========================================================================= Effective tax rate 34.10% 34.50% 34.20% 33.80% 33.60% 33.60% 32.90% Statutory tax rate 34.00% 34.00% 34.00% 34.00% 34.00% 34.00% 34.00% Property: Expenditures for property, plant, and equipment $ 39,542 $ 31,150 $ 20,425 $ 20,781 $ 19,597 $ 19,809 $ 13,882 Gross utility plant $345,671 $324,502 $300,829 $279,849 $262,769 $239,830 $221,769 Net utility plant $227,741 $202,313 $190,307 $179,473 $169,792 $159,012 $149,272 Net non-utility plant $ 2,628 $ 2,692 $ 1,182 $ 1,141 $ 1,958 $ 2,033 $ 2,118 Financial ratios: Payout ratio 77.14% 99.08% 80.00% 68.79% 99.08% 72.60% 88.70% Price/earnings ratio 19.82X 17.89x 14.54x 11.46x 14.68x 11.82x 14.66x Market to book ratio 1.81X 1.31x 1.34x 1.22x 1.16x 1.25x 1.52x Return on average common equity 9.29% 7.41% 9.31% 11.10% 7.87% 10.75% 10.35% Times interest charges earned before FIT 2.53X 2.30x 2.69x 2.96x 2.39x 3.12x 2.64x Times interest charges earned after FIT 2.01X 1.85x 2.11x 2.29x 1.92x 2.41x 2.10x Depreciation and amortization to energy revenues 7.77% 6.55% 5.84% 5.58% 5.69% 4.32% 4.34% Depreciation and amortization to utility plant 5.06% 4.30% 4.28% 4.29% 3.98% 4.01% 4.09% Other: Number of employees (actual) 615 637 562 575 553 568 608 (in thousands, except where noted) 1992 1991 1990 1989 - --------------------------------- ---- ---- ---- ---- Federal income tax provision (benefit): Current $ 2,374 $ 577 $ 1,713 $ (2,210) Deferred 347 305 107 (474) Investment tax credits, net - - (2) (6) ---------------------------------------- Total Federal income tax provision (benefit) 2,721 882 1,818 (2,690) Net income (loss) before preferred dividends of subsidiary 5,830 2,691 4,965 (3,314) ---------------------------------------- Income (loss) before income taxes $ 8,551 $ 3,573 $ 6,783 $ (6,004) ======================================== Effective tax rate 31.80% 24.70% 26.80% -44.80% Statutory tax rate 34.00% 34.00% 34.00% 34.00% Property: Expenditures for property, plant, and equipment $ 13,391 $ 12,411 $ 15,737 $ 17,019 Gross utility plant $210,087 $199,216 $189,952 $172,302 Net utility plant $144,767 $139,741 $135,331 $124,644 Net non-utility plant $ 2,203 $ 2,655 $ 4,475 $ 4,489 Financial ratios: Payout ratio 95.65% 250.00% 119.66% NM Price/earnings ratio 13.91x 30.80x 13.03x NM Market to book ratio 1.33x 1.45x 1.21x 1.40x Return on average common equity 9.61% 4.54% 9.25% -5.83% Times interest charges earned before FIT 2.25x 1.51x 1.86x 0.10x Times interest charges earned after FIT 1.85x 1.35x 1.64x 0.50x Depreciation and amortization to energy revenues 4.56% 4.43% 4.15% 3.77% Depreciation and amortization to utility plant 4.13% 3.76% 3.43% 3.14% Other: Number of employees (actual) 610 690 729 704
NM - Not Meaningful Page 36 GLOSSARY AND DEFINED TERMS - -------------------------- BUNDLING: The sale and/or transportation of natural gas under one rate, which does not differentiate separate rate components for the sale, transportation, storage, or gathering services associated with such sale or transportation. BUSINESS CHOICE: The unbundling program of ProvGas, which enables customers to purchase gas from other suppliers, i.e. retail marketers that "rent space" (transportation capacity) on ProvGas pipelines. CAPACITY: The amount of natural gas that can be produced, transported, stored, distributed, or utilized in a given period of time under design conditions. CITY GATE: The city gate is the point at which interstate and intrastate pipelines deliver natural gas to local distribution companies, in other words, the physical connection of an interstate pipeline and the pipes of a local gas utility. DEGREE DAY: A measure of the coldness of the weather experienced, based on the extent to which the daily mean temperature falls below a reference temperature, usually 65 degrees F. For example, on a day when the mean outdoor dry-bulb temperature is 35 degrees F, there would be 30 degree days experienced. A daily mean temperature usually represents the sum of the high and low readings divided by two. DEMAND SIDE MANAGEMENT REBATE PROGRAM: In 1996, ProvEnergy implemented this program, which furnishes rebates to customers installing new technologies, such as gas-fired air conditioning, cogeneration and gas motors--technologies that use proportionately more natural gas during summer months, ProvGas' off- peak season. ENERGIZE RI: An innovative three-year regulatory plan designed to provide price stability to customers, improve system reliability, and enhance economic development while improving earnings stability. Effective from the period from October 1, 1997 to September 30, 2000, the Plan provides customers with an initial price decrease of approximately four percent in addition to a three-year price freeze. Under the Plan, ProvGas may earn up to 10.9 percent annually on its average common equity, subject to certain limits as set forth in the Plan. ENERGY MARKETER: An entity engaged in selling energy commodities, such as natural gas. Services typically include procuring supply, arranging transportation, and delivery. Marketers usually buy for their own account and resell commodities. A major function of marketers is aggregating natural gas supplies and/or markets. EXOGENOUS CHANGE(S): The Energize RI agreement defines certain "Exogenous Changes," i.e., "...significant increases or decreases in the ProvGas' costs or revenues which are beyond ProvGas' reasonable control." FEDERAL ENERGY REGULATORY COMMISSION: An agency within the United States Department of Energy that, among other things, has jurisdiction over natural gas companies that sell or transport gas in interstate commerce for resale. FIRM CUSTOMER: A customer for whom contract demand is reserved and to whom the supplier is obligated to provide service. Firm customers pay a higher rate but also receive higher priority delivery service. Page 37 FIRM TRANSPORTATION SERVICE: Provides for the transportation on a firm 365-day basis of gas supplies purchased on a customer's behalf from a supplier other than ProvGas. Service is classified as either FT-1 or FT-2 SERVICE. FT-1 SERVICE: Firm transportation service for customers purchasing gas from other suppliers. This service requires daily balancing of consumption and deliveries. FT-2 SERVICE: Same as FT-1 SERVICE, without the requirement for recording daily usage. GATE STATION: See CITY GATE. HEDGING: The simultaneous execution of equal and opposite positions in the cash and futures markets in order to protect against adverse price movement in the cash market. INTERRUPTIBLE SERVICE: See NON-FIRM SERVICE LIQUEFIED NATURAL GAS: Natural gas that has been super cooled under pressure to (259 degrees F). Liquefied natural gas is almost pure methane. In volume it occupies 1/600 of the space occupied in the vapor state at standard conditions. LOCAL DISTRIBUTION COMPANY: A company that obtains the major portion of its natural gas revenues from the operations of a retail gas distribution system and that operates no transmission system other than incidental connections within its own system or to the system of another company. Both ProvGas and North Attleboro Gas are LDCs. NON-FIRM SERVICE: Sales and transportation service that is offered at both a lower cost and lower level of reliability. Under this service, gas companies can interrupt customers on short notice, typically during peak service days in the winter season. Non-firm services are provided through individually negotiated contracts and in most cases, the price and availability charge takes into account the price of the customer's alternative fuel. OFF-PEAK: The period during a day, week, month, or year when the load being delivered by a gas system is not at or near the maximum volume delivered by that system for the corresponding period of time. For ProvGas, the period from May through October. PEAK: For ProvGas, the period from November through April. PORTLAND NATURAL GAS TRANSMISSION SYSTEM: PNGTS is a new 272-mile gas pipeline that runs from Quebec to Massachusetts. ProvGas is using its Supervisory Control and Data Acquisition (SCADA) system to monitor the portion of the pipeline that runs from Pittsburg, New Hampshire, on the Quebec border, to Westbrook, Maine, just outside of Portland, Maine. PRICE STABILIZATION PLAN SETTLEMENT AGREEMENT: See ENERGIZE RI. RATE STABILIZATION PLAN: See ENERGIZE RI. Page 38 STORAGE SERVICE: A service in which natural gas is received by the seller of the service and held for the customer's account for redelivery at a later time. It requires the use of storage facilities that can be reinjected and produced with minimal loss. Storage service usually requires payment of injection fees, withdrawal fees, and holding fees and involves limits on rates and times of injection and withdrawal, and maximum volumes to be held. THERM: A unit of heating value equivalent to 100,000 British thermal units (BTUs). THROUGHPUT: Total of transportation volumes and tariff sales; gas volumes delivered through a LDC's gas distribution system. UNBUNDLING: The process of separating out the package of services offered by a gas company--i.e., transportation, storage, gathering and products extraction-- and charging separate rates or rate components for each service that fairly represent the cost of providing that service. See BUSINESS CHOICE. Page 39 ABBREVIATIONS, ACRONYMS AND OTHER DEFINED TERMS: AFUDC: Allowance for Funds Used During Construction ALGONQUIN: Algonquin Gas Transmission Company CCEC: Capital Center Energy Company, LLC CGA: Cost of Gas Adjustment Clause CIS: Customer Information System DEM: Rhode Island Department of Environmental Management DETM: Duke Energy Trading and Marketing, L.L.C. DIVISION: Rhode Island Division of Public Utilities and Carriers FASB: Financial Accounting Standards Board FERC: Federal Energy Regulatory Commission GAAP: Generally Accepted Accounting Principles GCC: Gas Change Clause HVAC: Heating, Ventilating and Air Conditioning systems IRP: Integrated Resource Plan IT: Information Technology LDC: Local Distribution Company LNG: Liquefied Natural Gas MALL: Providence Place Mall MDTE: Massachusetts Department of Telecommunications and Energy PBR: Performance Based Regulation PNGTS: Portland Natural Gas Transmission System PRP: Potentially Responsible Party RIPUC: Rhode Island Public Utilities Commission SCADA: Supervisory Control and Data Acquisition system SEC: Securities and Exchange Commission Page 40 SFAS: Statement of Financial Accounting Standards SOP: Statement of Position VEBA TRUST: Voluntary Employee Benefit Association Trust COMPANY NAMES: CCEC: Capital Center Energy Company, LLC COMPANY: Providence Energy Corporation or ProvEnergy NORTH ATTLEBORO GAS: North Attleboro Gas Company PROVENERGY FUELS: ProvEnergy Fuels, Inc. PROVENERGY POWER: ProvEnergy Power, L.L.C. PROVENERGY SERVICES: Providence Energy Services, Inc. PROVGAS: The Providence Gas Company SOUTHERN UNION: Southern Union Company 41 EX-21 4 SUBSIDIARIES OF THE REGISTRANT Exhibit 21 Exhibit 21. SUBSIDIARIES OF THE REGISTRANT - ------------------------------------------- The Providence Gas Company - Incorporated under the laws of Rhode Island. Newport America Corporation - Incorporated under the laws of Rhode Island. Providence Energy Services, Inc. - Incorporated under the laws of Rhode Island. North Attleboro Gas Company - Incorporated under the laws of Massachusetts. Providence Energy Oil Enterprises, Inc. - Incorporated under the laws of Rhode Island. ProvEnergy Power Company, LLC - Organized under the laws of Rhode Island. PEC Ventures, Inc. - Incorporated under the laws of Rhode Island. EX-27 5 FINANCIAL DATA SCHEDULE
UT 1,000 12-MOS SEP-30-1999 OCT-01-1998 SEP-30-1999 PER-BOOK 218,190 2,628 27,579 38,450 11,186 298,033 6,102 61,966 25,039 93,107 0 3,200 91,321 38,250 0 0 3,515 0 0 0 68,640 298,033 225,029 4,540 204,139 208,679 16,350 1,123 17,473 8,700 8,773 348 8,425 6,492 6,827 26,864 1.40 1.40
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