-----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, F2Q3M9ARLFFCtkDRz9oQZSBwgphgD1R6rQuX0ix4TM7wR+CXUQe63UFqW8vfE8v6 nHTpye7fEyXRbby89g4ZZg== /in/edgar/work/20000605/0000203248-00-000018/0000203248-00-000018.txt : 20000919 0000203248-00-000018.hdr.sgml : 20000919 ACCESSION NUMBER: 0000203248-00-000018 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19990614 ITEM INFORMATION: FILED AS OF DATE: 20000605 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHERN UNION CO CENTRAL INDEX KEY: 0000203248 STANDARD INDUSTRIAL CLASSIFICATION: [4924 ] IRS NUMBER: 750571592 STATE OF INCORPORATION: DE FISCAL YEAR END: 0630 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-06407 FILM NUMBER: 649195 BUSINESS ADDRESS: STREET 1: 504 LAVACA ST 8TH FL CITY: AUSTIN STATE: TX ZIP: 78701 BUSINESS PHONE: 5124775852 8-K 1 0001.txt ================================================================= UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 ------------------- FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) May 31, 2000 SOUTHERN UNION COMPANY (Exact name of registrant as specified in its charter) Delaware 1-6407 75-0571592 (State or other juris- (Commission (I.R.S. Employer diction of incorpora- File Number) Identification No.) tion) 504 Lavaca Street, Eighth Floor 78701 Austin, Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (512) 477-5852 ================================================================= ITEM 5. OTHER EVENTS As previously reported, Southern Union Company, a Delaware corpo- ration ("Southern Union"), SUG Acquisition Corporation, a Rhode Island corporation and a wholly-owned subsidiary of Southern Union ("Merger Sub"), and Valley Resources, Inc., a Rhode Island corporation ("Valley Resources"), entered into an Agreement and Plan of Merger on November 30, 1999 providing for, among other things, the merger of Merger Sub with Valley Resources, Inc., and Valley Resources, Inc. into Southern Union. On November 15, 1999, Southern Union, GUS Acquisition Corporation, a Rhode Island corporation and a wholly-owned subsidiary of Southern Union ("Newco"), and Providence Energy Corporation, a Rhode Island corporation ("Providence Energy"), entered into an Agreement and Plan of Merger, providing for, among other things, the merger of Newco with Providence Energy, and Providence Energy into Southern Union. In connection with the above-mentioned mergers, certain historical financial statements and related notes thereto of Valley Resources and Providence Energy are attached hereto as Exhibits to this Form 8-K. Audited historical financial statements and related notes of Valley Resources for the three years ended August 31, 1999. Unaudited historical financial statements and related notes of Valley Resources for the six months ended February 29, 2000. Audited historical financial statements and related notes of Providence Energy for the three years ended September 30, 1999. Unaudited historical financial statements and related notes of Providence Energy for the six months ended March 31, 2000. Additionally, in connection with the completed merger of Pennsylvania Enterprises, Inc., ("PEI"), with and into Southern Union on November 4, 1999, the unaudited September 30, 1999 interim financial statements and related notes thereto of PEI is attached hereto as Exhibits to this Form 8-K. Unaudited historical financial statements and related notes of PEI for the nine months ended September 30, 1999. ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS (c) Exhibit No. ---------- 23.1 Consent of Independent Public Accountants, Grant Thornton, LLP. 23.2 Consent of Independent Public Accountants, Arthur Andersen, LLP. 99.1 Audited historical financial statements and related notes of Valley Resources for the three years ended August 31, 1999. 99.2 Unaudited historical financial statements and related notes of Valley Resources for the six months ended February 29, 2000. 99.3 Audited historical financial statements and related notes of Providence Energy for the three years ended September 30, 1999. 99.4 Unaudited historical financial statements and related notes of Providence Energy for the six months ended March 31, 2000. 99.5 Unaudited historical financial statements and related notes of PEI for the nine months ended September 30, 1999. SIGNATURES Pursuant to the requirements 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. SOUTHERN UNION COMPANY ---------------------- (Registrant) Date June 5, 2000 By RONALD J. ENDRES ------------ ---------------- Ronald J. Endres Executive Vice President and Chief Financial Officer Date June 5, 2000 By DAVID J. KVAPIL ------------ --------------- David J. Kvapil Senior Vice President and Corporate Controller (Principal Accounting Officer) EX-23.1 2 0002.txt EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS We hereby consent to the incorporation of our report dated September 27, 1999 relating to the consolidatd financial statements of Valley Resources, Inc. and subsidiaries in the current Report on Form 8-K of Southern Union Company. /s/ GRANT THORNTON, LLP ------------------- Grant Thornton, LLP Boston, Massachusetts June 5, 2000 EX-23.2 3 0003.txt EXHIBIT 23.2 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the inclusion in this Registration Statement on Form 8-K 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 Providence Energy Corporation's Annual Report on Form 10-K for the year ended September 30, 1999, and all references to our Firm included in this registration statement. /s/ARTHUR ANDERSEN, LLP -------------------- Arthur Andersen, LLP Boston, Massachusetts May 31, 2000 EX-99.1 4 0004.txt EXHIBIT 99.1 VALLEY RESOURCES, INC. AND SUBSIDIARIES Report of Independent Certified Public Accountants To the Stockholders of Valley Resources, Inc. We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Valley Resources, Inc. (a Rhode Island corporation) and subsidiaries as of August 31, 1999 and 1998 and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the three years in the period ended August 31, 1999. These consolidated financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Valley Resources, Inc. and subsidiaries as of August 31, 1999 and 1998 and the consolidated results of their operations and their cash flows for each of the three years in the period ended August 31, 1999, in conformity with generally accepted accounting principles. s/Grant Thornton LLP Boston, Massachusetts September 27, 1999 Consolidated Statements of Earnings
For the year ended August 31 1999 1998 1997 - ---------------------------- ---- ---- ---- Operating revenues: Utility gas revenues ............................... $58,529,386 $59,343,603 $66,230,787 Nonutility revenues ................................ 23,180,791 22,245,293 21,253,190 - ----------- ----------- ----------- Total .......................................... 81,710,177 81,588,896 87,483,977 - ----------- ----------- ----------- Operating expenses: Cost of gas sold ................................... 30,493,570 31,437,159 37,843,842 Cost of sales - nonutility ......................... 15,787,006 15,516,609 14,790,835 Operations ............................................ 17,557,983 17,880,673 17,890,281 Maintenance ........................................ 1,689,664 1,671,829 1,633,671 Depreciation ....................................... 3,397,598 3,274,513 3,143,719 Taxes - other than Federal income ................. 4,116,642 4,119,808 4,242,841 - Federal income ............................ 1,772,370 1,330,045 1,334,677 - ----------- ----------- ----------- Total .......................................... 74,814,833 75,230,636 80,879,866 - ----------- ----------- ----------- Operating income ...................................... 6,895,344 6,358,260 6,604,111 Other income - net of tax ............................. 299,205 288,464 423,476 - ----------- ----------- ----------- Total income before interest .......................... 7,194,549 6,646,724 7,027,587 - ----------- ----------- ----------- Interest charges: Long-term debt ..................................... 2,388,817 2,482,840 1,957,052 Other .............................................. 619,123 557,923 1,411,222 - ----------- ----------- ----------- Total .......................................... 3,007,940 3,040,763 3,368,274 - ----------- ----------- ----------- Net income available for common stock ................. $ 4,186,609 $ 3,605,961 $ 3,659,313 =========== =========== =========== Average number of common shares outstanding ........... 4,979,508 4,966,270 4,267,038 Basic and diluted earnings per share .................. $0.84 $0.73 $0.86 The accompanying Notes are an integral part of these statements.
20 Consolidated Statements of Cash Flows
For the year ended August 31 1999 1998 1997 - ---------------------------- ---- ---- ---- Increase (decrease) in cash: Cash flows from operating activities: Net income .......................................... $ 4,186,609 $ 3,605,961 $ 3,659,313 Adjustments to reconcile net income to net cash: Depreciation ...................................... 3,397,598 3,274,513 3,143,719 Provision for uncollectibles ...................... 1,247,842 1,912,813 1,603,597 Deferred Federal income taxes ..................... 274,752 773,217 441,638 Amortization of investment tax credits ............ (47,688) (48,402) (49,090) Change in assets and liabilities: Accounts receivable ............................... (1,380,511) (413,842) (2,841,404) Deferred fuel costs ............................... 911,178 (1,277,658) 1,620,252 Unbilled gas costs ................................ 6,104 1,702 (1,140) Fuel and other inventories ........................ (140,622) 301,688 (71,908) Prepayments ....................................... (157,965) (63,281) 119,631 Common stock held for dividend reinvestment plan .. (21,472) 230,552 (220,829) Prepaid pensions .................................. (1,564,044) (1,728,432) (924,745) Accounts payable .................................. 1,110,923 (23,435) (944,778) Security deposits ................................. (9,155) (57,230) (61,952) Taxes accrued ..................................... 173,400 73,554 171,730 Other ............................................. 118,264 548,114 520,799 - ----------- ----------- ----------- Total adjustments ................................. 3,918,604 3,503,873 2,505,520 - ----------- ----------- ----------- Net cash provided by operating activities ........... 8,105,213 7,109,834 6,164,833 - ----------- ----------- ----------- Cash flows from investing activities: Utility capital expenditures ........................ (3,841,768) (3,555,028) (3,599,752) Nonutility capital expenditures ..................... (640,849) (978,538) (693,229) Other investments ................................... (103,422) (44,924) (81,222) - ----------- ----------- ----------- Net cash used by investing activities ............... (4,586,039) (4,578,490) (4,374,203) - ----------- ----------- ----------- Cash flows from financing activities: Dividends paid ...................................... (3,723,724) (3,698,155) (3,130,413) Common stock transactions ........................... (54,870) 869,155 6,450,861 Issuance of long-term debt, net of issuance cost .... - -0- -0- 9,655,515 Issuance of revolving credit arrangement ............ - -0- 100,000 100,000 Retirement of long-term debt ........................ (2,303,875) (209,200) (1,553,395) Increase (decrease) in notes payable ................ 2,500,000 400,000 (13,000,000) - ----------- ----------- ----------- Net cash used by financing activities ............... (3,582,469) (2,538,200) (1,477,432) - ----------- ----------- ----------- Net (decrease) increase in cash ........................ (63,295) (6,856) 313,198 Cash, beginning ........................................ 813,155 820,011 506,813 - ----------- ----------- ----------- Cash, ending ........................................... $ 749,860 $ 813,155 $ 820,011 - ----------- ----------- ----------- Supplemental disclosures of cash flow information: Cash paid during the year for: Interest .......................................... $ 2,932,870 $ 2,788,390 $ 3,378,894 =========== =========== =========== Federal income taxes .............................. $ 1,341,309 $ 500,000 $ 861,140 =========== =========== =========== Supplemental disclosures of noncash activity: Capital lease obligations incurred .................. $ 30,297 $ 832,026 $ 388,139 =========== =========== =========== The accompanying Notes are an integral part of these statements.
21 Consolidated Balance Sheets
August 31 1999 1998 - --------- ---- ---- Assets: Utility plant, at cost ................................................. $ 86,445,703 $82,964,897 Less: Accumulated provision for depreciation .......................... 34,111,279 31,655,080 ------------ ----------- Net utility plant ...................................................... 52,334,424 51,309,817 ------------ ----------- Leased property-less accumulated amortization of $4,604,837 and $4,007,748 ...................................................... 1,555,855 2,302,601 ------------ ----------- Nonutility property-less accumulated provision for depreciation of $4,510,553 and $4,315,566 ........................................... 4,162,601 4,106,232 ------------ ----------- Other investments ...................................................... 1,740,028 1,636,606 ------------ ----------- Current assets: Cash ............................................................... 749,860 813,155 Accounts receivable-less allowance for uncollectibles of $1,309,410 . and $928,279 ...................................................... 9,816,986 9,684,317 Deferred fuel costs ................................................. -0- 484,418 Deferred unbilled gas costs ......................................... 432,228 438,332 Fuel and other inventories .......................................... 5,959,289 5,818,667 Prepayments ......................................................... 1,510,917 1,352,952 Common stock held for dividend reinvestment plan .................... 142,568 121,096 ------------ ----------- Total current assets ............................................. 18,611,848 18,712,937 ------------ ----------- Deferred debits: Recoverable postretirement benefit .................................. -0- 230,974 Recoverable vacations accrued ....................................... 610,798 632,966 Recoverable deferred Federal income taxes ........................... 6,062,414 6,108,997 Recoverable transition obligation ................................... 10,700 21,300 Unamortized debt discount and expense ............................... 1,643,382 1,711,815 Prepaid pensions .................................................... 10,388,058 8,824,014 Other ............................................................... 3,102,418 2,882,349 ------------ ----------- Total deferred debits ........................................... 21,817,770 20,412,415 ------------ ----------- Total assets .................................................... $100,222,526 $98,480,608 ============ =========== The accompanying Notes are an integral part of these statements.
22 Consolidated Balance Sheets
August 31 1999 1998 - --------- ---- ---- Capitalization and liabilities: Capitalization ....................................................... $ 65,278,234 $64,860,725 ------------ ----------- Revolving credit arrangement ......................................... 2,400,000 2,400,000 ------------ ----------- Obligations under capital leases ..................................... 775,132 1,527,655 ------------ ----------- Current liabilities: Current maturities of long-term debt .............................. 150,000 2,288,937 Obligations under capital leases .................................. 780,723 774,946 Notes payable .................................................... 4,800,000 2,300,000 Accounts payable .................................................. 5,385,917 4,274,994 Security deposits ................................................. 968,410 977,565 Taxes accrued ..................................................... 608,709 435,309 Deferred fuel costs................................................ 426,760 -0- Accrued interest .................................................. 760,848 793,732 Other ............................................................. 716,594 740,971 ------------ ----------- Total current liabilities ..................................... 14,597,961 12,586,454 ------------ ----------- Commitments and contingencies Deferred credits: Unamortized investment tax credit ................................. 578,508 626,196 Transition obligation ............................................. 10,700 21,300 Unfunded deferred Federal income taxes ............................ 1,802,439 1,849,022 Postretirement benefit obligation ................................. -0- 230,974 Other ............................................................. 1,911,733 1,785,230 ------------ ----------- Total deferred credits ........................................ 4,303,380 4,512,722 ------------ ----------- Deferred Federal income taxes ........................................ 12,867,819 12,593,052 ------------ ----------- Total liabilities ............................................. 34,944,292 33,619,883 ------------ ----------- Total capitalization and liabilities .......................... $100,222,526 $98,480,608 ============ =========== The accompanying Notes are an integral part of these statements.
23 Consolidated Statements of Changes in Common Stock Equity
Common Shares Issued Paid in Retained and Outstanding Capital Earnings --------------- ------- -------- Number Amount ------ ------ Balance, August 31, 1996 .............. 4,280,028 $4,280,028 $18,204,063 $ 7,750,406 --------- - ---------- ----------- ----------- Add (deduct): Net income ......................... 3,659,313 Cash dividends on common stock ..... (3,130,413) Issuance of common stock ........... 620,000 620,000 5,893,100 Other .............................. (62,239) --------- - ---------- ----------- ----------- Balance, August 31, 1997 .............. 4,900,028 4,900,028 24,034,924 8,279,306 --------- - ---------- ----------- ----------- Add (deduct): Net income ......................... 3,605,961 Cash dividends on common stock ..... (3,698,155) Issuance of common stock ........... 93,000 93,000 795,296 Other .............................. (19,141) --------- - ---------- ----------- ----------- Balance, August 31, 1998 .............. 4,993,028 4,993,028 24,811,079 8,187,112 --- ---- --------- - ---------- ----------- ----------- Add (deduct): Net income ......................... 4,186,609 Cash dividends on common stock ..... (3,723,724) Other .............................. (54,870) --------- - ---------- ----------- ----------- Balance, August 31, 1999 .............. 4,993,028 $4,993,028 $24,756,209 $ 8,649,997 ========= ========== =========== =========== The accompanying Notes are an integral part of these statements.
Consolidated Statements of Capitalization
August 31 1999 1998 - --------- ---- ---- Common stock equity: Common stock, $1 par value Authorized 20,000,000 shares Issued and outstanding 4,993,028 shares ................... $ 4,993,028 $ 4,993,028 Paid in capital ............................................. 24,756,209 24,811,079 Retained earnings............................................ 8,649,997 8,187,112 - ----------- ----------- 38,399,234 37,991,219 Less: Accounts receivable from Valley Resources, Inc. 401(k) Employee Stock Ownership Plan ............................. 2,593,911 2,768,343 - ----------- ----------- Total common stock equity .......................... 35,805,323 35,222,876 - ----------- ----------- Long-term debt: 8% First Mortgage Bonds, due 2022 ........................... 20,029,000 20,039,000 7.7% Debentures, due 2027 ................................... 7,000,000 7,000,000 9% Notes Payable, due 1999 .................................. -0- 2,138,937 Note payable, due 2007 ...................................... 2,593,911 2,748,849 - ----------- ----------- Total .............................................. 29,622,911 31,926,786 Less: Current maturities .................................... 150,000 2,288,937 - ----------- ----------- Total long-term debt ............................... 29,472,911 29,637,849 - ----------- ----------- Total capitalization ............................... $65,278,234 $64,860,725 =========== =========== The accompanying Notes are an integral part of these statements.
24 Notes to Consolidated Financial Statements Note A: Summary of Significant Accounting Policies CONSOLIDATION - The consolidated financial statements include the accounts of Valley Resources, Inc. and its active wholly-owned subsidiaries (the "Corporation")--Valley Gas Company ("Valley Gas"), Valley Appliance and Merchandising Company ("VAMCO"), Valley Propane, Inc. ("Valley Propane"), Morris Merchants, Inc. ("Morris Merchants") (d/b/a the Walter F. Morris Company), and Bristol & Warren Gas Company ("Bristol & Warren"). The consolidated financial statements also include the Corporation's 80% interest in Alternate Energy Corporation ("AEC"). All significant intercompany transactions have been eliminated where required. USE OF ESTIMATES - 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 - The utility operations of Valley Gas and Bristol & Warren (collectively the "Utilities") are subject to regulation by the Rhode Island Public Utilities Commission ("RIPUC"). Accounting policies conform with generally accepted accounting principles, as applied in the case of regulated public utilities, and are in accordance with the accounting requirements and rate making practices of the RIPUC. DEPRECIATION - Annual provisions for depreciation for the Utilities are determined on a composite straight-line basis. The composite rate for fiscal 1999, 1998 and 1997 was 2.91%. Depreciation provisions for other subsidiary companies are provided on the straight-line and accelerated methods at rates ranging from 2.86% to 34%. OTHER ASSETS - Included in other assets is goodwill which is amortized on the straight-line basis over forty years. The Corporation continually evaluates the carrying value of goodwill. Any impairments would be recognized when the expected undiscounted future operating cash flows derived from goodwill is less than the carrying value. UNAMORTIZED DEBT EXPENSE - Costs incurred to obtain debt financing are amortized over the expected term of the related debt. Amortization of deferred financing costs is recorded as interest expense. DEFERRED FUEL COSTS - The Utilities' tariffs include a Purchased Gas Price Adjustment ("PGPA") which allows an adjustment of rates charged to customers in order to recover all changes in gas costs from stipulated base gas costs. The PGPA provides for an annual reconciliation of total gas costs billed with the actual cost of gas incurred. Any excess or deficiency in amounts collected as compared to costs incurred is deferred and either reduces the PGPA or is billed to customers over subsequent periods. DEFERRED UNBILLED GAS COSTS - Revenue is recorded on the basis of bills rendered on a cycle basis throughout the month. Valley Gas defers to the following month that portion of the base cost of gas delivered but not yet billed under the cycle billing system. ACCOUNTING FOR INCOME TAXES - Income tax regulations allow recognition of certain transactions for tax purposes in time periods other than the period during which these transactions will be recognized in the determination of net income for financial reporting purposes. As required by generally accepted accounting principles, deferred income taxes are provided to reflect the tax effect of these timing differences in the proper accounting periods. In accordance with Financial Accounting Standards Board Statement No. 109 "Accounting for Income Taxes," deferred income taxes are recorded for all book and tax temporary timing differences. 25 Investment tax credits relating to the Utilities property have been deferred and will be amortized to income over the productive lives of the related assets. Investment tax credits earned by the Corporation's other subsidiary companies were recognized as a reduction of Federal income tax expense in the year utilized. PENSION PLANS - The Utilities maintain two non-contributory defined benefit pension plans covering substantially all of their employees which provide benefits based on compensation and years of service. The Utilities fund pension costs that are deductible for Federal income tax purposes (see Note H). On January 1, 1997, the Valley Gas Company 401(k) plan and the Valley Gas Employee Stock Ownership Plan ("ESOP") were merged into the Valley Resources 401(k) Employee Stock Ownership Plan ("KSOP"). The KSOP covers all Corporate employees, if eligible (see Note D). The expense of these plans in fiscal 1999, 1998 and 1997 was $173,300, $144,000, and $160,800, respectively. Morris Merchants maintains an employee profit sharing plan covering substantially all of the employees who have completed one year of service. Contributions to the plan are at the discretion of the Board of Directors. In fiscal 1999, 1998, and 1997, profit sharing expense was $53,500, $72,000, and $64,600, respectively. NEW ACCOUNTING STANDARDS - In June of 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. It also 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. The new standard is effective for fiscal years beginning after June 15, 2000. Adoption of SFAS No. 133 will not affect the Corporation's financial condition or results of operations. INVENTORIES - Fuel and other inventories at August 31 are as follows:
1999 1998 ---- - ---- Fuels (at average cost) ........................ $3,462,277 $3,542,932 Merchandise and other (at average cost) ........ 1,234,326 1,241,224 Merchandise (at LIFO) .......................... 1,262,686 1,034,511 ---------- - ---------- $5,959,289 $5,818,667 ========== ==========
Merchandise (at LIFO), if valued at current cost, would have been greater by $205,000 in fiscal 1999 and $246,300 in fiscal 1998. Note B: Common Stock and Rights On August 26, 1997, the Corporation issued 620,000 shares of common stock. The net proceeds of this offering were used to reduce the short-term debt of the Utilities, to make loans to nonutility subsidiaries, to repay short-term debt and for working capital requirements. On September 24, 1997, the underwriters of the stock offering exercised their over-allotment option and 93,000 additional common shares were issued. Pursuant to the Corporation's direct stock purchase plan, stockholders can reinvest dividends and make limited additional cash investments. Shares issued through dividend reinvestment can be acquired on the open market or original issue. All shares issued pursuant to the plan in fiscal 1999 and 1998 were open-market purchases. On August 31, 1999 and 1998, 10,019 and 10,116 shares, respectively, were held by the Corporation for issuance to the plan. 26 On August 31, 1999, except as mentioned above, no shares of common stock of the Corporation were held by or for the account of the Corporation or were reserved for officers or employees or for options, warrants or other rights, except 41,125, shares of common stock reserved subject to sale under the Corporation's direct stock purchase plan. Each share of common stock of the Corporation includes one preferred stock purchase Right which entitles the holder to purchase one one-hundredth of a share of Cumulative Participating Junior Preferred Stock, par value $100, at a price of $35 per one one-hundredth of a share subject to adjustment. The Rights are not currently exercisable, and trade automatically with the common stock. The Rights will generally become exercisable, and separate certificates representing the Rights will be distributed, upon occurrence of certain events in excess of a stipulated percentage of ownership. The Rights should not interfere with any merger or business combination approved by the Board of Directors because, prior to the Rights becoming exercisable, the Rights may be redeemed by the Corporation at $0.01 per Right. The Rights have no dilutive effect and will not affect reported earnings per share. Note C: Short-Term Debt The Corporation borrows on bank lines of credit at the prevailing interest rate available at the time of borrowing. The Corporation either pays commitment fees or maintains compensating balances in connection with these lines of credit. Commitment fees paid in fiscal 1999, 1998, and 1997 amounted to $105,900, $106,800 and $110,000, respectively. There are no legal restrictions on withdrawal of compensating balances. A detail of short-term borrowings for fiscal 1999, 1998, and 1997 is as follows:
1999 1998 1997 ---- ---- ---- At year end Weighted average interest rate ..... 5.4% 5.7% 5.7% Unused lines of credit ............. $24,200,000 $34,700,000 $35,100,000 For the year ended Weighted average interest rate ..... 5.5% 5.8% 5.7% Average borrowings ................. $ 4,162,500 $ 2,433,300 $16,800,000 Maximum month-end borrowings ....... $ 7,400,000 $ 6,200,000 $22,000,000 Month of maximum borrowings ........ December December January
Note D: Long-Term Debt The composition of long-term debt is included in these financial statements in the separate Consolidated Statements of Capitalization. The aggregate amount of maturities and sinking fund requirements for each of the five fiscal years following fiscal 1999 are: 2000, $930,700; 2001, $2,904,800; 2002, $383,400; 2003, $224,600 and 2004, $212,600, inclusive of capitalized lease obligations. Valley Gas utility plant and equipment have been pledged as collateral to secure its long-term debt. In accordance with the redemption provisions of the Valley Gas 8% First Mortgage Bonds, $10,000, $51,000, and $122,000 of the bonds were redeemed by holders in fiscal 1999, 1998, and 1997, respectively. The fair market value of the Corporation's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Corporation for debt of the same remaining maturities. Management believes the carrying value of the debt approximates the fair value at August 31, 1999. Regulatory treatment allows payments under capital leases to be recorded as rental expenses. Rental expenses for all leases in fiscal 1999, 1998, and 1997 were $1,028,700, $1,218,600, and $1,169,500, respectively. Valley Gas entered into an intermediate term financing arrangement with a bank in November 1995. The terms of the arrangement call for a $6,000,000 revolving line of credit which matures in 2000. 27 The Corporation borrowed funds under a line of credit at rates less than the prevailing prime rate, which are restricted in their use to being loaned to the KSOP. The receivable from the KSOP has been shown as a reduction of common stock equity. The financing by the KSOP is secured by the common stock of two unregulated subsidiaries and the unallocated shares held by the KSOP. The Corporation's common stock purchased by the KSOP with the borrowed money is held by the KSOP trustee in a "suspense account." As the Corporation matches employee 401(k) contributions and makes discretionary contributions to the plan, a portion of the common stock is released from the suspense account and allocated to participating employees. Any dividends on unallocated shares are used to pay loan interest. Note E: Restriction on Retained Earnings On August 31, 1999, $1,751,400 of the retained earnings of Valley Gas were available for the payment of cash dividends to the Corporation under the most restrictive provisions of Valley Gas' first mortgage bonds. There are no restrictions as to the payment of dividends for the other subsidiaries. Note F: Income Taxes In accordance with Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" ("SFAS 109"), the Corporation's financial statements are required, among other things, to record the cumulative deferred income taxes on all temporary timing differences. As approved by the RIPUC, the Utilities did not fully record deferred income taxes but, rather, "flowed through" certain tax benefits to utility customers prior to fiscal 1994. On August 31, 1999, the Corporation has a liability of $6,062,400 on the Consolidated Balance Sheets as recoverable deferred income taxes and a corresponding recoverable deferred charge. The liability represents the tax effect of timing differences for which deferred income taxes had not been provided, increased in accordance with SFAS 109 for the tax effect of future revenue requirements. The Utilities are recovering unfunded deferred taxes from utility customers over the remaining book life of utility property. Federal income tax expense has been calculated based on filing a consolidated corporate tax return and is comprised of the following:
1999 1998 1997 - ---- ---- ---- Current income tax expense: Operating expense ................................... $1,497,618 $ 556,828 $ 893,039 Nonoperating expense................................. (4,279) 57,482 103,200 - ---------- ---------- ---------- 1,493,339 614,310 996,239 - ---------- ---------- ---------- Deferred income tax expense: Accelerated depreciation............................. 303,332 316,197 332,771 Pensions............................................. 531,775 587,667 314,413 Deferred fuel costs.................................. (111,946) 99,941 (229,039) Uncollectibles....................................... (126,488) (36,985) (23,830) Directors' fees and interest......................... (47,438) (42,525) (36,845) Bond premium ........................................ (6,240) (6,240) (6,240) Rate case expenses................................... (11,926) (61,308) (97,257) Capitalization of inventory costs.................... (8,748) 1,155 28,869 Consulting contracts................................. (19,920) (19,920) 30,570 Software amortization................................ (140,332) (86,136) 140,856 Alternative minimum tax.............................. - -0- 96,359 -0- Excess VEBA contribution............................. (78,532) (78,532) (78,532) Other ............................................... (8,785) 3,544 65,902 - ---------- ---------- ---------- 274,752 773,217 441,638 - ---------- ---------- ---------- Total ............................................... $1,768,091 $1,387,527 $1,437,877 ========== ========== ==========
28 The Federal income tax amounts included in the Consolidated Statements of Earnings differ from the amounts which result from applying the statutory Federal income tax rate to income from operations before income tax. The reasons, with related percentage effects, are shown below:
1999 1998 1997 - ---- ---- ---- Statutory Federal rate ......................................... 34% 34% 34% Maintenance costs capitalized for book purposes ............. (4) (4) (4) Cost of removal ............................................. (1) (1) (1) ESOP dividends .............................................. (1) (1) (1) Prior year over accrual ..................................... - -0- (2) -0- Other ....................................................... 2 2 -0- - -- -- -- Total ....................................................... 30% 28% 28% == == ==
Temporary differences which gave rise to the following deferred tax assets and liabilities at August 31, 1999 and 1998 are:
1999 1998 ---- ---- Unbilled revenues .................... $ 262,737 $ 266,652 Directors' fees and interest ......... 342,285 294,847 Other ................................ 793,234 568,055 ------------ ------------ Total deferred tax assets ......... 1,398,256 1,129,554 ------------ ------------ Accelerated depreciation ............. (9,499,234) (9,195,902) Pensions ............................. (3,550,626) (3,018,851) Software amortization ................ (450,450) (590,782) Deferred fuel costs .................. (52,757) (164,703) Other ................................ (713,008) (752,368) ------------ - ------------ Total deferred tax liabilities .... (14,266,075) (13,722,606) ------------ - ------------ Total deferred taxes ................. $(12,867,819) $(12,593,052) ============ ============
The Corporation's nonutility operations are subject to state income taxes. For fiscal 1999, 1998, and 1997, state income taxes totaled $93,800, $124,100, and $170,700, respectively. Note G: Regulatory Matter On June 1, 1997, the Utilities received approval to redesign their rates and offer transportation services to large commercial and industrial customers. Note H: Commitments and Contingencies PENSION PLANS - The Utilities have two non-contributory defined benefit pension plans covering substantially all of their employees and a supplemental pension plan covering certain officers. Net periodic pension cost (income) is comprised of the following components:
For the Year Ended August 31, 1999 1998 1997 - ----------------------------- ---- ---- ---- Service cost ..................................... $ 704,892 $ 640,994 $ 543,241 Interest cost on projected benefit obligation .... 1,448,757 1,360,031 1,337,602 Expected return on plan assets ................... (3,373,477) (3,245,272) (2,579,914) Recognition of actuarial gain .................... (280,738) (400,878) (142,367) Net amortization and deferral .................... (63,478) (83,307) (83,307) ----------- - ----------- ----------- Net periodic pension income ...................... $(1,564,044) $(1,728,432) $ (924,745) =========== =========== ===========
29 Assumptions used in actuarial calculations were as follows:
For the Year Ended August 31, 1999 1998 1997 - ----------------------------- ---- ---- ---- Weighted average discount rate .................. 7.00% 7.00% 7.25% Future compensation increases ................... 5.50 5.50 5.50 Expected long-term rate of return on assets ..... 9.00 9.00 9.00
The following tables set forth the reconciliation of the plans' benefit obligation and fair value of assets is as follows:
For the Year Ended August 31, 1999 1998 - ----------------------------- ---- ---- Reconciliation of benefit obligation: Obligation at September 1....................... $21,240,659 $19,266,157 Service cost.................................... 704,892 640,994 Interest cost................................... 1,448,757 1,360,031 Amendments...................................... -0- 297,429 Actuarial (gain) loss........................... (598,721) 716,918 Benefit payments................................ (1,118,340) (1,040,870) ----------- - ----------- Obligation at August 31......................... $21,677,247 $21,240,659 =========== =========== Reconciliation of fair value of plan assets: Fair value of plan assets at September 1........ $38,027,205 $36,565,680 Actual return on plan assets ................... 3,327,389 2,502,395 Benefit payments................................ (1,118,340) (1,040,870) ----------- - ----------- Fair value of plan assets at August 31.......... $40,236,254 $38,027,205 =========== ===========
The funded status of the plans is as follows:
August 31, 1999 1998 - ---------- ---- ---- Plan assets at fair value: Projected benefit obligation less than (in excess of) plan assets......... $20,401,395 $18,802,795 Unrecognized net gain..................................................... (10,609,146) (10,511,112) Unrecognized transition amount............................................ (381,660) (529,184) Unrecognized prior service cost .......................................... 977,469 1,061,515 ----------- ----------- Prepaid pension costs .................................................... $10,388,058 $ 8,824,014 =========== ===========
Assets of the employee benefit plans are invested in domestic and international equities, domestic and international fixed income securities and other short-term debt instruments. POSTRETIREMENT LIFE AND HEALTH BENEFIT PLAN - Valley Gas sponsors a postretirement benefit plan that covers substantially all of its employees except for nonunion employees hired on or after September 1, 1993 and union employees hired on or after April 1, 1994. The plan provides medical, dental and life insurance benefits. The plan is non-contributory. In accordance with Statement of Financial Accounting Standards No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS 106"), Valley Gas records the cost for this plan on an accrual basis. As permitted by SFAS 106, Valley Gas will record the transition obligation over 20 years. Valley Gas' cost under this plan for fiscal 1999, 1998 and 1997 was $701,000, $725,000, and $775,600, respectively. 30 The regulatory asset represents the excess of postretirement benefits on the accrual basis over amounts authorized to be recovered in rates. The RIPUC authorized Valley Gas a phase-in recovery of the tax deductible portion of these postretirement benefits, if funded. The following table sets forth the reconciliation of the plans' benefit obligation and fair value of plan assets is as follows:
For the year ended August 31, 1999 1998 - ---------------------------- - ---- ---- Reconciliation of benefit obligation: Obligation at September 1................................... $6,523,627 $6,057,989 Service cost................................................ 144,363 147,852 Interest cost............................................... 443,516 426,588 Actuarial loss.............................................. 418,504 184,606 Benefit payments............................................ (311,095) (293,408) - ---------- ---------- Obligation at August 31..................................... $7,218,915 $6,523,627 ========== ========== Reconciliation of fair value of plan assets: Fair value of plan assets at September 1.................... $2,351,191 $1,699,662 Actual return on plan assets................................ 97,620 (40,980) Employer contributions...................................... 1,242,884 985,917 Benefit payments............................................ (311,095) (293,408) - ---------- ---------- Fair value of plan assets at August 31...................... $3,380,600 $2,351,191 ========== ==========
The following table sets forth the plan's funded status reconciled with the amounts recognized in the Company's financial statements is as follows:
For the year ended August 31, 1999 1998 - ---------------------------- ---- ---- Accumulated postretirement benefit obligation in excess of plan assets..... $(3,838,315) $(4,172,436) Unrecognized net loss (gain) from past experience different from that assumed and from changes in assumptions ................................ 208,257 (277,466) Unrecognized transition obligation......................................... 3,888,824 4,166,598 ----------- ----------- Prepaid (accrued) postretirement benefit cost.............................. $ 258,766 $ (283,304) =========== ===========
Net periodic postretirement benefit cost consisted of the following:
For the Year Ended August 31, 1999 1998 1997 - ----------------------------- ---- ---- ---- Service cost - benefits attributable to service during the period....... $ 144,363 $ 147,852 $ 136,372 Interest cost on accumulated postretirement benefit obligation.......... 443,516 426,588 419,246 Expected return on plan assets.......................................... (147,746) (105,934) (55,569) Net amortization and deferral........................................... 277,774 277,774 277,774 Recognition of net actuarial gain....................................... (17,093) (21,232) (23,414) --------- --------- --------- Net periodic postretirement benefit cost................................ $ 700,814 $ 725,048 $ 754,409 ========= ========= =========
For measurement purposes, a 9% (4.5% for dental costs) annual rate of increase in the per capita cost of covered health care benefits was assumed for 1999; the rate of increase for medical costs was assumed to decrease gradually to 5% by fiscal 2002 and to remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation at August 31, 1999 by $534,000 and the aggregate of the service and the interest cost components of net periodic postretirement benefit cost for the year then ended by $54,000. The weighted average discount rate used in determining the 30 accumulated postretirement benefit obligation was 7.0%, 7.0% and 7.25% for fiscal 1999, 1998 and 1997, respectively. The expected long-term rate of return on plan assets was 8.50% for fiscal 1999, 1998 and 1997. LONG-TERM OBLIGATIONS - The Utilities have contracts which expire at various dates through the year 2012 for the purchase, delivery and storage of natural gas and supplemental gas supplies. Certain contracts for the purchase of the supplemental gas supplies contain minimum purchase obligations which approximate 2% of total system requirements. FERC ORDER NO. 636 TRANSITION COSTS - As a result of FERC Order 636, the Utilities' interstate pipeline service providers have unbundled their supply, storage and transportation services. This unbundling caused the interstate pipeline companies to incur substantial costs in order to comply with Order 636. These transition costs include four types: (1) unrecovered gas costs (gas costs that have been incurred but not yet recovered by the pipelines when they were providing bundled service to local distribution companies); (2) gas supply realignment costs (the cost of renegotiating existing gas supply contracts with producers); (3) stranded costs (unrecovered costs of assets that cannot be assigned to customers of unbundled services); and (4) new facilities costs (costs of new facilities required to physically implement Order 636). Pipelines are expected to be allowed to recover prudently incurred transition costs from customers primarily through a demand charge, after approval by FERC. The Utilities' pipeline suppliers began direct billing these costs in fiscal 1994 as a component of demand charges. The Utilities estimate their remaining portion of transition costs to be $10,700 and have recognized a liability for these costs as of August 31, 1999. The RIPUC has allowed the recovery of transition costs through the PGPA. Under the provisions of SFAS 71, regulatory assets totaling $10,700 were recorded for the expected future recovery of the transition obligations. Actual transition costs to be incurred depend on various factors, and, therefore, future costs may differ from the amounts discussed above. CONTINGENT LIABILITIES - A lawsuit has been filed against Valley Gas and other parties by Blackstone Valley Electric Company ("Blackstone") seeking contribution towards a judgment against Blackstone's share of total cleanup costs of approximately $6,000,000 at the Mendon Road site in Attleboro, Massachusetts. The expenses relate to a site to which oxide waste was transported in the 1930's prior to the incorporation of Valley Gas. Management is of the opinion the Corporation will prevail as a result of the indemnification provisions included in the agreement entered into when Valley Gas acquired the utility assets from Blackstone. Management cannot determine the future cash flow impact, if any, of this claim and related legal fees. Legal fees associated with this claim are recovered in rates. In a recent decision of the U.S. Court of Appeals for the First Circuit, Blackstone's appeal of the judgment against it was sustained and the case was remanded for further proceedings, including a referral of the case to the EPA to determine if the substance in question (FFC) is hazardous. Valley Gas received letters of responsibility from the Rhode Island Department of Environmental Management ("DEM") with respect to releases from coal waste on its properties that were the site of the former Tidewater gas manufacturing plant in Pawtucket, Rhode Island and the former Hamlet Avenue gas manufacturing plant in Woonsocket, Rhode Island. Valley Gas and Blackstone have submitted site investigation reports to DEM relating to certain releases on these sites. Management cannot determine the future cash flow impact, if any, of these claims and related expenses. As noted above, management takes the position that it is indemnified by Blackstone for any such expenses. Management intends to seek recovery from Blackstone and any insurance carriers deemed to be at risk during the relevant periods. Remediation of sites such as the former Tidewater plant and the Hamlet Avenue plant are governed by a regulatory framework which now permits more flexibility in methods of remediation and in property reuse. Note I: Segment Information The Corporation adopted SFAS 131, "Disclosure about Segments of an Enterprise and Related Information," during fiscal 1999. SFAS 131 established standards for reporting information about operating segments ("business segments") in annual financial statements and requires selected information in interim financial statements. Business segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, to make 32 decisions on how to allocate resources and to assess performance. The Corporation's chief operating decision making group is the Chief Executive Officer ("CEO") and certain other executive officers that report directly to the CEO. The operating segments are organized and managed separately because each segment offers different products or services. The Corporation evaluates the performance of its business segments based on the operating income generated. Operating income does not include income taxes, interest expense, extraordinary charges, and non-operating income and expense items. Under SFAS 131, an operating segment that does not exceed certain quantitative levels is not considered a reportable segment. Instead, the results of all segments that do not exceed the quantitative thresholds are combined and reported as one segment and referred to as "all other." The Corporation's subsidiaries VAMCO, Valley Propane and AEC business segments did not meet these quantitative threshholds and have been grouped into the "all other" category. The accounting policies of the operating segments are the same as those described in Note A except the intercompany transactions have not been eliminated in determining individual segment results. The following information is presented relative to the gas, contract sales and other operations of the Corporation.
1999 1998 1997 - ---- ---- ---- Gas Operations Operating revenues........................................... $ 58,529,386 $59,343,603 $66,230,787 Operating income before Federal income taxes................. 6,991,106 6,178,629 6,465,007 Identifiable assets at August 31............................. 95,121,383 89,713,540 88,927,776 Depreciation................................................. 2,817,161 2,692,326 2,594,712 Capital expenditures......................................... 3,841,768 3,555,028 3,599,752 Contract Sales Operating revenues........................................... $ 15,291,428 $15,104,272 $14,243,778 Operating income before Federal income taxes................. 549,041 646,303 612,744 Identifiable assets at August 31............................. 3,959,667 3,993,215 3,749,762 Depreciation................................................. 44,866 45,703 51,704 Capital expenditures......................................... 9,255 30,704 21,703 All Other Operations, including Corporate & Eliminations Operating revenues........................................... $ 7,889,363 $ 7,141,021 $ 7,009,412 Operating income before Federal income taxes................. 1,127,567 863,373 861,037 Identifiable assets at August 31............................. 1,141,476 4,773,853 5,019,599 Depreciation................................................. 535,571 536,484 497,303 Capital expenditures......................................... 631,594 947,834 671,526 Total Corporation Operating revenues........................................... $ 81,710,177 $81,588,896 $87,483,977 Operating income before Federal income taxes................. 8,667,714 7,688,305 7,938,788 Federal income tax expense................................... (1,772,370) (1,330,045) (1,334,677) Nonoperating income-net...................................... 299,205 288,464 423,476 Interest expense............................................. (3,007,940) (3,040,763) (3,368,274) Net income................................................... 4,186,609 3,605,961 3,659,313 Identifiable assets at August 31............................. 100,222,526 98,480,608 97,697,137 Depreciation................................................. 3,397,598 3,274,513 3,143,719 Capital expenditures......................................... 4,482,617 4,533,566 4,292,981
33 Expenses used to determine operating income before Federal income taxes are charged directly to each segment or are allocated based on time studies. Assets allocated to each segment are based on specific identification of such assets as provided by corporate records. Segment Information at August 31, 1998 and 1997 has been restated to conform with the presentation of SFAS 131 at August 31, 1999. Note J: Summarized Quarterly Financial Data (Unaudited)
Three months ended (in thousands, except as to basic and diluted earnings (loss) per share) November February May August - ---------------------------------- -------- -------- --- ------ Fiscal 1999 Total operating revenues............................ $15,270 $29,201 $23,581 $13,658 Income (loss) before Federal income taxes........... $(1,091) $ 5,057 $ 3,228 $(1,287) Net income (loss)................................... $ (637) $ 3,292 $ 2,320 $ (789) Basic and diluted earnings (loss) per share.......... $ (0.13) $ 0.66 $ 0.47 $ (0.16) Fiscal 1998 Total operating revenues............................ $15,824 $30,428 $22,587 $12,750 Income (loss) before Federal income taxes........... $(1,288) $ 4,818 $ 2,692 $(1,229) Net income (loss)................................... $ (761) $ 3,232 $ 1,828 $ (693) Basic and diluted earnings (loss) per share......... $ (0.15) $ 0.65 $ 0.37 $ (0.14)
EX-99.2 5 0005.txt EXHIBIT 99.2 VALLEY RESOURCES, INC. AND SUBSIDIARIES Consolidated Condensed Statements of Earnings (Unaudited)
3 Months Ended 6 Months Ended - ---------------------- ----------------------- Feb. 29, Feb. 28, Feb. 29, Feb. 28, 2000 1999 2000 1999 -------- -------- -------- -------- (in thousands except share and per share numbers) Operating Revenues: Utility Gas Revenues $ 26,693 $ 23,345 $ 36,973 $ 33,169 Nonutility Revenues 6,152 5,856 12,270 11,302 ----------- ----------- ----------- ----------- Total 32,845 29,201 49,243 44,471 ----------- ----------- ----------- ----------- Operating Expenses: Cost of Gas Sold 15,164 12,725 20,791 17,868 Cost of Sales - Nonutility 4,256 3,621 8,508 7,409 Operations 4,801 4,492 9,133 9,103 Maintenance 469 428 917 837 Depreciation and Amortization 914 852 1,827 1,708 Taxes - Other Than Federal Income 1,434 1,330 2,326 2,196 - Federal Income 1,729 1,775 1,422 1,326 ----------- ----------- ----------- ----------- Total 28,767 25,223 44,924 40,447 ----------- ----------- ----------- ----------- Operating Income 4,078 3,978 4,319 4,024 Other Income (Loss) - Net of Tax 91 81 (226) 150 ----------- ----------- ----------- ----------- Total Income 4,169 4,059 4,093 4,174 ----------- ----------- ----------- ----------- Interest Charges: Long-Term Debt 571 610 1,140 1,230 Other 233 157 412 288 ----------- ----------- ----------- ----------- Total 804 767 1,552 1,518 ----------- ----------- ----------- ----------- Net Income $ 3,365 $ 3,292 $ 2,541 $ 2,656 =========== =========== =========== =========== Average Number of Common Shares Outstanding 4,986,620 4,976,890 4,983,013 4,980,682 Basic & Diluted Earnings Per Average Common Share Outstanding $0.67 $0.66 $0.51 $0.53 Dividends Declared on Common Stock . $0.1875 $0.1875 $0.375 $0.375
The accompanying Notes are an integral part of these statements VALLEY RESOURCES, INC. AND SUBSIDIARIES Consolidated Condensed Balance Sheets
(Unaudited) Feb. 29, Aug. 31, 2000 1999 -------- -------- (in thousands) ASSETS Utility Plant - Net $ 52,774 $ 52,334 -------- -------- Leased Property - Net 1,189 1,556 -------- -------- Nonutility Property-Net 4,236 4,163 -------- -------- Other Investments 1,701 1,740 -------- -------- Current Assets: Cash 491 750 Accounts Receivable - Net 17,116 9,817 Deferred Unbilled Gas Costs 1,817 432 Fuel and Other Inventories (Note 3) 4,788 5,959 Prepayments 992 1,511 Common Stock held for Dividend Reinvestment-amounting to 4,572 and 10,116 shares respectively (Note 4) 101 143 -------- -------- Total 25,305 18,612 -------- -------- Deferred Debits: Recoverable Vacations Accrued 771 611 Unamortized Debt Discount and Expense 1,609 1,643 Prepaid Pensions 11,268 10,388 Recoverable Deferred FIT 5,950 6,062 Recoverable Transition Obligation 11 11 Other 4,065 3,103 -------- -------- Total 23,674 21,818 -------- -------- $108,879 $100,223 ======== ========
The accompanying Notes are an integral part of these statements. VALLEY RESOURCES, INC. AND SUBSIDIARIES Consolidated Condensed Balance Sheets (Cont'd)
(Unaudited) Feb. 29, Aug. 31, 2000 1999 -------- - -------- (in thousands) CAPITALIZATION & LIABILITIES Capitalization: Common Stock $ 4,993 $ 4,993 Paid In Capital 24,765 24,756 Retained Earnings 9,324 8,650 Less: Accounts Receivable from ESOP (2,492) (2,594) -------- - -------- Total Common Stock Equity 36,590 35,805 -------- - -------- Long-Term Debt (Less Current Maturities): 8% First Mortgage Bonds, Series Due 2022 19,932 20,029 7.7% Debentures, Due 2027 7,000 7,000 Notes Payable 2,342 2,444 -------- - -------- Total Long-Term Debt 29,274 29,473 -------- - -------- Total Capitalization 65,864 65,278 -------- - -------- Revolving Credit Arrangement 2,400 2,400 -------- - -------- Obligation Under Capital Lease 577 775 -------- - -------- Current Liabilities: Current Maturities of Long-Term Debt 150 150 Obligation Under Capital Lease 612 781 Notes Payable 8,200 4,800 Accounts Payable 7,803 5,386 Security Deposits & Refund Obligations 1,142 968 Taxes Accrued 1,798 609 Deferred Fuel Costs 624 427 Accrued Interest 728 761 Other 878 716 -------- - -------- Total 21,935 14,598 -------- - -------- Commitment and Contingencies Deferred Credits 4,494 4,304 -------- - -------- Deferred Federal Income Taxes 13,609 12,868 -------- - -------- $108,879 $100,223 ======== ========
The accompanying Notes are an integral part of these statements. VALLEY RESOURCES, INC. AND SUBSIDIARIES Consolidated Condensed Statements of Cash Flows (Unaudited)
For the 6 Months Ended - ------------------- Feb. 29, Feb. 28, 2000 1999 - -------- -------- (in thousands) Cash Flows from Operating Activities: Net Income $ 2,541 $ 2,656 Adjustments to Reconcile Net Income to Net Cash used in Operating Activities: Depreciation and Amortization 1,827 1,708 Provision for Uncollectibles 625 624 Deferred Federal Income Taxes 741 659 Amortization of ITC (24) (24) Change in Assets and Liabilities: Accounts Receivable (7,924) (7,324) Deferred Fuel Costs 198 1,414 Unbilled Gas Costs (1,385) (1,257) Fuel and Other Inventories 1,172 1,067 Other Current Assets (319) (215) Accounts Payable, Accrued Expenses and Current Liabilities 3,780 1,764 Other - Net (532) (35) ------- ------- Net Cash Provided by Operating Activities 700 1,037 ------- ------- Cash Flows from Investing Activities: Utility Capital Expenditures (1,953) (1,860) Nonutility Capital Expenditures (388) (336) Other Investments 39 (23) ------- ------- Net Cash Used by Investing Activities (2,302) (2,219) ------- ------- Cash Flows from Financing Activities: Dividends Paid (1,867) (1,859) Capital Stock Transactions 9 (33) Retirement of Long-Term Debt (199) (85) Increase in Notes Payable 3,400 2,900 ------- ------- Net Cash Provided by Financing Activities 1,343 923 ------- ------- Net (Decrease) in Cash (259) (259) Cash - Beginning 750 813 ------- ------- Cash - Ending $ 491 $ 554 ======= ======= Supplemental Disclosures of Cash Flow Information Cash Paid During the Period for: Interest $ 1,585 $ 1,585 ======= ======= Federal Income Taxes $ 125 $ -0- ======= ======= Capital Lease Obligations Incurred $ -0- $ 11 ======= =======
The accompanying Notes are an integral part of these statements. NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS Note 1 - ------ In the opinion of the Corporation, the accompanying unaudited consolidated condensed financial statements contain all adjustments (consisting of only normal recurring accruals and matters discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations") necessary to present fairly the financial position at February 29, 2000, the results of operations for the three- and six-months ended February 29, 2000 and February 28,1999 and Statement of Cash Flows for the six-months ended February 29, 2000 and February 28, 1999. The results of operations for the three- and six-month periods ended February 29, 2000 and February 28, 1999 are not necessarily indicative of the results to be expected for the full year. Note 2 - ------ The Corporation computes basic and diluted earnings per average common share in accordance with SFAS 128, based on the weighted average number of shares outstanding during the period.
(Unaudited) (Unaudited) 3 Months Ended 6 Months Ended ----------------------- ----------------------- Feb. 29, Feb. 28, Feb. 29, Feb. 28, 2000 1999 2000 1999 ---------- ---------- ---------- ---------- Net Income $3,364,578 $3,292,123 $2,541,089 $2,655,508 Weighted average shares outstanding 4,986,620 4,976,890 4,983,013 4,980,682 Basic and diluted earnings per share $0.67 $0.66 $0.51 $0.53
Note 3 - ------ Inventories - Fuel and Other Inventories: (in Thousands)
(Unaudited) February 29, August 31, 2000 1999 ------------ - ----------- Fuels (at average cost) $2,160 $3,462 Merchandise and Other (at average cost) 1,170 1,234 Merchandise (at LIFO) 1,458 1,263 ------ ------ $4,788 $5,959 ====== ======
Note 4 - ------ Pursuant to the dividend reinvestment plan, stockholders can reinvest dividends and make limited additional investments in shares of Common Stock. Shares issued through dividend reinvestment can be acquired on the open market or original issue. Note 5 - ------ On December 1, 1999, Southern Union Company and Valley Resources, Inc. announced that they have signed a definitive merger agreement under which Valley Resources, Inc. will ultimately merge into Southern Union Company in a transaction which is valued at approximately $160 million, including assumption of debt. See the section in "Management's Discussion and Analysis of Financial Condition and Results of Operations" entitled "Valley Resources Inc./Southern Union Company Merger" for further details. EX-99.3 6 0006.txt EXHIBIT 99.3 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) 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. 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. 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 ======== ======== ======== 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. 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. 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. 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. 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). 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: (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. 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 --------- ---------- 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: 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. 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. 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 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. 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: 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. 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: 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 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 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 =========== ========== ========== 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) ======== ======== ======= 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) 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. EX-99.4 7 0007.txt EXHIBIT 99.4 PROVIDENCE ENERGY CORPORATION AND SUBSIDIARIES - ---------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME - --------------------------------- FOR THE PERIODS ENDED MARCH 31 - ------------------------------ (Unaudited) - --------- THREE MONTHS SIX MONTHS - -------------------- -------------------- 2000 1999 2000 1999 - -------------------- -------------------- (thousands, except per share amounts) Energy revenues $ 110,586 $ 93,713 $ 181,367 $ 158,435 Cost of energy 67,290 51,618 107,901 86,628 - --------- -------- --------- --------- Operating margin 43,296 42,095 73,466 71,807 - --------- -------- --------- --------- Operating expenses: Operation and maintenance 15,734 14,859 28,942 28,359 Depreciation and amortization 4,892 4,373 9,633 8,728 Taxes: State gross earnings 2,489 2,471 4,171 4,152 Local property and other 2,652 2,404 4,881 4,459 - --------- -------- --------- --------- Total operating expenses 25,767 24,107 47,627 45,698 - --------- -------- --------- --------- Operating income 17,529 17,988 25,839 26,109 - --------- -------- --------- --------- Other income (loss): Merger related expenses (992) - (2,076) - Other 335 169 667 189 - --------- -------- --------- --------- Total other income (loss) (657) 169 (1,409) 189 - --------- -------- --------- --------- Income before interest expense and preferred dividends of subsidiary 16,872 18,157 24,430 26,298 - --------- -------- --------- --------- Interest expense: Long-term debt 1,752 1,692 3,520 3,244 Other 1,083 667 1,913 1,183 Interest capitalized (60) (94) (119) (170) - --------- -------- --------- --------- 2,775 2,265 5,314 4,257 - --------- -------- --------- --------- Income before Federal income taxes 14,097 15,892 19,116 22,041 Provision for Federal income taxes 5,114 5,414 6,849 7,492 - --------- -------- --------- --------- Income before preferred dividends of subsidiary 8,983 10,478 12,267 14,549 Preferred dividends of subsidiary 75 105 145 209 - --------- -------- --------- --------- Net income $ 8,908 $ 10,373 $ 12,122 $ 14,340 ========= ======== ========= =========.Page 4 [[1]]FINEDG:[62335.TX]00001.PIP EDGAR only EDG: 9-MAY-2000 00:29 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 859 V3.0 Net income per common share - basic $ 1.45 $ 1.73 1.98 $ 2.40 ========= ======== ========= ========= Net income per common share - diluted $ 1.43 $ 1.73 $ 1.96 $ 2.39 ========= ======== ========= ========= Weighted average number of shares outstanding: Basic 6,144.6 5,996.5 6,131.7 5,985.3 ========= ======== ======== ======== Diluted 6,209.3 6,006.9 6,192.7 5,996.0 ========= ======== ======== ======== The accompanying notes are an integral part of these consolidated financial statements. I-1. [[1]]FINEDG:[62335.TX]00002.PIP EDGAR only EDG: 9-MAY-2000 01:01 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 960 V3.0 PART I. FINANCIAL INFORMATION - ------ --------------------- ITEM 1. FINANCIAL STATEMENTS - ----------------------------- PROVIDENCE ENERGY CORPORATION AND SUBSIDIARIES - ---------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME - --------------------------------- FOR THE PERIODS ENDED MARCH 31 - ------------------------------ (Unaudited) - --------- TWELVE MONTHS - ------------- 2000 1999 - ------------- (thousands, except per share amounts) Energy revenues $ 247,961 $ 224,809 Cost of energy 140,316 120,557 - --------- --------- Operating margin 107,645 104,252 - --------- --------- Operating expenses: Operation and maintenance 53,630 54,549 Depreciation and amortization 18,401 15,844 Taxes: State gross earnings 5,692 5,769 Local property and other 9,302 8,550 - --------- --------- Total operating expenses 87,025 84,712 - --------- --------- Operating income 20,620 19,540 - --------- --------- Other income (loss): Merger related expenses (2,076) - Other 1,601 (104) - --------- --------- Total other income (loss) (475) (104) - --------- --------- Income before interest expense and preferred dividends of subsidiary 20,145 19,436 - --------- --------- Interest expense: Long-term debt 7,103 6,663 Other 2,992 1,940 Interest capitalized (338) (270) - --------- --------- 9,757 8,333 - --------- --------- Income before Federal income taxes 10,388 11,103 Provision for Federal income taxes 3,897 3,841 - --------- --------- Income before preferred dividend of subsidiary 6,491 7,262 Preferred dividends of subsidiary 284 418 - --------- --------- Net income $ 6,207 $ 6,844 ========= =========.Page 6 [[1]]FINEDG:[62335.TX]00002.PIP EDGAR only EDG: 9-MAY-2000 01:01 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 960 V3.0 Net income per common share - basic $ 1.02 $ 1.15 ========= ========= Net income per common share - diluted $ 1.01 $ 1.15 ========= ========= Weighted average number of shares outstanding: Basic 6,088.9 5,966.4 ========= ========= Diluted 6,132.5 5,976.6 ========= ========= The accompanying notes are an integral part of these consolidated financial statements. I-1 (a). [[1]]FINEDG:[62335.TX]00003.PIP EDGAR only EDG: 8-MAY-2000 19:07 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG PROVIDENCE ENERGY CORPORATION AND SUBSIDIARIES - ---------------------------------------------- CONSOLIDATED BALANCE SHEETS - --------------------------- (thousands) (Unaudited) - ------------- March 31, March 31, September 30, 2000 1999 1999 - ---------------------------------------- ASSETS - ------ Current assets: Cash and temporary cash investments $ 4,067 $ 6,364 $ 2,804 Accounts receivable, less allowance of $6,580 at 3/31/00, $4,885 at 3/31/99 and $2,883 at 9/30/99 55,046 45,401 13,684 Unbilled revenues 10,981 8,055 2,821 Inventories, at average cost - Fuel oil and underground gas storage 484 403 558 Materials and supplies 1,358 1,428 1,283 Prepaid and refundable taxes 2,875 2,026 4,215 Prepayments 1,100 1,782 2,214 - -------- -------- -------- 75,911 65,459 27,579 - -------- -------- -------- Gas plant, at original cost 347,969 340,048 345,671 Less - Accumulated depreciation and plant acquisition adjustments 128,546 133,610 127,481 - -------- -------- -------- 219,423 206,438 218,190 - -------- -------- -------- Other assets: Other property, net 3,669 2,517 2,628 Investments 13,568 5,021 11,186 Deferred environmental costs 10,996 5,881 9,719 Deferred charges and other assets 31,144 20,244 28,731 - -------- -------- -------- 59,377 33,663 52,264 - -------- -------- -------- Total assets $354,711 $305,560 $298,033 ======== ======== ======== CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization (See accompanying statement) $191,690 $196,291 $187,628 - -------- -------- -------- Current liabilities: Notes payable 64,596 17,146 38,250 Current portion of long-term debt 3,384 3,313 3,515 Accounts payable 32,031 33,119 12,199 Accrued compensation 1,295 1,558 1,634 Accrued environmental costs 4,165 3,400 6,145 Accrued interest 1,755 1,584 1,647 Accrued taxes 10,651 8,325 3,557 Accrued vacation 2,177 1,992 1,807 Accrued workers compensation 707 596 595 Customer deposits 3,150 3,010 2,973 Other 4,044 3,324 4,352 - -------- -------- -------- 127,955 77,367 76,674 - -------- -------- -------- Deferred credits and reserves: Accumulated deferred Federal income taxes 24,440 23,380 24,151 Unamortized investment tax credits 1,980 2,138 2,059.Page 8 [[1]]FINEDG:[62335.TX]00003.PIP EDGAR only EDG: 8-MAY-2000 19:07 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG Accrued pension 7,190 5,946 6,982 Other 1,456 438 539 - -------- -------- -------- 35,066 31,902 33,731 - -------- -------- -------- Commitments and contingencies Total capitalization and liabilities $354,711 $305,560 $298,033 ======== ======== ======== The accompanying notes are an integral part of these consolidated financial statements. I-2. [[1]]FINEDG:[62335.TX]00004.PIP EDGAR only EDG: 8-MAY-2000 19:07 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG PROVIDENCE ENERGY CORPORATION AND SUBSIDIARIES - ---------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOWS - ------------------------------------- FOR THE SIX MONTHS ENDED MARCH 31 - --------------------------------- (Unaudited) - --------- 2000 1999 - -------------------- (thousands) Cash provided by Operating Activities: Income after interest expense $ 12,267 $ 14,549 Items not requiring cash: Depreciation and amortization 9,633 8,728 Change as a result of regulatory actions (344) - Gain on sale of financial instruments (242) (357) Deferred Federal income taxes 279 1,077 Amortization of investment tax credits (79) (79) Changes in assets and liabilities which provided (used) cash: Accounts receivable (41,004) (31,334) Unbilled revenues (8,160) (6,390) Inventories 163 258 Prepaid and refundable taxes 1,340 3,367 Prepayments 1,114 71 Accounts payable 19,874 23,794 Accrued compensation (339) 221 Accrued interest 108 103 Accrued taxes 7,119 5,504 Accrued vacation, accrued workers compensation, customer deposits and other 678 (463) Accrued pension 208 134 Deferred charges and other 738 (128) - -------- -------- Net cash provided by operating activities 3,353 19,055 - -------- -------- Investing Activities: Expenditures for property, plant and equipment, net (13,525) (17,709) Expenditures for business acquisitions (4,170) - Investment in joint venture (2,464) (3,032) Proceeds from sale of financial instruments, net 286 426 - -------- -------- Net cash used in investing activities (19,873) (20,315) - -------- -------- Financing Activities: Proceeds from exercise of stock options 29 14 Issuance of mortgage bonds - 15,000 Redemption of preferred stock (3,200) (1,600) Payments on long-term debt (2,309) (2,129) Increase (decrease) in notes payable, net 26,146 (2,933) Cash dividends on preferred shares (145) (209) Cash dividends on common shares (2,738) (2,525) - -------- -------- Net cash provided by financing activities 17,783 5,618 - -------- -------- Increase in cash and temporary cash investments 1,263 4,358 Cash and temporary cash investments at beginning of period 2,804 2,006 - -------- -------- Cash and temporary cash investments at end $ 4,067 $ 6,364 ======== ======== of period Supplemental disclosure of cash flow information: Cash paid during period for: Interest (net of amount capitalized) $ 5,061 $ 4,085.Page 10 [[1]]FINEDG:[62335.TX]00004.PIP EDGAR only EDG: 8-MAY-2000 19:07 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG Income taxes (net of refunds) $ 2,312 $ 511 Schedule of non-cash investing activities: Capital lease obligations for equipment $ - $ 115 The accompanying notes are an integral part of these consolidated financial statements. I-3.Page 11 [[1]]FINEDG:[62335.TX]00005.PIP EDGAR only EDG: 8-MAY-2000 19:07 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG PROVIDENCE ENERGY CORPORATION AND SUBSIDIARIES - ---------------------------------------------- CONSOLIDATED STATEMENTS OF CAPITALIZATION - ----------------------------------------- (thousands) (Unaudited) - -------------- March 31, March 31, September 30, 2000 1999 1999 - ------------------------------------------ Common stockholders' investment: Common stock, $1 par Authorized - 20,000 shares Outstanding - 6,148 at 3/31/00, 6,007 at 3/31/99 and 6,102 at 9/30/99 $ 6,148 $ 6,007 $ 6,102 Amount paid in excess of par 63,264 59,873 61,966 Retained earnings 33,818 34,180 25,000 - -------- -------- -------- 103,230 100,060 93,068 Accumulated other comprehensive earnings (loss): Unrealized gain (loss) on financial instruments 8 (30) 39 - -------- -------- -------- Total common equity 103,238 100,030 93,107 - -------- -------- -------- Cumulative preferred stock of subsidiary: Redeemable 8.7% Series, $100 par Authorized - 80 shares Outstanding - 0 shares as of 3/31/00 and 32 shares as of 3/31/99 and 9/30/99 - 3,200 3,200 - -------- -------- -------- Long-term debt: First Mortgage Bonds 88,219 90,728 89,819 Other long-term debt 3,323 4,597 4,461 Capital leases 294 1,049 556 - -------- -------- -------- Total long-term debt 91,836 96,374 94,836 Less current portion 3,384 3,313 3,515 - -------- -------- -------- Long-term debt, net 88,452 93,061 91,321 - -------- -------- -------- Total capitalization $191,690 $196,291 $187,628 ======== ======== ======== The accompanying notes are an integral part of these consolidated financial statements. I-4. [[1]]FINEDG:[62335.TX]00006.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG PROVIDENCE ENERGY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements 1. Accounting Policies - ------------------- It is the Registrant's opinion that the financial information contained in this report reflects all normal, recurring adjustments necessary to a fair statement of the results for the periods reported; however, such results are not necessarily indicative of results to be expected for the year, due to the seasonal nature of the Registrant's operations. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, the disclosures herein when read with the annual report for 1999 filed on Form 10-K are adequate to make the information presented not misleading. 2. Reclassifications - ----------------- Certain prior period amounts have been reclassified for consistent presentation with the current period. 3. Rates and Regulation - -------------------- The Providence Gas Company (ProvGas), a wholly owned subsidiary of the Registrant, is subject to the regulatory jurisdiction of the Rhode Island Public Utilities Commission (RIPUC) with respect to rates and charges, standards of service, accounting and other matters. In August 1997, the RIPUC approved the Price Stabilization Plan Settlement Agreement (Energize RI or the Plan) among ProvGas, the Rhode Island Division of Public Utilities and Carriers (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 Gas Charge Clause (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 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. I-5. [[1]]FINEDG:[62335.TX]00007.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG 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 for the recovery of $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 has a remaining deferred balance as of March 31, 2000 of approximately $.1 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 those experienced in 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 this year, the final year of Energize RI, is substantially impaired. As Energize RI is due to expire on September 30, 2000, several alternatives are available to ProvGas to address the expiration of this program including the possible extension or replication of Energize RI or filing a rate case. On January 31, 2000, ProvGas filed for a two-month extension of Energize RI to allow time for ProvGas to discuss its options with the appropriate parties. At an open meeting on February 22, 2000 the two-month extension was approved. On April 7, 2000 ProvGas filed for an additional two-month extension, which was subsequently approved at the April 13, 2000 open meeting. 4. Gas Supply - ---------- As part of the Price Stabilization Plan Settlement Agreement described above in Rates and Regulations, ProvGas entered into a full requirements gas - --------------------- supply contract with Duke Energy Trading and Marketing, L.L.C. (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 liquified natural gas (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 Firm Transportation (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. I-6. [[1]]FINEDG:[62335.TX]00008.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG 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. ProvGas may realize demand cost reductions by terminating higher-priced contracts. 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 LNG service contract with Algonquin Gas Transmission Company (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 began November 10, 1999. Under the terms of the agreement, Algonquin replaced and expanded the vaporization capability at the tank. ProvGas has received 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 was received in January 2000, and serves as reimbursement for the additional costs that DETM will incur as a result of the release of the Algonquin storage capacity to DETM as provided for in the gas supply asset management contract described above. In June 1999, the Federal Energy Regulatory Commission (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 and ProvGas' parallel filing, PR99-8, requesting regulatory authorization to charge Algonquin for displacement of gas for other Algonquin 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, ProvGas will assume any remaining liability, which is not expected to be material. 5. 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 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 March 31, 2000, the Registrant was aware of five sites at which future costs may be incurred. Plympton Sites (2) - ------------------ ProvGas has been designated as a potentially responsible party (PRP) under the Comprehensive Environmental Response Compensation and Liability Act of 1980 at two C. M. Brackett sites in Plympton, Massachusetts. Disposal contractors employed in the past, either directly or indirectly by ProvGas and other PRPs, allegedly deposited waste materials at the C. M. Brackett sites. With respect to one of the sites, ProvGas has joined with other PRPs in entering into an Administrative Consent Order with the Massachusetts Department of Environmental Protection. The same group is currently negotiating a similar agreement for the second site. The costs to be borne by ProvGas in connection with both Plympton sites are not anticipated to be material to the financial condition of ProvGas. I-7. [[1]]FINEDG:[62335.TX]00008.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG.Page 16 [[1]]FINEDG:[62335.TX]00009.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG Providence Site - --------------- During 1995, ProvGas began a study at its primary gas distribution facility located at 642 Allens Avenue in Providence, Rhode Island. This site formerly contained a manufactured gas plant operated by ProvGas. As of March 31, 2000, approximately $3.0 million had been spent primarily on studies and the formulation of remediation work plans under Rhode Island Department of Environmental Management (DEM) supervision. ProvGas has completed the initial investigation to determine the extent of environmental contamination for the most contaminated portions of the property. ProvGas has compiled a preliminary range of costs, based on removal and off-site disposal of the most contaminated soil, ranging from $7.0 million to in excess of $9.0 million. As of March 31, 2000, approximately $3.7 million had been spent on the remediation of this soil. The remediation of the most contaminated portions of the property is scheduled to be completed approximately six months after DEM issues the final air quality permit for the project. An investigation of the remaining soil was begun in December 1999 and was completed in March 2000. The total cost of this soil characterization was approximately $1.5 million. In addition, as of March 31, 2000 ProvGas has not begun its groundwater investigation at this site. The results of the additional investigation will be included in the determination of the final remedial solution. Because of the uncertainties associated with the pending investigation and remedial solutions, ProvGas can not offer any conclusions as to the total future cost of remediation of the property at this time. Based on the proposals for remediation work, ProvGas has an accrual balance of $4.2 million at March 31, 2000 for anticipated future remediation and investigation costs at this site. Westerly Site - ------------- ProvGas acquired the Westerly, Rhode Island operations center in 1990 from another company. In 1996 an environmental investigation revealed the existence of coal tar waste on the site. ProvGas never operated a manufactured gas plant at this location, but the previous owner did. The former manufactured gas plant is allegedly the source of the coal tar waste. In February 1999, DEM issued ProvGas and the previous owner a letter of responsibility for the site. As of March 31, 2000, ProvGas had removed an underground oil storage tank and regulators containing mercury from the site, as well as some localized contamination. The costs associated with the investigation and removal of localized contamination were shared equally with the former owner of the property. ProvGas is currently engaged in negotiations to transfer the property back to the previous owner, who would continue to remediate the site at no cost to ProvGas. The purchase and sale agreement is anticipated to be signed during the current fiscal year, at which time the previous owner will assume responsibility for removal of coal tar waste. ProvGas has completed the required cleanup related to any mercury-containing regulators and remains responsible for cleanup of any mercury released into adjacent water. Costs incurred by ProvGas to remediate this site were approximately $.1 million. I-8. [[1]]FINEDG:[62335.TX]00010.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG Allens Avenue Site - ------------------ In November 1998, ProvGas received a letter of responsibility from DEM relating to possible contamination on previously owned property at 170 Allens Avenue in Providence. The current operator of the property has also received a letter of responsibility. A work plan has been created and approved by DEM. An investigation has begun to determine the extent of contamination as well as the extent of ProvGas' responsibility. ProvGas has entered into a cost-sharing agreement with the current operator of the property, under which ProvGas is responsible for approximately 20 percent of the costs related to the investigation. Costs of testing at this site as of March 31, 2000 were approximately $.3 million. Until the results of the investigation are known, ProvGas 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 Rates and Regulations, 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 March 31, 2000, ProvGas has incurred environmental assessment and remediation costs of $8.3 million and has an accrual balance of $4.2 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. 6. Net Income per Common Share - --------------------------- A reconciliation of the weighted average number of shares outstanding used in the computation of the basic and diluted earnings per share for each of the periods ended March 31 is as follows: Three Months Six Months Twelve Months 2000 1999 2000 1999 2000 1999 - ---- ---- ---- ---- ---- ---- Weighted average shares 6,144.6 5,996.5 6,131.7 5,985.3 6,088.9 5,966.4 Effect of dilutive stock options 64.7 10.4 61.0 10.7 43.6 10.2 - ------- ------- ------- ------- ------- ------- Weighted average shares diluted 6,209.3 6,006.9 6,192.7 5,996.0 6,132.5 5,976.6 ======= ======= ======= ======= ======= ======= The net income used in the calculation for basic and diluted earnings per share agrees with the net income appearing in the consolidated financial statements. I-9. [[1]]FINEDG:[62335.TX]00011.PIP EDGAR only EDG: 8-MAY-2000 20:35 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 WP2EDG 7. Comprehensive Income - -------------------- Effective October 1, 1998, the Registrant adopted the provisions of Statement of Financial Accounting Standards (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. The following is a summary of the reclassification adjustments and the income tax effects for the components of other comprehensive loss for the six months ended March 31: Unrealized Holding Reclassification Gains on Adjustments for Investments Gains Other Arising During Included in Comprehensive (thousands of dollars) the Period Net Income Loss - ------------------------ ---------- ---------- ---- 2000 Pretax income $ 11 $ (58) $ (47) Income tax expense 4 (20) (16) - ---------- ---------- ------ Net change $ 7 $ (38) $ (31) ========== ========== ====== 8. Commitments and Contingencies - ----------------------------- The Registrant has employment agreements with 11 officers. Upon a change in control of the Registrant, potential severance expense will substantially increase. The Registrant's salary severance expense could total approximately $5.0 million. I-10. [[1]]FINEDG:[62335.TX]00012.PIP EDGAR only EDG: 10-MAY-2000 12:16 BLK: 00-000-0000 00:00 [[1]]PROVIDENCE ENERGY FORM 10-Q R.R. Donnelley (617) 345-4345 72119 V3.0 EX-99.5 8 0008.txt EXHIBIT 99.5 PART I. FINANCIAL INFORMATION PENNSYLVANIA ENTERPRISES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended September 30, September 30, - ------------------------------ ------------------------------ 1999 1998 1999 1998 - ------------------------------ --------------- -------------- (Thousands of Dollars) OPERATING REVENUES: Energy products and services - Regulated .................................. $ 16,115 $ 15,177 $ 128,517 $ 105,187 Nonregulated ............................... 15,738 8,112 48,959 25,254 Pipeline construction and services ............ 3,391 3,611 8,727 9,219 - -------- -------- -------- ------- Total operating revenues ................ 35,244 26,900 186,203 139,660 - -------- -------- -------- ------- OPERATING EXPENSES: Cost of gas and other energy ................... 19,571 13,105 111,795 77,752 Operation and maintenance ...................... 13,610 11,681 38,455 34,038 Depreciation ................................... 2,895 2,691 8,611 7,902 Income taxes ................................... (2,301) (2,098) 3,783 1,365 Taxes other than income taxes .................. 1,948 1,780 9,911 8,757 - -------- -------- -------- ------- Total operating expenses .................... 35,723 27,159 172,555 129,814 - -------- -------- -------- ------- OPERATING INCOME (LOSS) ............................ (479) (259) 13,648 9,846 OTHER INCOME (DEDUCTIONS), NET ..................... (80) 635 (60) 1,570 - -------- -------- -------- ------- INCOME (LOSS) BEFORE INTEREST CHARGES .............. (559) 376 13,588 11,416 - -------- -------- -------- ------- INTEREST CHARGES: Interest on long-term debt ..................... 2,644 2,668 7,762 7,701 Other interest ................................. 155 138 555 407 Allowance for borrowed funds used during construction ........................... (10) (38) (42) (90) - -------- ------- ------- ------- Total interest charges .................. 2,789 2,768 8,275 8,018 - -------- ------- ------- ------- INCOME (LOSS) BEFORE SUBSIDIARY'S PREFERRED STOCK DIVIDENDS ............................... (3,348) (2,392) 5,313 3,398 SUBSIDIARY'S PREFERRED STOCK DIVIDENDS ............. 52 319 156 961 - -------- ------- ------- ------- NET INCOME (LOSS) .................................. $ (3,400) $ (2,711) $ 5,157 $ 2,437 ========= ======= ======= ======= EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Basic ......................................... $ (0.31) $ (0.27) $ 0.48 $ 0.25 ========= ======== ======== ======= Diluted ....................................... $ (0.31) $ (0.27) $ 0.47 $ 0.24 ========= ======== ======== ======= WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING Basic ......................................... 10,856,815 10,062,702 10,759,034 9,906,282 =========== ========== ========== ========= Diluted ....................................... 11,004,036 10,141,608 10,861,501 9,989,804 =========== ========== ========== ========= CASH DIVIDENDS PER SHARE ........................... $ 0.30 $ 0.30 $ 0.90 $ 0.90 =========== ========== ========== =========
The accompanying notes are an integral part of the consolidated financial statements. PENNSYLVANIA ENTERPRISES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
September 30, December 31, 1999 1998 ------------------- -------------- (Thousands of Dollars) ASSETS UTILITY PLANT: At original cost ........................................... $ 389,666 $ 376,685 Accumulated depreciation ................................... (102,467) (95,735) ---------------- ---------------- 287,199 280,950 ---------------- ----------------- OTHER PROPERTY AND INVESTMENTS: Nonutility property and equipment .......................... 36,725 31,816 Accumulated depreciation ................................... (6,200) (5,460) Other ...................................................... 2,411 2,296 ---------------- ----------------- 32,936 28,652 ---------------- ----------------- CURRENT ASSETS: Cash and cash equivalents .................................. 846 807 Restricted cash - common stock subscribed (Note 3).......... - 452 Accounts receivable - Customers ............................................... 20,485 26,259 Others .................................................. 756 811 Reserve for uncollectible accounts ...................... (1,901) (1,465) Unbilled revenues .......................................... 3,520 12,247 Materials and supplies, at average cost .................... 3,322 3,053 Gas held by suppliers, at average cost ..................... 26,519 22,676 Deferred cost of gas and supplier refunds, net ............. - 6,058 Prepaid income taxes ....................................... 1,903 2,090 Prepaid expenses and other ................................. 4,733 2,713 ---------------- ----------------- 60,183 75,701 ---------------- ----------------- DEFERRED CHARGES: Regulatory assets - Deferred taxes collectible .............................. 31,558 31,097 Other ................................................... 8,144 8,598 Unamortized debt expense ................................... 842 1,014 Other ...................................................... 94 190 ---------------- ----------------- 40,638 40,899 ---------------- ----------------- TOTAL ASSETS ................................................... $ 420,956 $ 426,202 ================ =================
The accompanying notes are an integral part of the consolidated financial statements. PENNSYLVANIA ENTERPRISES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
September 30, December 31, 1999 1998 ----------------- ------------------ (Thousands of Dollars) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common shareholders' investment (Note 3) ................................. $137,832 $132,326 Preferred stock of PG Energy - Not subject to mandatory redemption ................................... - 4,831 Subject to mandatory redemption ....................................... - 240 Long-term debt ........................................................... 95,000 98,000 ---------------- ---------------- 232,832 235,397 ---------------- ---------------- CURRENT LIABILITIES: Current portion of long-term debt ........................................ 51,007 81,348 Preferred stock of PG Energy called for redemption ................................................. 4,985 - Notes payable ............................................................ 26,590 6,200 Accounts payable ......................................................... 17,664 22,370 Deferred cost of gas and supplier refunds, net ........................... 4,846 - Accrued general business and realty taxes ................................ 1,511 1,764 Accrued interest ......................................................... 1,264 1,811 Other .................................................................... 1,799 1,924 ---------------- ---------------- 109,666 115,417 ---------------- ---------------- DEFERRED CREDITS: Deferred income taxes .................................................... 63,352 60,923 Unamortized investment tax credits ....................................... 4,294 4,424 Operating reserves ....................................................... 3,189 2,836 Other .................................................................... 7,623 7,205 ---------------- ---------------- 78,458 75,388 ---------------- ---------------- COMMITMENTS AND CONTINGENCIES (Note 6) TOTAL CAPITALIZATION AND LIABILITIES ......................................... $420,956 $426,202
The accompanying notes are an integral part of the consolidated financial statements. PENNSYLVANIA ENTERPRISES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended September 30, ----------------------------- 1999 1998 ------------ ----------- (Thousands of Dollars) CASH FLOW FROM OPERATING ACTIVITIES: Net income ............................................................... $ 5,157 $ 2,437 Gain on sales of other property .......................................... (143) (2,275) Effects of noncash charges to income - Depreciation ......................................................... 8,697 7,970 Deferred income taxes, net ........................................... 1,967 2,336 Provisions for self insurance ........................................ 1,118 560 Other, net ........................................................... 2,407 1,576 Changes in working capital, exclusive of cash and current portion of long-term debt - Receivables and unbilled revenues ............................... 14,988 22,777 Gas held by suppliers ........................................... (3,843) (4,549) Accounts payable ................................................ (3,851) (373) Deferred cost of gas and supplier refunds, net .................. 10,904 (6,030) Other current assets and liabilities, net ....................... (3,027) (8,624) Other operating items, net ............................................... (1,577) (1,954) ------- ------- Net cash provided by operating activities ...................... 32,797 13,851 ------- ------- CASH FLOW FROM INVESTING ACTIVITIES: Additions to utility plant ............................................... (15,323) (19,955) Additions to nonutility property ......................................... (4,621) (13,179) Proceeds from the sales of other property ................................ 211 2,855 Other, net ............................................................... 93 55 ------- ------- Net cash used for investing activities .......................... (19,640) (30,224) ------- ------- CASH FLOW FROM FINANCING ACTIVITIES: Issuance of common stock ................................................. 10,485 9,049 Common stock subscribed, net ............................................. - 487 Repurchase of subsidiary's preferred stock ............................... (86) (128) Dividends on common stock ................................................ (9,708) (8,926) Repayment of long-term debt .............................................. (33,000) - Net increase in bank borrowings .......................................... 19,194 14,110 Other, net ............................................................... (3) 11 ------- ------ Net cash (used for)/provided by financing activities ............ (13,118) 14,603 ------- ------ NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ........................... 39 (1,770) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ............................... 807 2,202 ------ ------ CASH AND CASH EQUIVALENTS AT END OF PERIOD ..................................... $ 846 $ 432 ====== ====== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the period for: Interest (net of amount capitalized) .................................. $ 8,665 $ 8,178 ======== ====== Income taxes .......................................................... $ 1,725 $ 2,679 ======== ======
PENNSYLVANIA ENTERPRISES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of the Business. Pennsylvania Enterprises, Inc. (the "Company") is a holding company which, through its subsidiaries, is engaged in both regulated and nonregulated activities. The Company's regulated activities are conducted by its principal subsidiary, PG Energy Inc. ("PG Energy"), a regulated public utility, and PG Energy's wholly-owned subsidiary, Honesdale Gas Company ("Honesdale"), also a regulated public utility. Together PG Energy and Honesdale distribute natural gas to a thirteen-county area in northeastern Pennsylvania, a territory that includes the cities of Scranton, Wilkes-Barre and Williamsport. In 1998, PG Energy and Honesdale collectively accounted for approximately 77% of the Company's operating revenues. The Company, through its other subsidiaries, PG Energy Services Inc. ("Energy Services"), PEI Power Corporation ("Power Corp"), Theta Land Corporation ("Theta") and Keystone Pipeline Services, Inc. ("Keystone"), a wholly-owned subsidiary of Energy Services, is engaged in various nonregulated activities. These activities include the sale of natural gas, propane, electricity and other energy-related products and services; the construction, maintenance and rehabilitation of utility facilities, primarily natural gas distribution pipelines; and the sale of property for residential, commercial and other development. Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its subsidiaries, PG Energy (including Honesdale), Energy Services (including Keystone), Power Corp and Theta. All material intercompany accounts have been eliminated in consolidation. Both PG Energy and Honesdale (collectively referred to as the "Regulated Subsidiaries") are subject to the jurisdiction of the Pennsylvania Public Utility Commission (the "PPUC") for rate and accounting purposes. The financial information of the Regulated Subsidiaries that is incorporated in these consolidated financial statements has been prepared in accordance with generally accepted accounting principles, including the provisions of Financial Accounting Standards Board ("FASB") Statement 71, "Accounting for the Effects of Certain Types of Regulation," which give recognition to the rate and accounting practices of regulatory agencies such as the PPUC. Interim Financial Statements. The interim consolidated financial statements included herein have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. The results for the interim periods are not indicative of the results to be expected for the year, primarily due to the effect of seasonal variations in weather on the sale of natural gas. However, in the opinion of management, all adjustments, consisting of only normal recurring accruals, necessary to present fairly the results for the interim periods have been reflected in the consolidated financial statements. It is suggested that these consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company's latest annual report on Form 10-K. Use of Accounting Estimates. 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. These estimates involve judgments with respect to, among other things, various future economic factors and regulatory matters which are difficult to predict and are beyond the control of the Company. Therefore, actual amounts could differ from these estimates. (2) RATE MATTERS Rate Increase. By Order adopted October 16, 1998, the PPUC approved an overall 4.1% increase in PG Energy's base rates, designed to produce $7.4 million of additional annual revenue, effective October 17, 1998. Gas Cost Adjustments. The provisions of the Pennsylvania Public Utility Code require that the tariffs of local gas distribution companies ("LDCs") be adjusted on an annual basis, and, in the case of larger LDCs such as PG Energy, on an interim basis when circumstances dictate, to reflect changes in their purchased gas costs. The procedure includes a process for the reconciliation of actual gas costs incurred and actual revenues received and also provides for the refund of any overcollections or the recoupment of any undercollections of gas costs, plus interest in either case. In accordance with these procedures PG Energy has been permitted to make the following changes since January 1, 1998, to the gas costs contained in its tariff rates:
Change in Calculated Effective Rate per MCF Increase (Decrease) Date From To in Annual Revenue ---------------- ----------- - ------------- -------------------------- September 1, 1999 ....................... $ 4.15 $ 4.00 $(3,500,000) June 1, 1999 ............................ 4.39 4.15 (5,800,000) March 1, 1999 ........................... 4.53 4.39 (3,200,000) December 1, 1998 ........................ 4.25 4.53 7,100,000 September 1, 1998 ....................... 4.18 4.25 1,900,000 June 1, 1998 ............................ 3.95 4.18 5,800,000 March 1, 1998 ........................... 4.05 3.95 (2,100,000)
The changes in gas rates on account of purchased gas costs have no effect on earnings since the change in revenue is offset by a corresponding change in the cost of gas. (3) RESTRICTED CASH - COMMON STOCK SUBSCRIBED Until its suspension on June 7, 1999, as a result of the proposed merger with Southern Union Company (see Note 7 of these Notes to Consolidated Financial Statements), the Company's Customer Stock Purchase Plan (the "Customer Plan") provided the residential customers of all the Company's subsidiaries with a method of purchasing shares of the Company's common stock without payment of brokerage commission, service charge or other regular expense. On January 1, 1999, the Company issued 19,177 shares of its common stock for an aggregate consideration of $446,000 with respect to payments received pursuant to the Customer Plan during the subscription period ended December 31, 1998. Such payments are reflected under the captions "Restricted cash - common stock subscribed" and "Common shareholders' investment" in the consolidated balance sheet as of December 31, 1998. (4) OPERATING SEGMENTS The Company has three principal operating segments: o Regulated Energy Products and Services, principally the purchase, distribution and sale of natural gas in thirteen counties in northeastern Pennsylvania by the Regulated Subsidiaries ("Energy Products and Services - Regulated") o Nonregulated Energy Products and Services, principally the sale of natural gas, propane, electricity and other energy-related products and services by Energy Services, generally in a twenty-six county area in northeastern and central Pennsylvania, and the generation and sale of electricity and steam by Power Corp. ("Energy Products and Services - Nonregulated") o Pipeline Construction and Services, principally the construction, maintenance and rehabilitation of utility facilities throughout the eastern United States by Keystone ("Pipeline Construction and Services"). Information regarding the operating segments for the three and nine-month periods ended September 30, 1999 and 1998, is as follows:
Three Months Ended Nine Months Ended September 30, September 30, - ------------------------------- ------------------------------- 1999 1998 1999 1998 - --------------- --------------- --------------- --------------- (Thousands of Dollars) Operating revenues: Energy products and services - Regulated ......................................... $ 16,165 $ 15,223 $ 128,628 $ 105,381 Nonregulated ...................................... 16,450 8,759 50,479 25,902 Pipeline construction and services ................. 3,391 3,611 8,727 9,219 Intercompany eliminations .......................... (762) (693) (1,631) (842) - ------------ ------------ ----------- ------------ Total ........................................... $ 35,244 $ 26,900 $ 186,203 $ 139,660 ============ ============ ============ ============ Operating income (loss): Energy products and services - Regulated ......................................... $ (170) $ (468) $ 14,398 $ 9,394 Nonregulated ...................................... 53 (19) 592 506 Pipeline construction and services ................. (73) 195 (304) 177 Intercompany eliminations and Corporate expenses ................................ (289) 33 (1,038) (231) - ----------- ------------ ------------ ------------ Total ........................................... $ (479) $ (259) $ 13,648 $ 9,846 =========== ============ ============ ============
(5) ACCOUNTING CHANGES Accounting for Derivative Instruments and Hedging Activities. In June 1998, FASB Statement 133, "Accounting for Derivative Instruments and Hedging Activities" was issued. The provisions of this statement, as amended which are effective for fiscal quarters beginning after June 15, 2000, establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. While the Company generally has not used derivative instruments, it expects to adopt, to the extent necessary, the provisions of FASB Statement 133 in the third quarter of 2000. The impact of such adoption on the Company's future financial condition and results of operations will depend upon a number of factors, including the extent to which the Company may use derivative instruments, and the designation and effectiveness of such derivative hedging market risk. (6) COMMITMENTS AND CONTINGENCIES Environmental Matters. PG Energy, like many gas distribution companies, once utilized manufactured gas plants in connection with providing gas service to its customers. None of these plants has been in operation since 1972, and several of the plant sites are no longer owned by PG Energy. Pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"), PG Energy filed notices with the United States Environmental Protection Agency (the "EPA") with respect to the former plant sites. None of the sites is or was formerly on the proposed or final National Priorities List. The EPA has conducted site inspections and made preliminary assessments of each site and has concluded that no further remedial action is planned. The conclusion by the EPA that it anticipates no further remedial action with respect to the sites at which PG Energy operated manufactured gas plants does not, however, constitute a legal prohibition against further regulatory action under CERCLA or other applicable federal or state law, and even in the absence of any further action by the EPA, some of the sites may ultimately require remediation. In any event, the Company does not believe that additional costs, if any, related to these manufactured gas plant sites would be material to its financial position or results of operations since environmental remediation costs generally are recoverable through rates over a period of time. (7) PROPOSED MERGER On June 7, 1999, the Company's Board of Directors approved a definitive merger agreement with Southern Union Company ("Southern Union"), an international energy company headquartered in Austin, Texas. In accordance with the terms of the merger agreement, the Company will merge with and into Southern Union and Southern Union will be the surviving company. On the same day, following the merger of the Company and Southern Union, Honesdale will be merged with and into PG Energy and immediately thereafter PG Energy will be merged into Southern Union. The merger agreement is subject to the approval of the shareholders of both the Company and Southern Union, which was obtained at meetings of the shareholders of the respective companies held on October 19, 1999, as well as various regulatory approvals, all of which are expected to be obtained by November 1, 1999, and other customary conditions. In connection with the merger, Southern Union and the Company are soliciting consents from the holders of PG Energy's First Mortgage Bonds and Senior Notes to proposed amendments to certain of the covenants of the Company regarding such debt. If the required consents are obtained, the proposed amendments will become effective immediately following the merger of PG Energy into Southern Union. The merger agreement with Southern Union provides for each outstanding share of the Company's common stock to be exchanged for $32.00 in Southern Union common stock and $3.00 in cash, subject to adjustment for market fluctuations in the price of Southern Union common stock. Although there can be no certainty, the Company currently anticipates that the merger with Southern Union will be consummated by the end of 1999. -----END PRIVACY-ENHANCED MESSAGE-----