-----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, EHuZulIdwbgZNqiD59tZZrEfn2d4FtLPaCUQVGG/arvkkd5w/xvUo69h5Q9DdF7Y bHKlloX8yRZV2TIcrb8qxA== 0000009548-99-000014.txt : 19991117 0000009548-99-000014.hdr.sgml : 19991117 ACCESSION NUMBER: 0000009548-99-000014 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991115 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BANGOR HYDRO ELECTRIC CO CENTRAL INDEX KEY: 0000009548 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 010024370 STATE OF INCORPORATION: ME FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-10922 FILM NUMBER: 99751871 BUSINESS ADDRESS: STREET 1: 33 STATE ST CITY: BANGOR STATE: ME ZIP: 04401 BUSINESS PHONE: 2079455621 MAIL ADDRESS: STREET 1: PO BOX 932 CITY: BANGOR STATE: ME ZIP: 04401 10-Q 1 BANGOR HYDRO 3RD QTR 1999 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR SECTION 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarter ended SEPTEMBER 30, 1999 Commission File No. 0-505 ------------------ ----- BANGOR HYDRO-ELECTRIC COMPANY ------------------------------------------ (Exact Name of Registrant as specified in its Charter MAINE 01-0024370 - ------------------------------- ------------------ (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 33 STATE STREET, BANGOR, MAINE 04401 - ---------------------------------------- -------- (Address of Principal Executive Offices) (Zip Code) Registrant's Telephone Number, including Area Code 207-945-5621 ------------ NONE - ---------------------------------------------------------------------- Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report Outstanding Common Stock, $5 Par Value - 7,363,424 Shares September 30, 1999 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- --- FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 1999 PART I - FINANCIAL INFORMATION PAGE Cover Page 1 Index 2 Consolidated Statements of Income 3 Management's Discussion and Analysis of Results of Operations and Financial Condition 4 Consolidated Balance Sheets - September 30, 1999 and December 31, 1998 28 Consolidated Statements of Capitalization 30 Consolidated Statements of Cash Flows 31 Consolidated Statements of Common Stock Investment 32 Notes to the Consolidated Financial Statements 33 PART II - OTHER INFORMATION 44 Item 6 - Exhibits and Reports on Form 8-K 45 Signature Page 46 BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME 000's Omitted Except Per Share Amounts (UNAUDITED)
Three Months Ended Nine Months Ended Sept. 30, Sept. 30, Sept. 30, Sept. 30, 1999 1998 1999 1998 -------- -------- --------- ---------- ELECTRIC OPERATING REVENUES $ 51,452 $ 49,158 $ 148,973 $ 144,859 -------- -------- --------- ---------- OPERATING EXPENSES: Fuel for generation and purchased power $ 23,183 $ 20,610 $ 60,535 $ 62,014 Other operation and maintenance 7,875 8,433 26,104 25,061 Depreciation and amortization 1,697 2,446 6,563 7,500 Amortization of Seabrook Nuclear Unit 424 424 1,274 1,274 Amortization of contract buyouts and restructuring 5,200 5,201 15,601 15,242 Taxes - Property and payroll 1,133 1,289 4,106 4,102 State income 446 363 1,318 775 Federal income 2,163 1,305 5,753 3,388 -------- -------- --------- ---------- $ 42,121 $ 40,071 $ 121,254 $ 119,356 -------- -------- --------- ---------- OPERATING INCOME $ 9,331 $ 9,087 $ 27,719 $ 25,503 -------- -------- --------- ---------- OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction $ (382) $ 131 $ (81) $ 309 Other, net of applicable income taxes 438 113 1,219 582 -------- -------- --------- ---------- $ 56 $ 244 $ 1,138 $ 891 -------- -------- --------- ---------- INCOME BEFORE INTEREST EXPENSE $ 9,387 $ 9,331 $ 28,857 $ 26,394 -------- -------- --------- ---------- INTEREST EXPENSE: Long-term debt $ 4,120 $ 5,861 $ 14,993 $ 17,122 Other 238 729 1,102 2,158 Allowance for borrowed funds used during construction (8) (208) 61 (510) -------- -------- --------- ---------- $ 4,350 $ 6,382 $ 16,156 $ 18,770 -------- -------- --------- ---------- NET INCOME $ 5,037 $ 2,949 $ 12,701 $ 7,624 DIVIDENDS ON PREFERRED STOCK 279 312 836 935 -------- -------- --------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 4,758 $ 2,637 $ 11,865 $ 6,689 ======== ======== ========= ========== WEIGHTED AVERAGE NUMBER OF SHARES 7,363 7,363 7,363 7,363 ======== ======== ========= ========== EARNINGS PER COMMON SHARE, Basic $ .65 $ .36 $ 1.61 $ .91 Diluted .57 .34 1.42 .89 ======== ======== ========= ========== DIVIDENDS DECLARED PER COMMON SHARE $ .15 $ - $ .30 $ - ======== ======== ========= ========== See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Management's Discussion and Analysis of the Results of Operations and Financial Condition contained in Bangor Hydro-Electric Company's (the Company) Annual Report on Form 10-K for the year ended December 31, 1998 (1998 Form 10-K) should be read in conjunction with the comments below. EARNINGS The quarter ended September 30, 1999 resulted in basic earnings per common share of $.65, as compared to $.36 per common share for the quarter ended September 30, 1998. The improvement in third quarter earnings is attributable to an increase in electric sales, a 1.36% increase in rates related to the Company's alternative rate plan (ARP) effective June 1, 1999 (A discussion of this rate increase is included below under "Important Current Activities"), a gain on the sale of a subsidiary as part of the mandatory divestiture of generation assets (A discussion of this sale is included below under "Important Current Activities"), and one-time income tax benefits related to the utilization of investment tax credits and adjustments to the 1998 tax returns filed in September of 1999. The gain on sale of subsidiary and one-time tax benefits resulted in a $.10 increase in basic earnings per common share in the 1999 quarter. IMPORTANT CURRENT ACTIVITIES- SALE OF COMPANY'S GENERATING ASSETS - On May 27, 1999, the Company completed most of the transaction for the sale of its electric generating assets and certain transmission rights to PP&L Global (PP&L). The purchase price for the assets transferred was $79 million. The sale involved all but one of the Company's hydroelectric plants on the Penobscot, Piscataquis, and Union rivers and Bangor Hydro's 8.33% ownership interest in the Wyman Unit #4 oil-fired plant in Yarmouth, Maine--a total base load capacity of 83 megawatts. The sale also involved a transfer by the Company of rights to transmit power over the Maine Electric Power Company (MEPCO) transmission facilities connecting the New England Power Pool (NEPOOL) to New Brunswick Canada; the Company's rights as a participant in the regional utilities' agreement with Hydro-Quebec pursuant to an agency agreement; and the Company's rights to develop a second high voltage transmission line that will connect NEPOOL to New Brunswick, Canada. As discussed in the 1998 Form 10-K, the Company and other Maine utilities were required to sell their generation assets as a result of the comprehensive electric utility industry restructuring law adopted in Maine in 1997. The Company conducted an auction in 1998, which led to the signing of a purchase and sale agreement with PP&L in late September 1998. The purchase and sale agreement also included the Company's 50% interest in the 13 megawatt West Enfield hydro station on the Penobscot River. In late July 1999, the Company received $10 million in proceeds from the transfer of the economic interest in that project, and in late August 1999, the Maine Public Utilities Commission (MPUC) approved the sale to PP&L of Penobscot Hydro Company, Inc. (Penobscot Hydro), the Company's wholly-owned subsidiary which held the 50% interest in the West Enfield hydro station. The Company has utilized a significant portion of the net proceeds of the sale to reduce outstanding debt and preferred stock. The Company realized a net gain on the sale related to the PP&L sale of approximately $23.0 million, and $22.5 million of this amount has been recorded as a deferred liability at September 30, 1999 on the Consolidated Balance Sheets. Included in this deferred amount is the accrual of carrying costs on the deferred gain balance and the net expense associated with the sale of its generating assets and the simultaneous purchased power buyback agreement with PP&L (See below for a discussion of the net expense). The deferred gain will be utilized to reduce electric rates effective March 1, 2000, with the introduction of retail competition. The remaining $.5 million of the gain relates to the portion of the gain on sale of Penobscot Hydro, which is allocable to shareholders (recorded as other income in the Consolidated Statements of Income for the quarter ending September 30, 1999). For a discussion of the restructuring of the electric utility industry in the State of Maine, please see the 1998 Form 10-K. ALTERNATIVE RATE PLAN FILING - In May 1999, the MPUC approved a portion of the Company's February 1999 request for rate adjustment under the so-called ARP. Pursuant to the MPUC Order, the Company implemented an increase in its standard tariff of about 1.36% effective June 1, 1999. An alternative rate plan is a method of utility regulation intended to replace the costly, controversial periodic rate increase proceedings of the past. Under such a plan, utilities are permitted to adjust rates annually based on a formula tied to inflation minus a "productivity factor". Adjustments for certain specified categories of costs that are unrelated to inflation are also permitted. The MPUC implemented this plan for the Company in 1998. The 1999 increase was comprised entirely of the recovery of some of the specified categories of costs that are unrelated to inflation. This was made up mostly of the recovery of a portion (about $1.4 million, or about 25%) of the costs incurred to recover from the 1998 ice storm. The inflation component actually contributed to a reduction of the 1999 adjustment, because the productivity factor offset of 1.2% exceeded the inflation rate of .9%. The ARP will not be in effect with the implementation of new rates on March 1, 2000, and the Company is uncertain if any alternative rate plan will be adopted in the future. Also in connection with the ARP Order, as a result of the sale of the Company's generation assets, the Company was required to defer all savings, for the period from the asset sale through February 29, 2000, associated with the sale of its generating assets and the simultaneous purchased power buyback agreement with PP&L. Any net savings for this period are to be flowed-back to customers effective with new rates on March 1, 2000. The Company filed its plan for measuring the net savings with the MPUC in June 1999, and the determination of the methodology for measuring the savings has been incorporated into the Company's current rate proceeding with the MPUC. The Company utilized this methodology to calculate a net expense, as compared to savings, for the 1999 period in the amount of approximately $1.5 million. This net expense has been recorded as an addition to the Company's electric operating revenues and as a reduction of the previously discussed deferred asset sale gain. Of this amount, the third quarter net expense was approximately $337,000. The reason for the net expense is due principally to the Company incurring unusually high purchased power costs during the extremely hot weather in early June and in July 1999, as a result of the Company no longer owning certain generation and transmission assets subsequent to the asset sale to PP&L. Since these high costs would not have occurred if the Company had not sold these assets, the Company has recorded the net expense as a reduction of the deferred asset sale gain. In connection with the Company's current rate proceedings at the MPUC, the Company's proposed methodology for computing the previously discussed net expense and the rate used to calculate carrying costs on the deferred asset sale gain have been challenged by other parties in the rate proceedings. The Company is uncertain as to which method will ultimately be approved by the MPUC, and consequently has recorded a reserve of approximately $1.04 million on the Consolidated Balance Sheets as of September 30, 1999 to reflect the estimated difference in the computations between the parties. On the Consolidated Statements of Income, this reserve is reflected as a $688,000 reduction in electric operating revenues, a $508,000 reduction in Allowance for Equity Funds Used During Construction and a $155,000 addition to Allowance for Borrowed Funds Used During Construction. RESUMPTION OF DIVIDEND ON COMMON STOCK - At a regularly scheduled Board of Directors meeting held on June 16, 1999, the Board of Directors of the Company declared a cash dividend on its common stock of $.15 per share, payable July 20, 1999 to shareholders of record on June 30, 1999. This was the first common stock dividend since the Company suspended common dividend payments in March 1997 due to financial difficulties triggered by problems at the Maine Yankee nuclear generating plant. The Company has a 7% ownership interest in Maine Yankee, which was permanently shut down later in 1997 and is now in the process of being decommissioned. The Company also declared a cash dividend on its common stock of $.15 per share, payable October 20, 1999 to shareholders of record on September 30, 1999. Prior to suspending the common dividend in March 1997, the Company had been paying quarterly dividends on its common stock of $.18 per share. ELECTRIC UTILITY INDUSTRY RESTRUCTURING - ACCOUNTING ORDER - In September 1999 the Company received an accounting order from the MPUC related to the Company's request to defer certain incremental costs associated with electric utility industry restructuring. In connection with the accounting order, the Company recorded as a deferred asset in September 1999 approximately $314,000 of restructuring costs, which had previously been charged to operation and maintenance expense in 1999. In connection with the current rate proceeding with the MPUC, the deferred restructuring costs are expected to start being recovered on March 1, 2000. Based on the accounting order, the Company will defer, for future recovery, certain additional incremental restructuring costs through the advent of retail competition on March 1, 2000. BANGOR GAS JOINT VENTURE - As reported in the Company's 1998 Form 10-K, the Company, through a wholly-owned subsidiary, has been participating in a joint-venture limited liability company, Bangor Gas Company, LLC (Bangor Gas), to provide natural gas service to the greater Bangor area. Gas service in the Bangor area has become feasible for the first time because of development of the Maritimes and Northeast Pipeline Project, extending from the Sable Offshore Energy Project near Sable Island, Nova Scotia, through the State of Maine and interconnecting with the Tennessee Gas Pipeline in Dracut, Massachusetts. The pipeline passes near the Bangor area. As the restructuring of the electric industry in Maine has developed, the Company has become increasingly cognizant of the need to focus on its core electric transmission and distribution business. Consequently the Company has determined that it no longer intends to participate in the Bangor Gas joint venture and is exploring options for divesting of its joint venture interest. The Company's investment in Bangor Gas as of September 30, 1999 is approximately $307,000 and is recorded as an Other Investment on the Consolidated Balance Sheets. Management is currently unable to predict the financial statement impact of this decision. REGULATORY PROCEEDINGS - As discussed in the 1998 Form 10-K, the principal provisions of the 1997 Maine Restructuring legislation provide for customers to have direct retail access to generation services and for deregulation of competitive electricity providers, commencing March 1, 2000, with transmission and distribution (T&D) companies continuing to be regulated by the MPUC. The MPUC is conducting the proceeding that will ultimately determine the Company's stranded costs and corresponding revenue requirements and revenue requirements as a T&D utility. The Company expects the MPUC to issue its order in connection with this proceeding in the near future. ICE STORM - RECEIPT OF FEDERAL FUNDS - In early October 1999, the Company received approximately $1.8 million from the federal government in connection with service restoration costs associated with the major ice storm in January 1998. This amount has been recorded as a reduction of the Company's deferred ice storm costs and will begin to be returned to customers with the implementation of new rates effective March 1, 2000. REVENUES Electric operating revenue increased by $2.3 million or 4.7% in the third quarter of 1999 due principally to the impact of the previously discussed 1.36% rate increase on June 1, 1999, an overall 4.6% increase in kilowatt hour (KWH) sales (excluding off-system sales, which are sales related to power pool and interconnection agreements and resales of purchased power) in the 1999 quarter. KWH sales in the third quarter of 1999 were positively affected by the warm summer weather. The increased revenues were offset by a reduction in off-system sales in the 1999 quarter and a $504,000 reduction in revenue sharing from the Company's largest industrial customer (See the 1998 Form 10-K for further discussion of this revenue sharing arrangement). EXPENSES Fuel for generation and purchased power expense increased $2.6 million or 12.5% in the third quarter of 1999 as compared to 1998. Purchased power expenses increased by about $.9 million in the third quarter of 1999 due to the May 27th sale of the Company's hydroelectric facilities and subsequent buyback contract with PP&L for the power from the plants. Also as a result of the sale to PP&L, incremental replacement power costs for other entitlements in Wyman #4, Hydro-Quebec and MEPCO transmission were $1.8 million greater for the third quarter of 1999 as compared to 1998. In preparation for utility restructuring, new market rules were implemented in NEPOOL on May 1, 1999 which sets prices for replacement purchases from the pool at open market levels related to supply and demand as opposed to marginal fuel costs, as was the case in the prior year. The result was on- peak power prices that were approximately two times as great as would normally occur during July. Settlement receipts associated with the Company's fuel risk management program, which are recorded as a reduction of fuel and purchased power expense, increased by approximately $3 million in the third quarter of 1999 compared to the 1998 quarter. The Company continued its hedge program in late 1998 and increased its hedge volume by approximately 30% as a result of replacing a fixed price power contract with a residual oil indexed contract. Although the spot price of residual oil was significantly greater in the 1999 quarter, fixed prices that the Company agreed to pay were 13% lower. See the 1998 Form 10-K for a more complete discussion of the Company's fuel risk management program. Other operation and maintenance (O&M) expense decreased by $558,000 in the third quarter of 1999 as compared to 1998. Decreasing other O&M expense in the 1999 quarter was a $314,000 reduction in expenses associated with the Company's hydroelectric facilities and interest in the Wyman #4 generating plant as a result of the sale to PP&L in May 1999. Also decreasing other O&M expense in the 1999 quarter was an increase in overhead expenses allocated to capital projects. This increase was principally a result of major construction activities being performed by the Company in connection with the Maine Independence Station, a new 520 megawatt gas fired generation facility in Veazie, Maine, coming online and connecting to the regional transmission power grid. The Company is being reimbursed by the owner of the facility for the construction costs incurred, including overheads. Other O&M was also reduced by the impact of the previously discussed deferred restructuring costs accounting order, whereby costs that were charged to O&M expense in the first two quarters of 1999 were deferred in the third quarter of 1999. Finally, reducing other O&M expense was a $142,500 reduction in bad debt expense in the 1999 quarter, resulting from lower levels of write-offs, and a $147,000 reduction in amortization expense associated with deferred demand-side management (DSM) costs, which resulted from the end of the amortization of a portion of the deferred DSM costs in 1999. These decreases in other O&M expense in the 1999 quarter were offset to some extent by a $246,000 increase in postretirement and active medical costs, principally as a result of increased medical claims costs, and the Company incurred approximately $247,000 of incremental non-labor expenditures in the third quarter of 1999 related costs associated with assessment and testing of systems for year 2000 (Y2K) compliance. Depreciation and amortization expense decreased $749,000 in the third quarter of 1999 as compared to the 1998 quarter due principally to the sale of the Company's generation assets in May 1999. This reduction was offset somewhat by the impact of anticipated 1999 property additions. The decrease in property and other taxes in the third quarter of 1999 was due principally to reductions in property taxes as a result of the sale of the Company's generation assets. This reduction in property taxes was offset to some extent by increased electric plant additions in 1999. The increase in income taxes was principally a function of greater earnings in the third quarter of 1999 as compared to the 1998 quarter. This increase was offset slightly by the impact of the one-time income tax benefits related to the utilization of investment tax credits and adjustments to the 1998 tax returns filed in September of 1999. See Footnote 2 to the Consolidated Financial Statements for a reconciliation of the Company's effective income tax rate. OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENS The increase in other income in the 1999 quarter was due primarily to the previously discussed gain on sale of Penobscot Hydro and interest income realized from invested generation asset sale proceeds, reduced by increased net operating expenses associated with non-core business ventures in the 1999 quarter. Allowance for funds used during construction (AFDC) decreased $713,000 in 1999 relative to 1998 due principally to $628,000 in carrying costs being recorded on the previously discussed deferred asset sale gain, including the aforementioned reserve, and the deferred gain on sale of Graham Station property (See the 1998 Form 10-K for a complete discussion of this property sale). Also decreasing AFDC in the 1999 quarter was a $99,000 reduction in carrying costs recorded on deferred ice storm costs. With the ARP rate increase on June 1, 1999, the Company ceased accruing carrying costs on the deferred ice storm costs. Long-term debt interest expense decreased $1.7 million in the third quarter of 1999 as compared to 1998 due primarily to principal repayments on the Company's 12.25% first mortgage bonds (which were fully repaid in August 1999); a $13.1 million principal payment at the end of June 1999 on the Finance Authority of Maine Revenue Notes; monthly principal payments from October 1998 through September 1999 amounting to $4.6 million on the $24.8 million medium term notes; principal repayments of $6.2 million and $38.8 million in January and June 1999, respectively, on the $45 million medium term notes which were issued on June 29, 1998; the full redemption of $15 million in outstanding 10.25% Series First Mortgage Bonds in early July 1999; and the redemption of $4.2 million in outstanding variable rate Pollution Control Revenue Bonds in early September 1999. Other interest expense decreased due principally to a $21.3 million reduction in weighted average short-term borrowings outstanding in the 1999 quarter as compared to 1998. The Company fully repaid the outstanding balance under its revolving credit line in April 1999, and no new borrowings have subsequently occurred. NINE MONTHS OF 1999 AS COMPARED TO THE NINE MONTHS OF 1998 EARNINGS Basic earnings per common share for the nine months ended September 30, 1999 were $1.61, as compared to $.91 per common share for the 1998 period. The increased earnings were largely the result of the June 1, 1999 rate increase, an increase in KWH sales in the 1999 period, a one-time benefit of $896,000 ($.07 increase in basic earnings per common share) related to the settlement of a dispute related to the NEPOOL transmission rates, a one-time benefit of $802,000 ($.06 increase in basic earnings per common share) due to the settlement, by NEPOOL, of a contract dispute with HQ, the February 13, 1998 rate increase authorized by the MPUC designed to increase annual revenues by approximately $13.2 million (which included the $5.1 million authorized in a temporary rate increase that became effective on July 1, 1997), and the previously discussed impact of the gain on sale of subsidiary and one-time income tax benefits in the third quarter of 1999. REVENUES Electric operating revenue increased by $4.1 million, or 2.8% in the first nine months of 1999 due principally to the impact of the previously discussed rate increases on February 13, 1998 and on June 1, 1999, an overall 3.5% increase in KWH sales (excluding off-system sales) in the 1999 period, and $854,000 in additional revenues attributable to the previously discussed net expense, for the period from June through September 1999, associated with the generation asset sale. The increase in KWH sales in 1999 was affected by service interruptions during the ice storm in January 1998, slightly colder weather in the winter and spring of 1999, and warmer weather during the summer months of 1999 as compared to 1998. The increased revenues were offset by a $1 million reduction in off-system sales in the 1999 period and a $1.7 million reduction in revenue sharing from the Company's largest industrial customer. EXPENSES Fuel for generation and purchased power expense decreased $1.5 million or 2.4% in the 1999 period as compared to 1998. The decreased expense was a result of several factors. The previously discussed settlements of the disputes with HQ and NEPOOL resulted in $747,000 and $896,000 reductions in expense, respectively in 1999. The Company recorded a benefit of $2.4 million in the 1999 period, as compared to $1.3 million for 1998, related to savings realized from the restructuring of the PERC purchased power contract in June 1998. The $1 million reduction in off-system sales in the 1999 period also impacted the decrease in fuel and purchased power expense. Purchased power expenses increased by about $1.3 million in the 1999 period due to the May 27th sale of the Company's hydroelectric facilities and subsequent buyback contract with PP&L for the power from the plants. Incremental replacement power costs for other entitlements in Wyman #4, Hydro-Quebec and MEPCO transmission were $3.4 million greater than the comparable 1998 expense. June 1999 replacement power costs were extremely high due to very unusual circumstances in NEPOOL, with record-breaking loads while many generators were still out of service on spring maintenance. Further, as previously discussed, the NEPOOL new market rules resulted in on- peak power prices that were two to three times as great as would normally occur during June. Excluding the impact of the unusually high replacement power costs incurred in June 1999, which are discussed above, there was a reduction in oil-related and other purchased power costs in the 1999 period as compared to 1998. A significant portion of the Company's power contracts are directly tied to the price of residual oil, which while 17% lower in the first quarter and largely unchanged in the second quarter of 1999 as compared to 1998, was 67% higher in the third quarter of 1999 as compared to 1998. For the nine month period residual oil prices have been 16% higher in 1999 compared to 1998. However, the Company had hedged these purchases through its fuel risk management program with a fixed price about 13% lower in 1999 compared to 1998 (See the 1998 Form 10-K for a more complete discussion of the Company's fuel risk management program). Also, prior to the generation asset sale at the end of May 1999, purchased power expenses were reduced by an increase in power generation by the Company's hydroelectric facilities. Other O&M expense increased by $1 million in the 1999 period as compared to 1998. Increasing other O&M expense in 1999 was a $791,000 increase in postretirement and active medical costs due principally to higher medical claims costs; the Company incurred approximately $621,000 of additional incremental non-labor expenditures in the 1999 period as compared to 1998 related to electric utility industry restructuring activities (net of the previously discussed deferral in the third quarter of 1999), costs associated with Y2K compliance, and an upgrade to the Company's customer information system; the Company has incurred approximately $354,000 in increased outside legal services expense in 1999 as compared to 1998, with much of the increase attributable to Federal Energy Regulatory Commission and NEPOOL issues; and the Company recorded $383,000 of amortization expense associated with deferred ice storm costs for the period from June 1 through September 30, 1999. Offsetting the increases in other O&M expense to some extent were a $333,000 reduction in bad debt expense, due to reduced write-offs in the 1999 period; hydroelectric and Wyman #4 O&M expenses were $433,000 lower in the 1999 period as a result of the generation asset sale in late May 1999; amortization of deferred DSM expenses was $342,000 lower in 1999 as compared to 1998 and overhead expenses allocated to capital projects were higher in the 1999 period, each for the previously discussed reasons. Depreciation and amortization expense decreased $937,000 in the 1999 period as compared to 1998, due principally to the reasons discussed for the third quarter of 1999 as compared to the third quarter of 1998. The $359,000 increase in amortization of contract buyouts and restructuring in 1999 was due principally to PERC purchased power contract restructuring in June 1998. In 1999 the Company recorded $750,000 of amortization related to deferred PERC contract restructuring costs as compared to $250,000 of amortization in 1998. This was offset to some extent by the February 1998 rate order, whereby the MPUC required the Company to reduce the amortization of the deferred regulatory asset associated with the 1993 buyout of one of its high-priced non-utility generator contracts by an annualized amount of approximately $1.1 million, effective February 13, 1998. The amortization of this regulatory asset amounted to $2.1 million in the 1999 period as compared to $2.2 million in 1998. The increase in income tax expense in the first nine months of 1999 was due principally to the reasons previously discussed for the third quarter of 1999 as compared to 1998. OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE The $637,000 increase in other income in 1999 was due principally to the previously discussed gain on sale of Penobscot Hydro and interest income realized from invested generation asset sale proceeds. The decreases in AFDC, long-term debt and other interest expense in the first nine months of 1999 as compared to the first nine months of 1998 were principally due to the reasons previously discussed for the quarters ended September 30, 1999 and 1998. Additionally, affecting the change in long-term debt interest expense in the two periods was the issuance of $24.8 million and $45 million of medium term notes at the end of March 1998 and the end of June 1998, respectively, and principal payments of $4 million in March 1998 and the final $30 million in June 1998 on the Company's old medium term notes. LIQUIDITY AND CAPITAL RESOURCES The Consolidated Statements of Cash Flows reflect events in the first nine months of 1999 and 1998 as they affect the Company's liquidity. Net increase in cash from operating activities was $40.4 million in 1999 as compared to $18.7 million in 1998. Positively impacting cash flows from operating activities in the 1999 period as compared to 1998 were the beneficial impacts of the 5.83% and 1.36% rate increases effective February 13, 1998 and June 1, 1999, respectively, a $1.75 million payment received in the first quarter of 1999 quarter related to a terminated purchased power contract (See 1998 Form 10-K), a $2.6 million reduction in deferred Maine Yankee incremental costs in the 1999 period as compared to 1998, and the Company's interest payments were reduced by $1.7 million in the 1999 period due principally to the previously discussed long-term debt principal payments and reduction in borrowings on the Company's revolving credit facility in 1999. In addition, in the 1998 period cash flows were reduced by $7.5 million in payments associated with restructuring the PERC purchased power contract, a $1.6 million reduction due to the effect of a large customer who prepaid its electric usage for a one-year period in the third quarter of 1997 and $4.0 million in incremental costs incurred in 1998 in connection with the January 1998 ice storm. Offsetting the previously discussed cash flow enhancements in 1999 as compared to 1998 were an $8.4 million increase in state and federal income tax payments as a result of the gain on sale of generating assets for income tax purposes. Also in the third quarter of 1999, the Company paid $2.8 million to the holders of the PERC warrants, upon the exercise of the warrants, (See the 1998 Form 10-K for a discussion of the warrants) in lieu of issuing shares of common stock. Construction expenditures were $2.1 million greater in the 1999 period due principally to increased construction activity on the transmission and distribution system in 1999. As previously discussed, the Company received approximately $79.6 million in proceeds related to its generation asset sale in late May 1999 and an additional $10 million in late July 1999 in connection with the sale of Penobscot Hydro. As previously discussed, the Company reinstated it common stock dividend in the second quarter of 1999, resulting in the increase in dividends on common stock in the 1999 period. The reduction in preferred dividends paid resulted principally from a $1.5 million sinking fund payment made on the Company's 8.76% mandatory redeemable preferred stock in December 1998. The increase in payments on long-term debt is due principally to the previously discussed principal payment activity. The Company utilized $6.2 million in proceeds, from the September 1998 property sale to Casco Bay Energy, released by the trustee in January 1999, to repay principal in connection with the $45 million medium term notes. The previously discussed $38.8 million repayment of the remaining outstanding medium term notes, $15 million redemption of the 10.25% First Mortgage Bonds, $2.1 million redemption of the 12.25% First Mortgage Bonds, and the redemption of $4.2 million of Pollution Control Revenue Bonds were accomplished through the utilization of the generation asset sale proceeds. Additionally, on October 20, 1999, the Company utilized asset sale proceeds to redeem the remaining $9 million of outstanding 8.76% mandatory redeemable preferred stock. Cash flows were enhanced in the 1998 period by the previously discussed issuances of $69.8 million in medium term notes, net of $1.5 million which were required to be deposited in a capital reserve fund. As previously discussed, the Company has maintained full borrowing capacity under its revolving credit facility since early in the second quarter of 1999. This elimination of short-term borrowings in the 1999 period is principally a result of the previously discussed enhancements in operating cash flows as well as the current availability of generation asset sale proceeds which have not yet been utilized to repay outstanding long-term debt. In June 1998, in connection with entering into an Amended and Restated Revolving Credit and Term Loan Agreement, the Company deposited $4.6 million of proceeds from the financing with a third party trustee to secure the existing letter of credit related to the Pollution Control Revenue Bonds, until a new letter of credit was issued in the fourth quarter of 1998. For additional discussion of liquidity and capital resources, see the Company's 1998 Form 10-K. Y2K UPDATE The Company has established a structured approach in connection with its Y2K compliance activities, which inventories and prioritizes its hardware, software and embedded technology systems including electrical transmission & distribution system, computer network, software applications, personal computers, telecommunications equipment and facilities. The Company has attained its goal of inventorying and prioritizing and has completed testing of the systems and devices that support its mission critical operations as of June 30, 1999. The Company has also identified and contacted the third parties with which it has a material relationship in order to establish their Y2K status in a timely fashion, and is continuing to do so. In addition, the Company is coordinating its efforts with the NEPOOL/ISO New England Year 2000 Joint Oversight Committee which has been given responsibility for operational reliability of the NEPOOL Control Area and has complied with North American Electric Reliability Council (NERC) Y2K guidelines and reporting requirements. In its June 30th NERC filing, the Company reported that all of its mission critical systems were "Y2K Ready". "Mission critical" systems are defined as those that are used to produce and deliver sustained and reliable electricity to customers. For the Company these systems include: - - The entire electrical transmission & distribution system, - - Telecommunications systems (phone and radio), - - Computer networks including division offices, - - Customer Information System (outage processing), - - Geographical Information System, and - - Key facilities devices (generators and uninterrupted power supply systems). With mission critical Y2K work complete, the Company will continue to assess and test various business systems and will be refining and practicing contingency plans. In addition, we will track and test, where necessary, changes to our systems to ensure no Y2K related problems are introduced. The Company has also prepared comprehensive contingency plans for its own operations and continues to monitor the integrated contingency planning efforts of NERC and the Northeast Power Coordinating Council. The estimated cost to conduct testing, develop or modify contingency plans, and replace non-compliant technologies is approximately $2 million, which includes both internal and external costs. Approximately $950,000 of these estimated costs are expected to be capitalized, instead of being charged to expense, since the costs relate principally to investments in new equipment and technologies and not the modification of existing systems. During the first nine months of 1999, approximately $1.1 million was expended in connection with the Y2K, of which $292,000 was capitalized and $779,000 charged to expense. Through September 30, 1999, on a cumulative basis, approximately $1.5 million has been expended, of which $613,000 has been capitalized and $867,000 charged to expense. Time and cost estimates are based on currently available information and could be affected by the ability to correct all relevant computer codes and equipment, and the Y2K readiness of the Company's business partners, among other factors. There is no certainty as to whether the Company will be able to solve its potential Y2K issues. Consequently, the Company has identified realistic failure scenarios, which for contingency plans have been developed. In addition, detailed transition and staffing plans have also been developed allowing efficient and effective problem resolution in the event of an unanticipated failure. Based on our testing to date, the Company believes its plans of action are adequate for Y2K compliance of its critical systems and to reduce the risk of external impacts to its operations. Nevertheless, achieving Y2K compliance is subject to the risks and uncertainties described above and adverse effects, should they occur, could be material despite the Company's efforts to prevent or mitigate them. NEW ACCOUNTING PRONOUNCEMENTS In May 1999, the Financial Accounting Standards Board voted to delay for one year the effective date of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FASB 133). The new effective date for implementing this pronouncement is for fiscal years beginning after June 15, 2000. The effects of the adoption on the Company's financial statements are currently not known. The Company believes its interest rate swap agreements will qualify for hedge accounting treatment under FASB 133. OTHER Management's discussion and analysis of results of operations and financial condition contains items that are "forward-looking" as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated in the forward-looking statements. Readers should not place undue reliance on forward-looking statements, which reflect management's view only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect subsequent events or circumstances. Factors that might cause such differences include, but are not limited to, future economic conditions, relationships with lenders, earnings retention and dividend payout policies, electric utility restructuring, developments in the legislative, regulatory and competitive environments in which the Company operates, the Y2K issue, and other circumstances that could affect revenues and costs. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS 000's Omitted (Unaudited) Sept. 30, Dec. 31, ASSETS 1999 1998 -------- -------- INVESTMENT IN UTILITY PLANT: Electric plant in service, at original cost $ 290,374 $ 352,975 Less - Accumulated depreciation and amortization 86,911 101,633 -------- -------- $ 203,463 $ 251,342 Construction work in progress 17,775 13,930 -------- -------- $ 221,238 $ 265,272 Investments in corporate joint ventures: Maine Yankee Atomic Power Company $ 5,385 $ 5,439 Maine Electric Power Company, Inc. 919 439 -------- -------- $ 227,542 $ 271,150 -------- -------- OTHER INVESTMENTS, principally at cost $ 1,702 $ 5,882 -------- -------- FUNDS HELD BY TRUSTEE, at cost $ 23,040 $ 29,868 -------- -------- CURRENT ASSETS: Cash and cash equivalents $ 18,314 $ 2,946 Accounts receivable, net of reserve 18,936 17,558 Unbilled revenue receivable 10,881 12,086 Inventories, at average cost: Material and supplies 2,749 2,909 Fuel oil 47 16 Prepaid expenses 222 1,129 -------- -------- Total current assets $ 51,149 $ 36,644 -------- -------- DEFERRED CHARGES: Investment in Seabrook Nuclear Project, net of accumulated amortization of $31,447 in 1999 and $30,173 in 1998 $ 27,395 $ 28,669 Costs to terminate/restructure power contracts, net of accumulated amortization of $95,660 in 1999 and $80,059 in 1998 123,008 136,979 Maine Yankee decommissioning costs 47,144 50,055 Deferred regulatory assets 24,664 32,996 Demand-side management costs 426 779 Other 8,743 12,666 -------- -------- Total deferred charges $ 231,380 $ 262,144 -------- -------- Total assets $ 534,813 $ 605,688 ======== ======== See notes to the consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS 000's Omitted (Unaudited) Sept. 30, Dec. 31, STOCKHOLDERS' INVESTMENT AND LIABILITIES 1999 1998 -------- -------- CAPITALIZATION: Common stock investment $ 128,169 $ 118,864 Preferred stock 4,734 4,734 Preferred stock subject to mandatory redemption, exclusive of current sinking fund requirements 7,650 7,604 Long-term debt, net of current portion 184,725 263,028 -------- -------- Total capitalization $ 325,278 $ 394,230 -------- -------- CURRENT LIABILITIES: Notes payable - banks $ - $ 12,000 -------- -------- Other current liabilities - Current portion of long-term debt and sinking fund requirements on preferred stock $ 20,874 $ 27,109 Accounts payable 14,037 13,896 Dividends payable 1,368 295 Accrued interest 3,837 3,474 Customers' deposits 419 329 Current income taxes (refundable) payable (390) 86 -------- -------- Total other current liabilities $ 40,145 $ 45,189 -------- -------- Total current liabilities $ 40,145 $ 57,189 -------- -------- DEFERRED CREDITS AND RESERVES: Deferred income taxes - Seabrook $ 14,216 $ 14,880 Other accumulated deferred income taxes 57,049 63,775 Maine Yankee decommissioning liability 47,144 50,055 Deferred regulatory liability 8,930 9,618 Deferred gain on asset sale 27,340 4,510 Unamortized investment tax credits 1,624 1,721 Accrued pension and postretirement benefit costs 9,178 7,770 Other 3,909 1,940 -------- -------- Total deferred credits and reserves $ 169,390 $ 154,269 -------- -------- Total Stockholders' Investment and Liabilities $ 534,813 $ 605,688 ======== ======== See notes to the consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION 000's Omitted (Unaudited) Sept. 30, Dec. 31, 1999 1998 --------- --------- COMMON STOCK INVESTMENT Common stock, par value $5 per share- $ 36,817 $ 36,817 Authorized -- 10,000,000 shares Outstanding -- 7,363,424 shares in 1999 and 1998 Amounts paid in excess of par value 58,703 59,054 Retained earnings 32,649 22,993 --------- --------- Total common stock investment $ 128,169 $ 118,864 --------- --------- PREFERRED STOCK-Non participating, cumulative- Par value $100 per share, authorized 600,000 shares Not redeemable or redeemable solely at the option of the issuer- 7%, Noncallable, 25,000 shares, authorized and outstanding $ 2,500 $ 2,500 4.25%, Callable at $100, 4,840 shares, authorized and outstanding 484 484 4%, Series A, Callable at $110, 17,500 shares, authorized and outstanding 1,750 1,750 --------- --------- $ 4,734 $ 4,734 --------- --------- 8.76%, Subject to mandatory redemption requirements- Callable at 103.13% if called on or prior to December 27, 1999, 150,000 shares authorized and 90,000 shares outstanding in 1999 and 1998 $ 9,244 $ 9,198 Less: Sinking fund requirements 1,594 1,594 --------- --------- $ 7,650 $ 7,604 --------- --------- LONG-TERM DEBT First Mortgage Bonds- 10.25% Series due 2019 $ - 15,000 10.25% Series due 2020 30,000 30,000 8.98% Series due 2022 20,000 20,000 7.38% Series due 2002 20,000 20,000 7.30% Series due 2003 15,000 15,000 12.25% Series due 2001 - 3,743 --------- --------- $ 85,000 $ 103,743 Less: Sinking fund requirements - 1,675 --------- --------- Total first mortgage bonds $ 85,000 $ 102,068 --------- --------- Variable rate demand pollution control revenue bonds Series 1983 due 2009 $ - $ 4,200 --------- --------- Other Long-Term Debt- Finance Authority of Maine - Taxable Electric Rate Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 100,600 $ 113,700 Medium Term Notes, Variable interest rate- LIBO Rate plus 1.125%, due 2002 18,405 21,900 Medium Term Notes, Variable interest rate- LIBO Rate plus 2%, due 2000 - 45,000 --------- --------- $ 119,005 $ 180,600 Less: Current portion of long-term debt 19,280 23,840 --------- --------- $ 99,725 $ 156,760 --------- --------- Total long-term debt $ 184,725 $ 263,028 --------- --------- Total Capitalization $ 325,278 $ 394,230 ========= ========= See notes to the consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS 000's Omitted (Unaudited) Nine Months Ended Sept. 30, Sept. 30, 1999 1998 --------- --------- Cash Flows From Operating Activities: Net income $ 12,701 $ 7,624 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 6,563 7,500 Amortization of Seabrook Nuclear Project 1,274 1,274 Amortization of contract buyouts and restructuring 15,601 15,242 Other amortizations 1,832 1,469 Allowance for equity funds used during construction 81 (309) Deferred income tax provision and amortization of investment tax credits (2,857) 4,041 Asset sale interim revenue requirement deficiency (853) - Gain on sale of subsidiary (523) - Changes in assets and liabilities: Release of Graham Station property sale proceeds by trustee 6,200 - Payment received related to terminated purchased power contract 1,750 - Costs to restructure purchased power contract (849) (7,448) Deferred incremental ice storm costs - (4,192) Deferred incremental Maine Yankee costs 1,699 (869) Deferred Maine Yankee refueling costs - 286 Exercise of PERC warrants-cash paid in lieu of issuing shares (2,834) - Accounts receivable, net and unbilled revenue (179) 689 Accounts payable (1,191) (1,994) Accrued interest 363 1,043 Current and deferred income taxes (62) 133 Deferred revenue - (1,571) Other current assets and liabilities, net 412 262 Other, net 1,239 (4,517) --------- --------- Net Increase in Cash From Operating Activities: $ 40,367 $ 18,663 --------- --------- Cash Flows From Investing Activities: Construction expenditures $ (15,346) $ (13,244) Allowance for borrowed funds used during construction 61 (510) Asset sale proceeds 89,588 - --------- --------- Net Increase (Decrease) in Cash From Investing Activities $ 74,303 $ (13,754) --------- --------- Cash Flows From Financing Activities: Dividends on common stock $ (1,104) $ - Dividends on preferred stock (822) (920) Payments on long-term debt (84,538) (52,353) Call premiums on early redemption of securities (838) - Proceeds from issuances of long-term debt, net of capital reserve fund requirements - 68,300 Short-term debt, net (12,000) (15,000) Special deposit associated with securing letter of credit - (4,592) --------- --------- Net Decrease in Cash From Financing Activities $ (99,302) $ (4,565) --------- --------- Net Increase in Cash and Cash Equivalents $ 15,368 $ 344 Cash and Cash Equivalents at Beginning of Period 2,946 937 --------- --------- Cash and Cash Equivalents at End of Period $ 18,314 $ 1,281 ========= ========= Cash Paid During the Nine Months For: Interest (Net of Amount Capitalized) $ 15,066 $ 16,776 Income Taxes 8,800 425 ========= ========= See notes to consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT 000's Omitted (Unaudited) Amounts Total Paid in Common Common Excess of Retained Stock Stock Par Value Earnings Investment BALANCE DECEMBER 31, 1997 $36,817 $56,969 $12,772 $106,558 Net income - - 7,624 7,624 Cash dividends declared on- Preferred stock - - (889) (889) Other - - (46) (46) Issuance of warrants - 2,085 - 2,085 ---------- ---------- ---------------------- BALANCE SEPTEMBER 30, 1998 $36,817 $59,054 $19,461 $115,332 ========== ========== ====================== BALANCE DECEMBER 31, 1998 $36,817 $59,054 $22,993 $118,864 Net income - - 12,701 12,701 Cash dividends declared on- Preferred stock - - (790) (790) Common stock - - (2,209) (2,209) Other - - (46) (46) Exercise of warrants-cash paid in lieu of issuing shares - (351) - (351) ---------- ---------- ---------------------- BALANCE SEPTEMBER 30, 1999 $36,817 $58,703 $32,649 $128,169 ========== ========== ====================== See notes to the consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 ------------- (Unaudited) (1) BASIS OF PRESENTATION AND ACCOUNTING POLICIES: 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, in the opinion of Bangor Hydro-Electric Company (the Company), the disclosures contained in this Form 10-Q are adequate to make the information presented not misleading. The year end condensed balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by generally accepted accounting principles. These statements should be read in conjunction with the consolidated financial statements, footnotes and all other information included in the 1998 Form 10-K. In the opinion of the Company, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring accruals, necessary to present fairly the financial position as of September 30, 1999 and the results of operations and cash flows for the periods ended September 30, 1999 and 1998. The Company's significant accounting policies are described in the Notes to the Consolidated Financial Statements included in its 1998 Form 10-K filed with the Securities and Exchange Commission. For interim reporting purposes, the Company follows these same basic accounting policies but considers each interim period as an integral part of an annual period. Accordingly, certain expenses are allocated to interim periods based upon estimates of such expenses for the year. (2) INCOME TAXES: The following table reconciles a provision calculated by multiplying income before federal income taxes by the statutory federal income tax rate to the federal income tax provision: Nine Months Ended September 30, ------------------------------- 1999 1998 ---- ---- Amount % Amount % ------ - ------ - (Dollars in Thousands) Federal income tax provision at statutory rate $7,250 35 $4,279 35 Plus permanent reductions in tax expense resulting from statutory exclusions from taxable income 63 - 33 - ------ --- ----- --- Federal income tax provision before effect of temporary differences and investment tax credits $7,313 35 $4,312 35 (Less) temporary differences that are flowed through for rate- making and accounting purposes (462) (3) (421) (4) (Less) utilization and amortization of investment tax credits (363) (2) (160) (1) ------ --- ----- --- Federal income tax provision $6,488 30 $3,731 30 ====== === ===== === (3) INVESTMENT IN JOINTLY OWNED FACILITIES: Condensed financial information for Maine Yankee Atomic Power Company (Maine Yankee), Maine Electric Power Company, Inc. (MEPCO), Bangor-Pacific Hydro Associates (BPHA), Chester SVC Partnership (Chester) and Bangor Gas Company, LLC (Bangor Gas) is as follows: MAINE YANKEE MEPCO ------------ ----- (Dollars in Thousands) (Unaudited) Operations for Nine Months Ended ------------------------------------- Sept 30, Sept 30, Sept 30, Sept 30, 1999 1998 1999 1998 OPERATIONS: -------- -------- -------- -------- As reported by investee- Operating revenues $ 53,604 $ 92,814 $ 2,072 $ 2,466 ========= ========= ======== ========= Earnings applicable to common stock $ 3,775 $ 6,386 $ 3,225 $ 822 ========= ========= ======== ========= Company's reported equity- Equity in net income $ 264 $ 447 $ 458 $ 117 (Deduct) Add-Effect of adjusting Company's estimate to actual (261) 9 33 (34) --------- -------- ------- --------- Amounts reported by Co. $ 3 $ 456 $ 491 $ 83 ========== ========= ======== ========= MAINE YANKEE MEPCO ------------ ----- (Dollars in Thousands) (Unaudited) Financial Position at ---------------------------------- Sept 30, Dec. 31, Sept 30, Dec. 31, 1999 1998 1999 1998 FINANCIAL POSITION: --------- --------- -------- -------- As reported by investee- Total assets $1,112,163 $1,183,298 $ 9,537 $ 5,515 Less- Preferred stock 16,200 16,800 - - Long-term debt 57,000 68,433 70 220 Other liabilities and deferred credits 962,572 1,018,575 3,099 2,079 --------- ---------- ------- ------- Net assets $ 76,391 $ 79,490 $ 6,368 $ 3,216 =========== ========== ======= ======= Co.'s reported equity- Equity in net assets $ 5,347 $ 5,564 $ 904 $ 457 Add(Deduct)- Effect of adjusting Company's estimate to actual 38 (125) 15 (18) ----------- ---------- ------- ------- Amounts reported by Co. $ 5,385 $ 5,439 $ 919 $ 439 ========== ========== ======= ========= In late July 1999, the Company sold its wholly-owned subsidiary Penobscot Hydro Company, Inc., which held a 50% ownership interest in BPHA (See Note 5). Consequently, no financial information related to financial position is presented for BPHA as of September 30, 1999. BPHA Chester ------------------- ------------------ (Dollars in Thousands) (Unaudited) Operations for Nine Months Ended * ----------------------------------------- July 31, Sept 30, Sept 30, Sept 30, 1999 1998 1999 1998 -------- -------- -------- -------- OPERATIONS: As reported by investee- Operating revenues $ 4,426 $ 5,663 $ 3,244 $ 3,347 ======= ======= ======= ======= Net Income $ 1,730 $ 2,010 $ - $ - ======= ======= ======= ======= Co.'s reported equity in net income $ 865 $ 1,005 $ - $ - ======= ======= ======= ======= * Except for BPHA for the 1999 period, which is presented for the seven months ending July 31, 1999. Financial Position at Sept 30, Dec. 31, Sept 30, Dec. 31, 1999 1998 1999 1998 --------- -------- -------- -------- FINANCIAL POSITION: As reported by investee- Total assets $ - $38,324 $25,427 $26,478 Less- Long-term debt - 26,300 23,767 24,654 Other liabilities - 2,517 1,660 1,824 -------- ------- ------- ------- Net assets $ - $ 9,507 $ - $ - ======== ======= ======= ======= Co.'s reported equity in net assets $ - $ 4,754 $ - $ - ======== ======= ======= ======= At September 30, 1999, and December 31, 1998, the Company's wholly owned subsidiary, Penobscot Natural Gas Company, had a $307,000 and $77,000 equity investment in Bangor Gas, a start-up entity, respectively and recorded equity losses in Bangor Gas of approximately $170,000 and $55,000 for the nine months ended September 30, 1999 and 1998, respectively. At September 30, 1999 and December 31, 1998, Bangor Gas' total assets, principally construction work in progress, amounted to $6.8 million and $2.6 million, respectively. (4) EARNINGS PER SHARE: The following table reconciles basic and diluted earnings per common share assuming all stock warrants were converted to common shares. (Amounts in 000's, except per share data) For the Quarters For the Nine Months Ended Ended -------------------- ------------------- Sept 30, Sept 30, Sept 30, Sept 30, 1999 1998 1999 1998 -------- -------- -------- -------- Earnings applicable to common stock $ 4,758 $ 2,637 $11,865 $ 6,689 -------- -------- ------- ------- Average common shares outstanding 7,363 7,363 7,363 7,363 Plus: incremental shares from assumed conversion 1,032 461 989 164 -------- -------- ------- ------- Average common shares outstanding plus assumed warrants converted 8,395 7,824 8,352 7,527 -------- -------- ------- ------- Basic earnings per common share $ .65 $ .36 $ 1.61 $ .91 ======== ======= ======= ======= Diluted earnings per common share $ .57 $ .34 $ 1.42 $ .89 ======== ======= ======= ======= (5) GENERATION ASSET SALE: On May 27, 1999, the Company completed most of the transaction for the sale of its electric generating assets and certain transmission rights to PP&L Global (PP&L). The purchase price for the assets transferred was $79 million. The sale involved all but one of the Company's hydroelectric plants on the Penobscot, Piscataquis, and Union rivers and Bangor Hydro's 8.33% ownership interest in the Wyman Unit #4 oil-fired plant in Yarmouth, Maine--a total base load capacity of 83 megawatts. The sale also involved a transfer by the Company of rights to transmit power over the Maine Electric Power Company (MEPCO) transmission facilities connecting the New England Power Pool (NEPOOL) to New Brunswick Canada; the Company's rights as a participant in the regional utilities' agreement with Hydro-Quebec pursuant to an agency agreement; and the Company's rights to develop a second high voltage transmission line that will connect NEPOOL to New Brunswick, Canada. As discussed in the 1998 Form 10-K, the Company and other Maine utilities were required to sell their generation assets as a result of the comprehensive electric utility industry restructuring law adopted in Maine in 1997. The Company conducted an auction in 1998, which led to the signing of a purchase and sale agreement with PP&L in late September 1998. The purchase and sale agreement also includes the Company's 50% interest in the 13 megawatt West Enfield hydro station on the Penobscot River. In late July 1999, the Company received $10 million in proceeds from the transfer of the economic interest in that project, and in late August 1999, the Maine Public Utilities Commission (MPUC) approved the sale of Penobscot Hydro Company, Inc. (Penobscot Hydro), the Company's wholly-owned subsidiary which held the 50% interest in the West Enfield hydro station, to PP&L. The Company has utilized a significant portion of the net proceeds of the sale to reduce outstanding debt and preferred stock. The Company realized a net gain on the sale related to the PP&L sale of approximately $23.0 million, and $22.5 million of this amount has been recorded as a deferred liability at September 30, 1999 on the Consolidated Balance Sheets. Included in this deferred amount is the accrual of carrying costs on the deferred gain balance and the net expense associated with the sale of its generating assets and the simultaneous purchased power buyback agreement with PP&L (See below for a discussion of the net expense). The deferred gain will be utilized to reduce electric rates effective March 1, 2000, with the introduction of retail competition. The remaining $.5 million of the gain relates to the portion of the gain on sale of Penobscot Hydro which is allocable to shareholders (recorded as other income in the Consolidated Statements of Income for the quarter ending September 30, 1999). For a discussion of the restructuring of the electric utility industry in the State of Maine, please see the 1998 Form 10-K. (6) ALTERNTIVE RATE PLAN FILING: In May 1999, the MPUC approved a portion of the Company's February 1999 request for rate adjustment under the so-called Alternative Rate Plan (ARP). Pursuant to the MPUC Order, the Company implemented an increase in its standard tariff of about 1.36% effective June 1, 1999. An alternative rate plan is a method of utility regulation intended to replace the costly, controversial periodic rate increase proceedings of the past. Under such a plan, utilities adjust rates annually based on a formula tied to inflation minus a "productivity factor". Adjustments for certain specified categories of costs that are unrelated to inflation are also permitted. The MPUC implemented this plan for the Company in 1998. The 1999 increase was comprised entirely of the recovery of some of the specified categories of costs that are unrelated to inflation. This was made up mostly of the recovery of a portion (about $1.4 million, or about 25%) of the costs incurred to recover from the 1998 ice storm. The inflation component actually contributed to a reduction of the 1999 adjustment, because the productivity factor offset of 1.2% exceeded the inflation rate of .9%. The ARP will not be in effect with the implementation of new rates on March 1, 2000, and the Company is uncertain if any alternative rate plan will be adopted in the future. Also in connection with the ARP Order, as a result of the sale of the Company's generation assets, the Company was required to defer all savings, for the period from the asset sale through February 29, 2000, associated with the sale of its generating assets and the simultaneous purchased power buyback agreement with PP&L. Any net savings for this period are to be flowed-back to customers effective with new rates on March 1, 2000. The Company filed its plan for measuring the net savings with the MPUC in June 1999, and the determination of the methodology for measuring the savings has been incorporated into the Company's current rate proceeding with the MPUC. The Company utilized this methodology to calculate a net expense, as compared to savings, for the 1999 period in the amount of approximately $1.5 million. This net expense has been recorded as an addition to the Company's electric operating revenues and as a reduction of the previously discussed deferred asset sale gain. Of this amount, the third quarter net expense was approximately $337,000. The reason for the net expense is due principally to the Company incurring unusually high purchased power costs during the extremely hot weather in early June and in July 1999, as a result of the Company no longer owning certain generation and transmission assets subsequent to the asset sale to PP&L. Since these high costs would not have occurred if the Company had not sold these assets, the Company has recorded the net expense as a reduction of the deferred asset sale gain. In connection with the Company's current rate proceedings at the MPUC, the Company's proposed methodology for computing the previously discussed net expense and the rate used to calculate carrying costs on the deferred asset sale gain have been challenged by other parties in the rate proceedings. The Company is uncertain as to which method will ultimately be approved by the MPUC, and consequently has recorded a reserve of approximately $1.04 million on the Consolidated Balance Sheets as of September 30, 1999 to reflect the estimated difference in the computations between the parties. On the Consolidated Statements of Income, this reserve is reflected as a $688,000 reduction in electric operating revenues, a $508,000 reduction in Allowance for Equity Funds Used During Construction and a $155,000 addition to Allowance for Borrowed Funds Used During Construction. (7) EXERCISE OF WARRANTS: In the period from late June through August 1999, 299,999 common stock warrants, which were issued in connection with the Penobscot Energy Recovery Company (PERC) purchased power contract restructuring, were exercised at a market prices ranging from $16 1/16 to $16 11/16 per share. For a complete discussion of the PERC contract restructuring and the issuance of warrants, please see the 1998 Form 10-K. The Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $2.8 million. Since the common shares were not issued, and the Company had recorded the estimated fair value of the warrants when issued in June 1998 as an addition to the PERC regulatory asset and additional paid-in capital, an adjustment has been made in connection with the cash payments option to increase the PERC regulatory asset by approximately $2.5 million and reduce additional paid-in capital by approximately $351,000 as of September 30, 1999. (8) ELECTRIC UTILITY INDUSTRY RESTUCTURING-ACCOUNTING ORDER: In September 1999 the Company received an accounting order from the MPUC related to the Company's request to defer certain incremental costs associated with electric utility industry restructuring. In connection with the accounting order, the Company recorded as a deferred asset in September 1999 approximately $314,000 of restructuring costs, which had previously been charged to operation and maintenance expense in 1999. In connection with the current rate proceeding with the MPUC, the deferred restructuring costs are expected to start being recovered on March 1, 2000. Based on the accounting order, the Company will defer, for future recovery, certain additional incremental restructuring costs through the advent of retail competition on March 1, 2000 (9) RECLASSFICATIONS: Certain 1998 amounts have been reclassified to conform with the presentation used in Form 10-Q for the quarter ended September 30, 1999. BANGOR HYDRO-ELECTRIC COMPANY FORM 10-Q FOR PERIOD ENDING SEPTEMBER 30, 1999 PART II Item 6. Exhibits and Reports on Form 8-K Exhibits: None. Reports on Form 8-K: None. BANGOR HYDRO-ELECTRIC COMPANY FORM 10-Q FOR PERIOD ENDED SEPTEMBER 30, 1999 The information furnished in this report reflects all adjustments which are, in the opinion of management, necessary to a fair statement of the results for the interim period. 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. BANGOR HYDRO-ELECTRIC COMPANY (Registrant) /s/ Frederick S. Samp --------------------- Dated: November 15, 1999 Frederick S. Samp Vice President - Finance & Law (Chief Financial Officer) EX-27 2 FINANCIAL DATA SCHEDULE FOR 3RD QTR 1999 10-Q
UT This schedule contains summary financial information extracted from Bangor Hydro-Electric Company's Form 10-Q for the third quarter of 1999 and is qualified in its entirety by reference to such 10-Q. 0000009548 BANGOR HYDRO-ELECTRIC COMPANY 1,000 9-MOS DEC-31-1999 SEP-30-1999 PER-BOOK 203,463 48,821 51,149 231,380 0 534,813 36,817 58,703 32,649 128,169 7,650 4,734 184,725 0 0 0 19,280 1,594 0 0 188,661 534,813 148,973 7,071 114,183 121,254 27,719 1,138 28,857 16,156 12,701 836 11,865 2,209 18,852 39,529 1.61 1.42
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