-----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, DE4r1AlgnxgNvsd0PSZqMQghEzV92FvF0i+4B3l7WnAcjRGTIPOdK9e3X2OlxZ4a E7lqSyhTzcrSqTKHoJr5rA== 0000043704-00-000004.txt : 20000329 0000043704-00-000004.hdr.sgml : 20000329 ACCESSION NUMBER: 0000043704-00-000004 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: GREEN MOUNTAIN POWER CORP CENTRAL INDEX KEY: 0000043704 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 030127430 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-08291 FILM NUMBER: 580710 BUSINESS ADDRESS: STREET 1: 163 ACORN LANE STREET 2: P.O.BOX 850 CITY: COLCHESTER STATE: VT ZIP: 05446 BUSINESS PHONE: 8028645731 MAIL ADDRESS: STREET 1: 25 GREEN MOUNTAIN DR STREET 2: P O BOX 850 CITY: SOUTH BURLINGTON STATE: VT ZIP: 05403 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K _X_ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 ___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION FILE NUMBER 1-8291 GREEN MOUNTAIN POWER CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) VERMONT 03-0127430 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) 163 ACORN LANE COLCHESTER, VT 05446 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (802) 864-5731 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED COMMON STOCK, PAR VALUE NEW YORK STOCK EXCHANGE $3.33-1/3 PER SHARE ________________________________________________________________________ SECURITIES REGISTERED PURSUANT TO SECTION 12 (G) OF THE ACT: NONE ________________________________________________________________________ INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES __X__ NO _____ INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. _X_ THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT AS OF MARCH 21, 2000, WAS APPROXIMATELY $44,492,259 BASED ON THE CLOSING PRICE OF $8.1875 FOR THE COMMON STOCK ON THE NEW YORK STOCK EXCHANGE AS REPORTED BY THE WALL STREET JOURNAL. THE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING ON MARCH 21, 2000, WAS 5,434,169. DOCUMENTS INCORPORATED BY REFERENCE THE COMPANY'S DEFINITIVE PROXY STATEMENT RELATING TO ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD ON MAY 18, 2000, TO BE FILED WITH THE COMMISSION PURSUANT TO REGULATION 14A UNDER THE SECURITIES EXCHANGE ACT OF 1934, IS INCORPORATED BY REFERENCE IN ITEMS 10, 11, 12 AND 13 OF PART III OF THIS FORM 10-K. 1 PART I ITEM 1. BUSINESS THE COMPANY GREEN MOUNTAIN POWER CORPORATION (THE COMPANY) IS A PUBLIC UTILITY OPERATING COMPANY ENGAGED IN SUPPLYING ELECTRICAL ENERGY IN THE STATE OF VERMONT IN A TERRITORY WITH APPROXIMATELY ONE QUARTER OF THE STATE'S POPULATION. WE SERVE APPROXIMATELY 84,000 CUSTOMERS. THE COMPANY WAS INCORPORATED UNDER THE LAWS OF THE STATE OF VERMONT ON APRIL 7, 1893. OUR SOURCES OF REVENUE FOR THE YEAR ENDED DECEMBER 31, 1999 WERE AS FOLLOWS: * 26.7% FROM RESIDENTIAL CUSTOMERS; * 27.1% FROM SMALL COMMERCIAL AND INDUSTRIAL CUSTOMERS; * 17.3% FROM LARGE COMMERCIAL AND INDUSTRIAL CUSTOMERS; * 27.2% FROM SALES TO OTHER UTILITIES; AND * 1.7% FROM OTHER SOURCES. DURING 1999, OUR ENERGY RESOURCES FOR RETAIL AND WHOLESALE SALES OF ELECTRICITY WERE OBTAINED AS FOLLOWS: * 43.0% FROM HYDROELECTRIC SOURCES (4.8% COMPANY-OWNED, 0.1% NEW YORK POWER AUTHORITY (NYPA), 35.7% HYDRO-QUEBEC AND 2.4% SMALL POWER PRODUCERS); * 30.3% FROM A NUCLEAR GENERATING SOURCE (THE VERMONT YANKEE NUCLEAR PLANT DESCRIBED BELOW); * 3.2% FROM WOOD; * 3.6% FROM NATURAL GAS; * 2.1% FROM OIL; AND * 0.6% FROM WIND. THE REMAINING 17.2% WAS PURCHASED ON A SHORT-TERM BASIS FROM OTHER UTILITIES THROUGH THE INDEPENDENT SYSTEM OPERATOR OF NEW ENGLAND (ISO), FORMERLY THE NEW ENGLAND POWER POOL (NEPOOL). IN 1999, WE PURCHASED 87.7% OF THE ENERGY REQUIRED TO SATISFY OUR RETAIL AND WHOLESALE SALES OF ELECTRICITY (INCLUDING ENERGY PURCHASED FROM VERMONT YANKEE AND UNDER OTHER LONG-TERM PURCHASE ARRANGEMENTS). SEE NOTE K OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. A MAJOR SOURCE OF THE COMPANY'S POWER SUPPLY IS OUR ENTITLEMENT TO A SHARE OF THE POWER GENERATED BY THE 531 MEGAWATT (MW) VERMONT YANKEE NUCLEAR GENERATING PLANT OWNED AND OPERATED BY VERMONT YANKEE NUCLEAR POWER CORPORATION (VERMONT YANKEE). WE HAVE A 17.9% EQUITY INTEREST IN VERMONT YANKEE. FOR INFORMATION CONCERNING VERMONT YANKEE, SEE POWER RESOURCES - VERMONT YANKEE. THE COMPANY PARTICIPATES IN NEPOOL, A REGIONAL BULK POWER TRANSMISSION ORGANIZATION ESTABLISHED TO ASSURE RELIABLE AND ECONOMICAL POWER SUPPLY IN THE NORTHEAST. AN INDEPENDENT SYSTEM OPERATOR IN NEW ENGLAND (THE "ISO") WAS CREATED TO MANAGE THE OPERATIONS OF NEPOOL IN 1999. THE ISO WORKS AS A CLEARINGHOUSE FOR PURCHASERS AND SELLERS OF ELECTRICITY IN THE NEW DEREGULATED MARKETS. SELLERS PLACE BIDS FOR THE SALE OF THEIR GENERATION OR PURCHASED POWER RESOURCES AND IF DEMAND IS HIGH ENOUGH THE OUTPUT FROM THOSE RESOURCES IS SOLD. WE MUST PURCHASE ADDITIONAL ELECTRICITY TO MEET CUSTOMER DEMAND DURING PERIODS OF HIGH USAGE AND TO REPLACE ENERGY REPURCHASED BY HYDRO-QUEBEC UNDER AN ARRANGEMENT NEGOTIATED IN 1997. OUR COSTS TO SERVE DEMAND DURING PERIODS OF WARMER THAN NORMAL TEMPERATURES IN SUMMER MONTHS AND TO REPLACE SUCH ENERGY REPURCHASES BY HYDRO-QUEBEC ROSE SUBSTANTIALLY AFTER THE MARKET OPENED TO COMPETITIVE BIDDING ON MAY 1, 1999. THE COST OF SECURING FUTURE POWER SUPPLIES HAS ALSO RISEN IN TANDEM WITH HIGHER SUMMER SUPPLY COSTS. THE COMPANY'S PRINCIPAL SERVICE TERRITORY IS AN AREA ROUGHLY 25 MILES IN WIDTH EXTENDING 90 MILES ACROSS NORTH CENTRAL VERMONT BETWEEN LAKE CHAMPLAIN ON THE WEST AND THE CONNECTICUT RIVER ON THE EAST. INCLUDED IN THIS TERRITORY ARE THE CITIES OF MONTPELIER, BARRE, SOUTH BURLINGTON, VERGENNES AND WINOOSKI, AS WELL AS THE VILLAGE OF ESSEX JUNCTION AND A NUMBER OF SMALLER TOWNS AND COMMUNITIES. WE ALSO DISTRIBUTE ELECTRICITY IN FOUR SEPARATE AREAS LOCATED IN SOUTHERN AND SOUTHEASTERN VERMONT THAT ARE INTERCONNECTED WITH OUR PRINCIPAL SERVICE AREA THROUGH THE TRANSMISSION LINES OF VELCO AND OTHERS. INCLUDED IN THESE AREAS ARE THE COMMUNITIES OF VERNON (WHERE THE VERMONT YANKEE PLANT IS LOCATED), BELLOWS FALLS, WHITE RIVER JUNCTION, WILDER, WILMINGTON AND DOVER. WE SUPPLY AT WHOLESALE A PORTION OF THE POWER REQUIREMENTS OF SEVERAL MUNICIPALITIES AND COOPERATIVES IN VERMONT. WE ARE OBLIGATED TO MEET THE CHANGING ELECTRICAL REQUIREMENTS OF THESE WHOLESALE CUSTOMERS, IN CONTRAST TO OUR OBLIGATION TO OTHER WHOLESALE CUSTOMERS, WHICH IS LIMITED TO SPECIFIED AMOUNTS OF CAPACITY AND ENERGY ESTABLISHED BY CONTRACT. 2 MAJOR BUSINESS ACTIVITIES IN OUR SERVICE AREAS INCLUDE COMPUTER ASSEMBLY AND COMPONENTS MANUFACTURING (AND OTHER ELECTRONICS MANUFACTURING), SOFTWARE DEVELOPMENT, GRANITE FABRICATION, SERVICE ENTERPRISES SUCH AS GOVERNMENT, INSURANCE, REGIONAL RETAIL SHOPPING AND TOURISM (PARTICULARLY WINTER RECREATION), AND DAIRY AND GENERAL FARMING. SEGMENT INFORMATION THE COMPANY HAS DECIDED TO SELL OR DISPOSE OF THE OPERATIONS AND ASSETS OF MOUNTAIN ENERGY, INC. (MEI). INDUSTRY SEGMENT INFORMATION REQUIRED TO BE DISCLOSED IS PRESENTED IN NOTE L OF THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, ANNUAL REPORT TO STOCKHOLDERS, 1999. SEASONAL NATURE OF BUSINESS WINTER RECREATIONAL ACTIVITIES, LONGER HOURS OF DARKNESS AND HEATING LOADS FROM COLD WEATHER USUALLY CAUSE OUR PEAK ELECTRIC SALES TO OCCUR IN DECEMBER, JANUARY OR FEBRUARY. OUR HEAVIEST LOAD IN 1999, 317.9 MW, OCCURRED ON DECEMBER 28, 1999. WE CHARGE OUR CUSTOMERS HIGHER RATES FOR BILLING CYCLES IN DECEMBER THROUGH MARCH AND LOWER RATES FOR THE REMAINING MONTHS. THESE ARE CALLED SEASONALLY DIFFERENTIATED RATES. IN ORDER TO ELIMINATE THE IMPACT OF THE SEASONALLY DIFFERENTIATED RATES ON EARNINGS, WE DEFER SOME OF THE REVENUES FROM THOSE FOUR MONTHS AND ACCOUNT FOR THEM IN LATER PERIODS IN WHICH WE HAVE LOWER REVENUES OR HIGHER COSTS. BY DEFERRING CERTAIN REVENUES WE ARE ABLE TO MATCH OUR REVENUES TO OUR COSTS MORE ACCURATELY. UNDER THIS STRUCTURE, RETAIL ELECTRIC RATES PRODUCE AVERAGE REVENUES PER KILOWATT-HOUR DURING FOUR PEAK SEASON MONTHS (DECEMBER THROUGH MARCH) THAT ARE APPROXIMATELY 30% HIGHER THAN DURING THE EIGHT OFF-SEASON MONTHS (APRIL THROUGH NOVEMBER). SEE ENERGY EFFICIENCY AND RATE DESIGN. SINGLE CUSTOMER DEPENDENCE OUR LARGEST CUSTOMER IS INTERNATIONAL BUSINESS MACHINES (IBM). ELECTRIC ENERGY SALES TO IBM FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997, ACCOUNTED FOR 11.8%, 14.7% AND 14.0%, RESPECTIVELY, OF OUR OPERATING REVENUES IN THOSE YEARS. THE PERCENTAGE DECREASE FROM 1998 TO 1999 REFLECTS THE IMPACT OF MS AGREEMENT TRANSACTIONS. REVENUES FROM IBM ACTUALLY INCREASED IN 1999. NO OTHER RETAIL CUSTOMER ACCOUNTED FOR MORE THAN 1.0% OF OUR REVENUE. UNDER THE PRESENT REGULATORY SYSTEM, THE LOSS OF IBM AS A CUSTOMER WOULD REQUIRE THE COMPANY TO SEEK RATE RELIEF TO RECOVER THE REVENUES PREVIOUSLY PAID BY IBM FROM OTHER CUSTOMERS IN AN AMOUNT SUFFICIENT TO OFFSET THE FIXED COSTS THAT IBM HAD BEEN COVERING THROUGH ITS PAYMENTS. SEE NOTES A AND K OF THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, ANNUAL REPORT TO STOCKHOLDERS, 1999. OPERATING STATISTICS FOR THE PAST FIVE YEARS ARE PRESENTED ON THE FOLLOWING TABLE. 3
GREEN MOUNTAIN POWER CORPORATION Operating Statistics For the years ended December 31, 1999 1998 1997 1996 1995 ----------- ----------- ----------- ----------- ----------- Total capability (MW) . . . . . . . . . . . . . . 393.2 396.9 416.9 425.8 396.1 Net system peak . . . . . . . . . . . . . . . . . 317.9 312.5 311.5 313.0 297.1 ----------- ----------- ----------- ----------- ----------- Reserve (MW). . . . . . . . . . . . . . . . . . . 75.3 84.4 105.4 112.8 99.0 =========== =========== =========== =========== =========== Reserve % of peak . . . . . . . . . . . . . . . . 23.7% 27.0% 33.8% 36.0% 33.3% Net Production (MWH**) Hydro . . . . . . . . . . . . . . . . . . . . . . 1,095,738 972,723 1,073,246 1,192,881 1,043,617 Wind. . . . . . . . . . . . . . . . . . . . . . . 7,956 - - - - Nuclear . . . . . . . . . . . . . . . . . . . . . 731,431 607,708 772,030 680,613 682,814 Conventional steam. . . . . . . . . . . . . . . . 2,328,267 750,602 560,504 705,331 673,982 Internal combustion . . . . . . . . . . . . . . . 12,312 40,148 4,827 2,674 6,646 Combined cycle. . . . . . . . . . . . . . . . . . 99,962 118,322 104,836 51,162 92,723 ----------- ----------- ----------- ----------- ----------- Total production. . . . . . . 4,275,666 2,489,503 2,515,443 2,632,662 2,499,782 Less non-firm sales to other utilities. . . . . . 2,152,781 499,409 524,192 663,175 582,942 ----------- ----------- ----------- ----------- ----------- Production for firm sales . . . . . . . . . . . . 2,122,885 1,990,094 1,991,251 1,969,487 1,916,840 Less firm sales and lease transmissions. . . . . 1,920,257 1,883,959 1,870,914 1,814,371 1,760,830 ----------- ----------- ----------- ----------- ----------- Losses and company use (MWH). . . . . . . . . . . 202,628 106,134 120,337 155,115 156,010 =========== =========== =========== =========== =========== Losses as a % of total production . . . . . . . . 4.74% 4.26% 4.78% 5.89% 6.24% System load factor (***). . . . . . . . . . . . . 80.3% 71.8% 71.6% 69.7% 71.2% Net Production (% of Total) Hydro . . . . . . . . . . . . . . . . . . . . . . 25.6% 39.1% 42.7% 45.3% 41.7% NYPA lease transmissions (Hydro). . . . . . . . . 0.2% 0.0% 0.0% 0.0% 0.0% Nuclear . . . . . . . . . . . . . . . . . . . . . 17.1% 24.4% 30.6% 25.9% 27.3% Conventional steam. . . . . . . . . . . . . . . . 54.5% 30.2% 22.3% 26.8% 27.0% Internal combustion . . . . . . . . . . . . . . . 0.3% 1.6% 0.2% 0.1% 0.3% Combined cycle. . . . . . . . . . . . . . . . . . 2.3% 4.8% 4.2% 1.9% 3.7% ----------- ----------- ----------- ----------- ----------- Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0% =========== =========== =========== =========== =========== Sales and Lease Transmissions(MWH) Residential - GMPC. . . . . . . . . . . . . . . . 544,447 533,904 549,259 557,726 549,296 Commercial & industrial - small . . . . . . . . . 688,493 665,707 645,331 630,838 608,688 Commercial & industrial - large . . . . . . . . . 664,110 636,436 608,051 584,249 556,278 Other . . . . . . . . . . . . . . . . . . . . . . 3,138 3,476 3,939 2,898 8,855 ----------- ----------- ----------- ----------- ----------- Total retail sales and lease transmissions. . . . 1,900,188 1,839,522 1,806,581 1,775,712 1,723,117 Sales to Municipals & Cooperatives (Rate W) . . . 20,069 44,437 64,333 38,660 37,713 ----------- ----------- ----------- ----------- ----------- Total Requirements Sales. . . . . . . . . . . . . 1,920,257 1,883,959 1,870,914 1,814,371 1,760,830 Other Sales for Resale. . . . . . . . . . . . . . 2,152,781 499,409 524,192 663,175 582,942 ----------- ----------- ----------- ----------- ----------- Total sales and lease transmissions(MWH) . . . . 4,073,038 2,383,368 2,395,106 2,477,546 2,343,772 =========== =========== =========== =========== =========== Average Number of Electric Customers Residential . . . . . . . . . . . . . . . . . . . 71,515 71,301 70,671 70,198 69,659 Commercial and industrial small . . . . . . . . . 12,438 12,170 11,989 11,828 11,712 Commercial and industrial large . . . . . . . . . 23 23 23 25 24 Other . . . . . . . . . . . . . . . . . . . . . . 66 70 75 75 76 ----------- ----------- ----------- ----------- ----------- Total. . . . . . . . . . . . . . . . 84,042 83,564 82,758 82,126 81,471 =========== =========== =========== =========== =========== Average Revenue Per KWH (Cents) Residential including lease revenues. . . . . . . 12.32 11.56 11.18 10.87 10.09 Lease charges . . . . . . . . . . . . . . . . . . 0.00 0.00 0.00 0.00 0.00 ----------- ----------- ----------- ----------- ----------- Residential including NYPA lease revenues . . . . 12.32 11.56 11.18 10.87 10.09 Commercial & industrial - small . . . . . . . . . 9.88 9.29 9.10 8.96 8.42 Commercial & industrial - large . . . . . . . . . 6.55 6.32 6.22 6.28 5.86 ----------- ----------- ----------- ----------- ----------- Total retail including lease. . . . . . . . . . . 9.47 8.96 8.79 8.72 8.08 =========== =========== =========== =========== =========== Average Use and Revenue Per Residential Customer KWh's including lease transmissions . . . . . . . 7,617 7,488 7,772 7,945 7,885 Revenues including lease revenues . . . . . . . . $ 938 $ 865 $ 869 $ 863 $ 796
(*) MW - Megawatt is one thousand kilowatts. (**) MWH - Megawatt hour is one thousand kilowatt hours. (***) Load factor is based on net system peak and firm MWH production less off-system losses. 4 EMPLOYEES AS OF DECEMBER 31, 1999, THE COMPANY HAD 196 EMPLOYEES, EXCLUSIVE OF TEMPORARY EMPLOYEES, AND OUR SUBSIDIARY, MOUNTAIN ENERGY INC., HAD FIVE EMPLOYEES. THE COMPANY CONSIDERS ITS RELATIONS WITH EMPLOYEES TO BE EXCELLENT. STATE AND FEDERAL REGULATION GENERAL. THE COMPANY IS SUBJECT TO THE REGULATORY AUTHORITY OF THE VERMONT PUBLIC SERVICE BOARD (VPSB), WHICH EXTENDS TO RETAIL RATES, SERVICES AND FACILITIES, SECURITIES ISSUES AND VARIOUS OTHER MATTERS. THE SEPARATE VERMONT DEPARTMENT OF PUBLIC SERVICE (THE DEPARTMENT), CREATED BY STATUTE IN 1981, IS RESPONSIBLE FOR DEVELOPMENT OF ENERGY SUPPLY PLANS FOR THE STATE OF VERMONT (THE STATE), PURCHASES OF POWER AS AN AGENT FOR THE STATE AND OTHER GENERAL REGULATORY MATTERS. THE VPSB PRINCIPALLY CONDUCTS QUASI-JUDICIAL PROCEEDINGS, SUCH AS RATE SETTING. THE DEPARTMENT, THROUGH A DIRECTOR FOR PUBLIC ADVOCACY, IS ENTITLED TO PARTICIPATE AS A LITIGANT IN SUCH PROCEEDINGS AND REGULARLY DOES SO. OUR RATE TARIFFS ARE UNIFORM THROUGHOUT OUR SERVICE AREA. WE HAVE ENTERED INTO A NUMBER OF JOBS INCENTIVE AGREEMENTS, PROVIDING FOR REDUCED CAPACITY CHARGES TO LARGE CUSTOMERS APPLICABLE ONLY TO NEW LOAD. WE HAVE AN ECONOMIC DEVELOPMENT AGREEMENT WITH IBM THAT PROVIDES FOR CONTRACTUALLY ESTABLISHED CHARGES, RATHER THAN TARIFF RATES, FOR INCREMENTAL LOADS. SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - RESULTS OF OPERATIONS - OPERATING REVENUES AND MWH SALES. OUR WHOLESALE RATE ON SALES TO TWO WHOLESALE CUSTOMERS IS REGULATED BY THE FEDERAL ENERGY REGULATORY COMMISSION (FERC). REVENUES FROM SALES TO THESE CUSTOMERS WERE LESS THAN 1% OF OPERATING REVENUES FOR 1999. LATE IN 1989, WE BEGAN SERVING A MUNICIPAL UTILITY, NORTHFIELD ELECTRIC DEPARTMENT, UNDER OUR WHOLESALE TARIFF. THIS CUSTOMER INCREASED OUR ELECTRICITY SALES IN 1999 BY APPROXIMATELY 17,540 MWH AND PEAK REQUIREMENTS BY APPROXIMATELY 5.5 MW. REVENUES IN 1999 FROM NORTHFIELD WERE $1,274,666. THE CONTRACT TO PURCHASE AND PROVIDE ENERGY, AND MAINTAIN RELATED PRODUCTION ASSETS, ENDED IN SEPTEMBER 1999. WE PROVIDE TRANSMISSION SERVICE TO TWELVE CUSTOMERS WITHIN THE STATE UNDER RATES REGULATED BY THE FERC; REVENUES FOR SUCH SERVICES AMOUNTED TO LESS THAN 1.0% OF THE COMPANY'S OPERATING REVENUES FOR 1999. ON APRIL 24, 1996, THE FEDERAL ENERGY REGULATORY COMMISSION (FERC) ISSUED ORDERS 888 AND 889 WHICH, AMONG OTHER THINGS, REQUIRED THE FILING OF OPEN ACCESS TRANSMISSION TARIFFS BY ELECTRIC UTILITIES, AND THE FUNCTIONAL SEPARATION BY UTILITIES OF THEIR TRANSMISSION OPERATIONS FROM POWER MARKETING OPERATIONS. ORDER 888 ALSO SUPPORTS THE FULL RECOVERY OF LEGITIMATE AND VERIFIABLE WHOLESALE POWER COSTS PREVIOUSLY INCURRED UNDER FEDERAL OR STATE REGULATION. ON JULY 17, 1997, THE FERC APPROVED OUR OPEN ACCESS TRANSMISSION TARIFF, AND ON AUGUST 30, 1997 WE FILED OUR COMPLIANCE REFUND REPORT. IN ACCORDANCE WITH ORDER 889, WE HAVE ALSO FUNCTIONALLY SEPARATED OUR TRANSMISSION OPERATIONS AND FILED WITH THE FERC A CODE OF CONDUCT FOR OUR TRANSMISSION OPERATIONS. WE DO NOT ANTICIPATE ANY MATERIAL ADVERSE EFFECTS OR LOSS OF WHOLESALE CUSTOMERS DUE TO THE FERC ORDERS MENTIONED ABOVE. THE OPEN ACCESS TARIFF COULD REDUCE THE AMOUNT OF CAPACITY AVAILABLE TO THE COMPANY FROM SUCH FACILITIES IN THE FUTURE. SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, TRANSMISSION ISSUES. THE COMPANY HAS EQUITY INTERESTS IN VERMONT YANKEE, VELCO AND VERMONT ELECTRIC TRANSMISSION COMPANY, INC. (VETCO), A WHOLLY OWNED SUBSIDIARY OF VELCO. WE HAVE FILED AN EXEMPTION STATEMENT UNDER SECTION 3(A)(2) OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, THEREBY SECURING EXEMPTION FROM THE PROVISIONS OF SUCH ACT, EXCEPT FOR SECTION 9(A)(2), WHICH PROHIBITS THE ACQUISITION OF SECURITIES OF CERTAIN OTHER UTILITY COMPANIES WITHOUT APPROVAL OF THE SECURITIES AND EXCHANGE COMMISSION (SEC). THE SEC HAS THE POWER TO INSTITUTE PROCEEDINGS TO TERMINATE SUCH EXEMPTION FOR CAUSE. LICENSING. PURSUANT TO THE FEDERAL POWER ACT, THE FERC HAS GRANTED LICENSES FOR THE FOLLOWING HYDRO-ELECTRIC PROJECTS OWNED BY THE COMPANY: 5
Issue Date Licensed Period ------------- --------------- Project Site: Bolton. . . . February 5,1982 February 5,1982 - February 4, 2022 Essex . . . . March 30, 1995 March 1, 1995 - March 1, 2025 Vergennes . . June 29, 1999 June 1, 1999 - May 31, 2029 Waterbury . . July 20, 1954 September 1, 1951 - August 31, 2001
MAJOR PROJECT LICENSES PROVIDE THAT AFTER AN INITIAL TWENTY-YEAR PERIOD, A PORTION OF THE EARNINGS OF SUCH PROJECT IN EXCESS OF A SPECIFIED RATE OF RETURN IS TO BE SET ASIDE IN APPROPRIATED RETAINED EARNINGS IN COMPLIANCE WITH FERC ORDER #5, ISSUED IN 1978. ALTHOUGH THE TWENTY-YEAR PERIODS EXPIRED IN 1985, 1969 AND 1971 IN THE CASES OF THE ESSEX, VERGENNES AND WATERBURY PROJECTS, RESPECTIVELY, THE AMOUNTS APPROPRIATED ARE NOT MATERIAL. THE RELICENSING APPLICATION FOR WATERBURY WAS FILED IN AUGUST 1999. THE COMPANY EXPECTS THE PROJECT TO BE RELICENSED FOR A 30 YEAR TERM IN THE NEAR FUTURE AND DOES NOT HAVE ANY COMPETITION FOR THE LICENSES. DEPARTMENT OF PUBLIC SERVICE TWENTY-YEAR ELECTRIC PLAN. IN DECEMBER 1994, THE DEPARTMENT ADOPTED AN UPDATE OF ITS TWENTY-YEAR ELECTRICAL POWER-SUPPLY PLAN (THE PLAN) FOR THE STATE. THE PLAN INCLUDES AN OVERVIEW OF STATEWIDE GROWTH AND DEVELOPMENT AS THEY RELATE TO FUTURE REQUIREMENTS FOR ELECTRICAL ENERGY; AN ASSESSMENT OF AVAILABLE ENERGY RESOURCES; AND ESTIMATES OF FUTURE ELECTRICAL ENERGY DEMAND. IN JUNE 1996, WE FILED WITH THE VPSB AND THE DEPARTMENT AN INTEGRATED RESOURCE PLAN PURSUANT TO VERMONT STATUTE 30 V.S.A. 218C. THAT FILING IS STILL PENDING BEFORE THE VPSB. RECENT RATE DEVELOPMENTS ON MAY 8, 1998, WE FILED A REQUEST WITH THE VPSB TO INCREASE RETAIL RATES BY 12.9 PERCENT. THE RETAIL RATE INCREASE WAS NEEDED TO COVER HIGHER POWER SUPPLY COSTS, THE COST OF THE JANUARY 1998 ICE STORM, HIGHER TAXES AND INVESTMENTS IN NEW PLANT AND EQUIPMENT. ON NOVEMBER 18, 1998, BY MEMORANDUM OF UNDERSTANDING (MOU), THE COMPANY, THE DEPARTMENT AND IBM AGREED TO: * IMPLEMENT A TEMPORARY RATE INCREASE OF 5.7 PERCENT, EFFECTIVE DECEMBER 15, 1998, WITH THE POTENTIAL FOR AN ADDITIONAL SURCHARGE IN ORDER TO PRODUCE ADDITIONAL REVENUES NECESSARY TO PROVIDE THE COMPANY WITH THE CAPACITY TO FINANCE ESTIMATED 1999 PINE STREET BARGE CANAL SITE EXPENDITURES OF $5.84 MILLION, AND * TO STAY, EFFECTIVE NOVEMBER 16, 1998, FURTHER RATE PROCEEDINGS IN THIS RATE CASE UNTIL OR AFTER SEPTEMBER 1, 1999, OR SUCH EARLIER DATE TO WHICH THE PARTIES MAY LATER AGREE OR THE VPSB MAY ORDER. ON SEPTEMBER 7 AND DECEMBER 17, 1999, (VPSB) ISSUED ORDERS APPROVING TWO AMENDMENTS TO THE MOU THAT THE COMPANY HAD ENTERED INTO WITH THE VERMONT DEPARTMENT OF PUBLIC SERVICE (THE DEPARTMENT OR DPS) AND IBM. THE TWO AMENDMENTS CONTINUED THE STAY OF PROCEEDINGS UNTIL SEPTEMBER 1, 2000, WITH A FINAL DECISION EXPECTED BY DECEMBER 31, 2000. THE AMENDMENTS MAINTAINED THE OTHER FEATURES OF THE ORIGINAL MOU, AND THE SECOND AMENDMENT PROVIDES FOR A TEMPORARY RATE INCREASE OF 3 PERCENT, IN ADDITION TO THE CURRENT TEMPORARY RATE LEVEL, TO BECOME EFFECTIVE AS OF JANUARY 1, 2000. THE TEMPORARY RATES ARE STILL SUBJECT TO REFUND IN THE FINAL RATE CASE DECISION, IF THE FINAL RATES SET ARE LOWER THAN THE TEMPORARY RATES. ONE PARTY TO THE RATE CASE, THE AMERICAN ASSOCIATION OF RETIRED PERSONS, (AARP), HAS FILED AN APPEAL TO THE VERMONT SUPREME COURT OF THE VPSB'S ORDER OF DECEMBER 17, 1999, ARGUING THAT THE VPSB SHOULD HAVE ORDERED THE COMPANY TO POST A BOND OR ESCROW FOR THE TEMPORARY RATE INCREASE. THE COMPANY HAS MOVED TO DISMISS THE APPEAL. FOR FURTHER INFORMATION REGARDING RECENT RATE DEVELOPMENTS, SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES, RATES, AND NOTE I OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. COMPETITION AND RESTRUCTURING ELECTRIC UTILITIES HISTORICALLY HAVE HAD EXCLUSIVE FRANCHISES FOR THE RETAIL SALE OF ELECTRICITY IN SPECIFIED SERVICE TERRITORIES. LEGISLATIVE AUTHORITY HAS EXISTED SINCE 1941 THAT WOULD PERMIT VERMONT CITIES, TOWNS AND VILLAGES TO OWN AND OPERATE PUBLIC UTILITIES. SINCE THAT TIME, NO MUNICIPALITY SERVED BY THE COMPANY HAS ESTABLISHED OR, AS FAR AS IS KNOWN TO THE COMPANY, IS PRESENTLY TAKING STEPS TO ESTABLISH A MUNICIPAL PUBLIC UTILITY. 6 IN 1987, THE VERMONT GENERAL ASSEMBLY ENACTED LEGISLATION THAT AUTHORIZED THE DEPARTMENT TO SELL ELECTRICITY ON A SIGNIFICANTLY EXPANDED BASIS. BEFORE THE NEW LAW WAS PASSED, THE DEPARTMENT'S AUTHORITY TO MAKE RETAIL SALES HAD BEEN LIMITED. IT COULD SELL AT RETAIL ONLY TO RESIDENTIAL AND FARM CUSTOMERS AND COULD SELL ONLY POWER THAT IT HAD PURCHASED FROM THE NIAGARA AND ST. LAWRENCE PROJECTS OPERATED BY THE NEW YORK POWER AUTHORITY. UNDER THE LAW, THE DEPARTMENT CAN SELL ELECTRICITY PURCHASED FROM ANY SOURCE AT RETAIL TO ALL CUSTOMER CLASSES THROUGHOUT THE STATE, BUT ONLY IF IT CONVINCES THE VPSB AND OTHER STATE OFFICIALS THAT THE PUBLIC GOOD WILL BE SERVED BY SUCH SALES. THE DEPARTMENT HAS MADE LIMITED ADDITIONAL RETAIL SALES OF ELECTRICITY. THE DEPARTMENT RETAINS ITS TRADITIONAL RESPONSIBILITIES OF PUBLIC ADVOCACY BEFORE THE VPSB AND ELECTRICITY PLANNING ON A STATEWIDE BASIS. IN CERTAIN STATES ACROSS THE COUNTRY, INCLUDING THE NEW ENGLAND STATES, LEGISLATION HAS BEEN ENACTED TO ALLOW RETAIL CUSTOMERS TO CHOOSE THEIR ELECTRICITY SUPPLIERS, WITH INCUMBENT UTILITIES REQUIRED TO DELIVER THAT ELECTRICITY OVER THEIR TRANSMISSION AND DISTRIBUTION SYSTEMS. INCREASED COMPETITIVE PRESSURE IN THE ELECTRIC UTILITY INDUSTRY MAY RESTRICT THE COMPANY'S ABILITY TO CHARGE ENERGY PRICES SUFFICIENT TO RECOVER EMBEDDED COSTS, SUCH AS THE COST OF PURCHASED POWER OBLIGATIONS OR OF GENERATION FACILITIES OWNED BY THE COMPANY. THE AMOUNT BY WHICH SUCH COSTS MIGHT EXCEED MARKET PRICES IS COMMONLY REFERRED TO AS STRANDED COSTS. REGULATORY AND LEGISLATIVE AUTHORITIES AT THE FEDERAL LEVEL AND IN SOME STATES, INCLUDING VERMONT WHERE LEGISLATION HAS NOT BEEN ENACTED, ARE CONSIDERING HOW TO FACILITATE COMPETITION FOR ELECTRICITY SALES. FOR FURTHER INFORMATION REGARDING COMPETITION AND RESTRUCTURING, SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - FUTURE OUTLOOK. POWER RESOURCES THE COMPANY HAS RENEWED A CONTRACT WITH MORGAN STANLEY CAPITAL GROUP, INC. AS THE RESULT OF OUR ALL POWER REQUIREMENTS SOLICITATION IN 1999. SEE NOTES I AND M OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. THE COMPANY GENERATED, PURCHASED OR TRANSMITTED 2,388,361 MWH OF ENERGY FOR RETAIL AND REQUIREMENTS WHOLESALE CUSTOMERS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1999. THE CORRESPONDING MAXIMUM ONE-HOUR INTEGRATED DEMAND DURING THAT PERIOD WAS 317.9 MW ON DECEMBER 28, 1999. THIS COMPARES TO THE ALL-TIME PEAK OF 322.6 MW ON DECEMBER 27, 1989. THE FOLLOWING TABLE SHOWS THE NET GENERATED AND PURCHASED ENERGY, THE SOURCE OF SUCH ENERGY FOR THE TWELVE-MONTH PERIOD AND THE CAPACITY IN THE MONTH OF THE PERIOD SYSTEM PEAK. SEE NOTE K OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 7
Net Electricity Generated and Purchased During year At time of Ended 12/31/99 of annual peak MWH percent KW percent --------------- --------------- ------- -------- Wholly-owned plants: Hydro . . . . . . . . . . . . . . 115,794 4.8% 35,300 9.0% Diesel and Gas Turbine. . . . . . 11,564 0.5% 46,200 11.7% Wind. . . . . . . . . . . . . . . 13,605 0.6% 850 0.2% Jointly-owned plants: Wyman #4. . . . . . . . . . . . . 20,426 0.8% 7,100 1.8% Stony Brook I . . . . . . . . . . 33,987 1.4% 31,000 7.9% McNeil. . . . . . . . . . . . . . 24,890 1.0% 6,600 1.7% Owned in association with Others: Vermont Yankee Nuclear. . . . . . 731,431 30.3% 95,680 24.3% Long Term Purchases: Hydro-Qubec . . . . . . . . . . . 861,657 35.7% 119,420 30.4% Stony Brook I . . . . . . . . . . 65,975 2.7% 14,150 3.6% Other: NYPA. . . . . . . . . . . . . . . 1,838 0.1% 250 0.1% Small Power Producers . . . . . . 115,906 4.8% 24,650 6.3% Short-term purchases. . . . . . . 417,208 17.3% 12,020 3.1% --------------- --------------- ------- -------- Total . . . . . . . . . . . . . . 2,414,281 393,220 Less system sales energy. . . . . (25,920) - --------------- --------------- Net Own Load. . . . . . . . . . . 2,388,361 100.00% 393,220 100.00% =============== =============== ======= ========
VERMONT YANKEE. ON OCTOBER 15, 1999, THE OWNERS OF VERMONT YANKEE NUCLEAR POWER CORPORATION ACCEPTED A BID FROM AMERGEN ENERGY COMPANY FOR THE VERMONT YANKEE GENERATING PLANT. THE ASSET SALE WILL REQUIRE NUMEROUS REGULATORY APPROVALS, INCLUDING THE FEDERAL ENERGY REGULATORY COMMISSION, THE NUCLEAR REGULATORY COMMISSION, THE SECURITIES AND EXCHANGE COMMISSION AND THE VPSB. ASSUMING A FINAL CLOSING DATE FOR THE TRANSACTION OF JULY 1, 2000, AMERGEN WILL PAY VERMONT YANKEE APPROXIMATELY $23.5 MILLION FOR THE PLANT AND PROPERTY. AS A CONDITION OF THE SALE, VERMONT YANKEE'S CURRENT OWNERS WILL MAKE A ONE-TIME AND FINAL PAYMENT OF $54.3 MILLION TO PRE-PAY THE PLANT'S DECOMMISSIONING FUND. IN RETURN, AMERGEN WILL ASSUME FULL RESPONSIBILITY FOR ALL FUTURE OPERATING COSTS AND THE OBLIGATION TO DECOMMISSION THE PLANT AT THE END OF ITS LIFE. THE COMPANY HAS AGREED TO BUY POWER FROM THE PLANT FOR PERIODS THAT MAY EXTEND UP TO TWELVE YEARS. THE COMPANY AND THE OTHER CURRENT OWNERS ARE ALSO RESPONSIBLE TO VERMONT YANKEE FOR THEIR SHARE OF THE UNRECOVERED PLANT AND OTHER COSTS RESULTING FROM THE SALE. THE COMPANY AND CENTRAL VERMONT PUBLIC SERVICE CORPORATION ACTED AS LEAD SPONSORS IN THE CONSTRUCTION OF THE VERMONT YANKEE NUCLEAR PLANT, A BOILING-WATER REACTOR DESIGNED BY GENERAL ELECTRIC COMPANY. THE PLANT, WHICH BECAME OPERATIONAL IN 1972, HAS A GENERATING CAPACITY OF 531 MW. VERMONT YANKEE HAS ENTERED INTO POWER CONTRACTS WITH ITS SPONSOR UTILITIES, INCLUDING THE COMPANY, THAT EXPIRE AT THE END OF THE LIFE OF THE UNIT. PURSUANT TO OUR POWER CONTRACT, WE ARE REQUIRED TO PAY 20% OF VERMONT YANKEE'S OPERATING EXPENSES (INCLUDING DEPRECIATION AND TAXES), FUEL COSTS (INCLUDING CHARGES IN RESPECT OF ESTIMATED COSTS OF DISPOSAL OF SPENT NUCLEAR FUEL), DECOMMISSIONING EXPENSES, INTEREST EXPENSE AND RETURN ON COMMON EQUITY, WHETHER OR NOT THE VERMONT YANKEE PLANT IS OPERATING. IN 1969, WE SOLD TO OTHER VERMONT UTILITIES A SHARE OF OUR ENTITLEMENT TO THE OUTPUT OF VERMONT YANKEE. ACCORDINGLY, THOSE UTILITIES HAVE AN OBLIGATION TO PAY US 2.338% OF VERMONT YANKEE'S OPERATING EXPENSES, FUEL COSTS, DECOMMISSIONING EXPENSES, INTEREST EXPENSE AND RETURN ON COMMON EQUITY, WHETHER OR NOT THE VERMONT YANKEE PLANT IS OPERATING. VERMONT YANKEE HAS ALSO ENTERED INTO CAPITAL FUNDS AGREEMENTS WITH ITS SPONSOR UTILITIES THAT EXPIRE ON DECEMBER 31, 2002. UNDER ITS CAPITAL FUNDS AGREEMENT, WE ARE REQUIRED, SUBJECT TO OBTAINING NECESSARY REGULATORY APPROVALS, TO PROVIDE 20% OF THE CAPITAL REQUIREMENTS OF VERMONT YANKEE NOT OBTAINED FROM OUTSIDE SOURCES. 8 IN DECEMBER 1996, AUGUST 1997 AND JULY 1998, DECISIONS WERE MADE TO RETIRE THREE NEW ENGLAND NUCLEAR UNITS, CONNECTICUT YANKEE, MAINE YANKEE AND MILLSTONE 1 EFFECTIVE IMMEDIATELY, WITH SEVERAL YEARS REMAINING ON EACH LICENSE. THE NRC'S MOST RECENTLY ISSUED SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE SCORES FOR VERMONT YANKEE ARE FOR THE PERIOD JANUARY 19, 1997 TO JULY 18, 1998. OPERATIONS, ENGINEERING, MAINTENANCE AND PLANT SUPPORT WERE RATED GOOD. THESE SCORES WERE IDENTICAL TO VERMONT YANKEE'S SCORES FOR THE PRIOR 18 MONTH-PERIOD EXCEPT FOR PLANT SUPPORT, WHICH DECLINED FROM SUPERIOR. DURING PERIODS WHEN VERMONT YANKEE POWER IS UNAVAILABLE, WE INCUR REPLACEMENT POWER COSTS IN EXCESS OF THOSE COSTS THAT WE WOULD HAVE INCURRED FOR POWER PURCHASED FROM VERMONT YANKEE. REPLACEMENT POWER IS AVAILABLE TO US FROM THE ISO AND THROUGH CONTRACTUAL ARRANGEMENTS WITH OTHER UTILITIES. REPLACEMENT POWER COSTS ADVERSELY AFFECT CASH FLOW AND, ABSENT DEFERRAL, AMORTIZATION AND RECOVERY THROUGH RATES, WOULD ADVERSELY AFFECT REPORTED EARNINGS. ROUTINELY, IN THE CASE OF SCHEDULED OUTAGES FOR REFUELING, THE VPSB HAS PERMITTED THE COMPANY TO DEFER, AMORTIZE AND RECOVER THESE EXCESS REPLACEMENT POWER COSTS FOR FINANCIAL REPORTING AND RATE MAKING PURPOSES OVER THE PERIOD UNTIL THE NEXT SCHEDULED OUTAGE. VERMONT YANKEE HAS ADOPTED AN 18-MONTH REFUELING SCHEDULE. THE 2000 REFUELING OUTAGE IS TENTATIVELY SCHEDULED TO BEGIN JUNE 2001, THOUGH IT MAY OCCUR EARLIER. IN THE CASE OF UNSCHEDULED OUTAGES OF SIGNIFICANT DURATION RESULTING IN SUBSTANTIAL UNANTICIPATED COSTS FOR REPLACEMENT POWER, THE VPSB GENERALLY HAS AUTHORIZED DEFERRAL, AMORTIZATION AND RECOVERY OF SUCH COSTS. VERMONT YANKEE'S CURRENT ESTIMATE OF COSTS TO DECOMMISSION THE PLANT, AS APPROVED BY FERC, IS APPROXIMATELY $430 MILLION, OF WHICH $247 MILLION HAS BEEN FUNDED. AT DECEMBER 31, 1999, OUR PORTION OF THE NET NON-FUNDED LIABILITY WAS $33 MILLION, WHICH WE EXPECT WILL BE RECOVERED THROUGH RATES OVER VERMONT YANKEE'S REMAINING OPERATING LIFE. VERMONT YANKEE'S CURRENT OPERATING LICENSE EXPIRES MARCH 2012. DURING THE YEAR ENDED DECEMBER 31, 1999, WE USED 731,431 MWH OF VERMONT YANKEE ENERGY TO MEET 30.3% OF OUR RETAIL AND REQUIREMENTS WHOLESALE (RATE W) SALES. THE AVERAGE COST OF VERMONT YANKEE ELECTRICITY IN 1999 WAS $0.051 PER KWH. VERMONT YANKEE'S ANNUAL CAPACITY FACTOR FOR 1999 WAS 90.9%, COMPARED TO 73.6% IN 1998 AND 93.5% IN 1997. THE 1999 CAPACITY FACTOR WAS THE BEST EVER FOR VERMONT YANKEE IN A YEAR THAT INCLUDED A REFUELING OUTAGE. SEE NOTE B OF THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, ANNUAL REPORT TO STOCKHOLDERS, 1999. HYDRO-QUEBEC HIGHGATE INTERCONNECTION. ON SEPTEMBER 23, 1985, THE HIGHGATE TRANSMISSION FACILITIES, WHICH WERE CONSTRUCTED TO IMPORT ENERGY FROM HYDRO-QUEBEC IN CANADA, BEGAN COMMERCIAL OPERATION. THE TRANSMISSION FACILITIES AT HIGHGATE INCLUDE A 225-MW AC-TO-DC-TO-AC CONVERTER TERMINAL AND SEVEN MILES OF 345-KV TRANSMISSION LINE. VELCO BUILT AND OPERATES THE CONVERTER FACILITIES, WHICH WE OWN JOINTLY WITH A NUMBER OF OTHER VERMONT UTILITIES. NEPOOL/HYDRO-QUEBEC INTERCONNECTION. VELCO AND CERTAIN OTHER NEPOOL MEMBERS HAVE ENTERED INTO AGREEMENTS WITH HYDRO-QUEBEC WHICH PROVIDED FOR THE CONSTRUCTION IN TWO PHASES OF A DIRECT INTERCONNECTION BETWEEN THE ELECTRIC SYSTEMS IN NEW ENGLAND AND THE ELECTRIC SYSTEM OF HYDRO-QUEBEC IN CANADA. THE VERMONT PARTICIPANTS IN THIS PROJECT, WHICH HAS A CAPACITY OF 2,000 MW, WILL DERIVE ABOUT 9.0% OF THE TOTAL POWER-SUPPLY BENEFITS ASSOCIATED WITH THE NEPOOL/HYDRO-QUEBEC INTERCONNECTION. THE COMPANY, IN TURN, RECEIVES ABOUT ONE-THIRD OF THE VERMONT SHARE OF THOSE BENEFITS. THE BENEFITS OF THE INTERCONNECTION INCLUDE: * ACCESS TO SURPLUS HYDROELECTRIC ENERGY FROM HYDRO-QUEBEC AT COMPETITIVE PRICES; * ENERGY BANKING, UNDER WHICH PARTICIPATING NEW ENGLAND UTILITIES WILL TRANSMIT RELATIVELY INEXPENSIVE ENERGY TO HYDRO-QUEBEC DURING OFF-PEAK PERIODS AND WILL RECEIVE EQUAL AMOUNTS OF ENERGY, AFTER ADJUSTMENT FOR TRANSMISSION LOSSES, FROM HYDRO-QUEBEC DURING PEAK PERIODS WHEN REPLACEMENT COSTS ARE HIGHER; AND * A PROVISION FOR EMERGENCY TRANSFERS AND MUTUAL BACKUP TO IMPROVE RELIABILITY FOR BOTH THE HYDRO-QUEBEC SYSTEM AND THE NEW ENGLAND SYSTEMS. PHASE I. THE FIRST PHASE (PHASE I) OF THE NEPOOL/HYDRO-QUEBEC INTERCONNECTION CONSISTS OF TRANSMISSION FACILITIES HAVING A CAPACITY OF 690 MW THAT TRAVERSE A PORTION OF EASTERN VERMONT AND EXTEND TO A CONVERTER TERMINAL LOCATED IN COMERFORD, NEW HAMPSHIRE. THESE FACILITIES ENTERED COMMERCIAL OPERATION ON OCTOBER 1, 1986. VETCO WAS ORGANIZED TO CONSTRUCT, OWN AND OPERATE THOSE PORTIONS OF THE TRANSMISSION FACILITIES LOCATED IN VERMONT. TOTAL CONSTRUCTION COSTS INCURRED BY VETCO FOR PHASE I WERE $47,850,000. OF THAT AMOUNT, VELCO PROVIDED $10,000,000 OF EQUITY CAPITAL TO VETCO THROUGH SALES OF VELCO PREFERRED STOCK TO THE VERMONT PARTICIPANTS IN THE PROJECT. THE COMPANY PURCHASED $3,100,000 OF VELCO PREFERRED STOCK TO FINANCE THE EQUITY PORTION OF PHASE I. THE REMAINING $37,850,000 OF CONSTRUCTION COST WAS FINANCED BY VETCO'S ISSUANCE OF $37,000,000 OF LONG-TERM DEBT IN THE FOURTH QUARTER OF 1986 AND THE BALANCE OF $850,000 WAS FINANCED BY SHORT-TERM DEBT. UNDER THE PHASE I CONTRACTS, EACH NEW ENGLAND PARTICIPANT, INCLUDING THE COMPANY, IS REQUIRED TO PAY MONTHLY ITS PROPORTIONATE SHARE OF VETCO'S TOTAL COST OF SERVICE, INCLUDING ITS CAPITAL COSTS. EACH PARTICIPANT ALSO PAYS A PROPORTIONATE SHARE OF THE TOTAL COSTS OF SERVICE ASSOCIATED WITH THOSE PORTIONS OF THE TRANSMISSION FACILITIES CONSTRUCTED IN NEW HAMPSHIRE BY A SUBSIDIARY OF NEW ENGLAND ELECTRIC SYSTEM. 9 PHASE II. AGREEMENTS EXECUTED IN 1985 AMONG THE COMPANY, VELCO AND OTHER NEPOOL MEMBERS AND HYDRO-QUEBEC PROVIDED FOR THE CONSTRUCTION OF THE SECOND PHASE (PHASE II) OF THE INTERCONNECTION BETWEEN THE NEW ENGLAND ELECTRIC SYSTEM AND THAT OF HYDRO-QUEBEC. PHASE II EXPANDED THE PHASE I FACILITIES FROM 690 MW TO 2,000 MW, AND PROVIDES FOR TRANSMISSION OF HYDRO-QUEBEC POWER FROM THE PHASE I TERMINAL IN NORTHERN NEW HAMPSHIRE TO SANDY POND, MASSACHUSETTS. CONSTRUCTION OF PHASE II COMMENCED IN 1988 AND WAS COMPLETED IN LATE 1990. THE PHASE II FACILITIES COMMENCED COMMERCIAL OPERATION NOVEMBER 1, 1990, INITIALLY AT A RATING OF 1,200 MW, AND INCREASED TO A TRANSFER CAPABILITY OF 2,000 MW IN JULY 1991. THE HYDRO-QUEBEC-NEPOOL FIRM ENERGY CONTRACT PROVIDES FOR THE IMPORT OF ECONOMICAL HYDRO-QUEBEC ENERGY INTO NEW ENGLAND. THE COMPANY IS ENTITLED TO 3.2% OF THE PHASE II POWER-SUPPLY BENEFITS. TOTAL CONSTRUCTION COSTS FOR PHASE II WERE APPROXIMATELY $487,000,000. THE NEW ENGLAND PARTICIPANTS, INCLUDING THE COMPANY, HAVE CONTRACTED TO PAY MONTHLY THEIR PROPORTIONATE SHARE OF THE TOTAL COST OF CONSTRUCTING, OWNING AND OPERATING THE PHASE II FACILITIES, INCLUDING CAPITAL COSTS. AS A SUPPORTING PARTICIPANT, THE COMPANY MUST MAKE SUPPORT PAYMENTS UNDER 30-YEAR AGREEMENTS. THESE SUPPORT AGREEMENTS MEET THE CAPITAL LEASE ACCOUNTING REQUIREMENTS UNDER SFAS 13. AT DECEMBER 31, 1999, THE PRESENT VALUE OF THE COMPANY'S OBLIGATION WAS APPROXIMATELY $7,038,000. THE COMPANY'S PROJECTED FUTURE MINIMUM PAYMENTS UNDER THE PHASE II SUPPORT AGREEMENTS ARE APPROXIMATELY $440,000 FOR EACH OF THE YEARS 2000-2004 AND AN AGGREGATE OF $4,838,000 FOR THE YEARS 2005-2020. THE PHASE II PORTION OF THE PROJECT IS OWNED BY NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC. AND NEW ENGLAND HYDRO-TRANSMISSION CORPORATION, SUBSIDIARIES OF NEW ENGLAND ELECTRIC SYSTEM, IN WHICH CERTAIN OF THE PHASE II PARTICIPATING UTILITIES, INCLUDING THE COMPANY, OWN EQUITY INTERESTS. THE COMPANY OWNS APPROXIMATELY 3.2% OF THE EQUITY OF THE CORPORATIONS OWNING THE PHASE II FACILITIES. DURING CONSTRUCTION OF THE PHASE II PROJECT, THE COMPANY, AS AN EQUITY SPONSOR, WAS REQUIRED TO PROVIDE EQUITY CAPITAL. AT DECEMBER 31, 1999, THE CAPITAL STRUCTURE OF SUCH CORPORATIONS WAS APPROXIMATELY 39% COMMON EQUITY AND 61% LONG-TERM DEBT. SEE NOTES B AND J OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. AT TIMES, WE REQUEST THAT PORTIONS OF OUR POWER DELIVERIES FROM HYDRO-QUEBEC AND OTHER SOURCES BE ROUTED THROUGH NEW YORK. OUR ABILITY TO DO SO COULD BE ADVERSELY AFFECTED BY THE PROPOSED TARIFF THAT NEPOOL HAS FILED WITH THE FERC, WHICH WOULD REDUCE OUR ALLOCATION OF CAPACITY ON TRANSMISSION INTERFACES WITH NEW YORK. AS A RESULT, OUR ABILITY TO IMPORT POWER TO VERMONT FROM OUTSIDE NEW ENGLAND COULD BE ADVERSELY AFFECTED, THEREBY IMPACTING OUR POWER COSTS IN THE FUTURE. SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - TRANSMISSION ISSUES AND NOTE J OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. HYDRO-QUEBEC POWER SUPPLY CONTRACTS. WE HAVE SEVERAL PURCHASE POWER CONTRACTS WITH HYDRO-QUEBEC. THE BULK OF OUR PURCHASES ARE COMPRISED OF TWO SCHEDULES, B AND C3, PURSUANT TO A FIRM CONTRACT DATED DECEMBER 1987. UNDER THESE TWO SCHEDULES, WE PURCHASE 114.2 MW. UNDER AN ARRANGEMENT NEGOTIATED IN JANUARY 1996, THE 96-01 AND THE 96-02 CONTRACTS, WE RECEIVED CASH PAYMENTS FROM HYDRO-QUEBEC OF $3,000,000 IN 1996 AND $1,100,000 IN 1997. IN ACCORDANCE WITH SUCH ARRANGEMENT, WE AGREED TO SHIFT CERTAIN TRANSMISSION REQUIREMENTS, PURCHASE CERTAIN QUANTITIES OF POWER AND MAKE CERTAIN MINIMUM PAYMENTS FOR PERIODS IN WHICH POWER IS NOT PURCHASED. IN ADDITION, IN NOVEMBER 1996, WE ENTERED INTO A MEMORANDUM OF UNDERSTANDING WITH HYDRO-QUEBEC UNDER WHICH HYDRO-QUEBEC PAID $8,000,000 TO THE COMPANY IN EXCHANGE FOR CERTAIN POWER PURCHASE OPTIONS. THE EXERCISE OF THESE OPTIONS IN 1999 RESULTED IN AN INCREASE OF APPROXIMATELY $5.4 MILLION TO POWER SUPPLY EXPENSE TO MEET CONTRACTUAL OBLIGATIONS UNDER THE COMPANY'S SELL-BACK AGREEMENT OF DECEMBER 1997 WITH HYDRO-QUEBEC SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - POWER SUPPLY EXPENSES, AND NOTES I, J AND K OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. IN 1999, WE USED 447,281 MWH UNDER SCHEDULE B, 310,094 MWH UNDER SCHEDULE C3, AND 104,282 MWH UNDER HQ 9601 AND 9602 TO MEET 35.7% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES. THE AVERAGE COST OF HYDRO-QUEBEC ELECTRICITY IN 1999 WAS $0.055 PER KWH. STONY BROOK I. THE MASSACHUSETTS MUNICIPAL WHOLESALE ELECTRIC COMPANY (MMWEC) IS PRINCIPAL OWNER AND OPERATOR OF STONY BROOK, A 352.0-MW COMBINED-CYCLE INTERMEDIATE GENERATING STATION LOCATED IN LUDLOW, MASSACHUSETTS, WHICH COMMENCED COMMERCIAL OPERATION IN NOVEMBER 1981. WE ENTERED INTO A JOINT OWNERSHIP AGREEMENT WITH MMWEC DATED AS OF OCTOBER 1, 1977, WHEREBY WE ACQUIRED AN 8.8% OWNERSHIP SHARE OF THE PLANT, ENTITLING US TO 31.0 MW OF CAPACITY. IN ADDITION TO THIS ENTITLEMENT, WE HAVE CONTRACTED FOR 14.2 MW OF CAPACITY FOR THE LIFE OF THE STONY BROOK I PLANT, FOR WHICH WE WILL PAY A PROPORTIONATE SHARE OF MMWEC'S SHARE OF THE PLANT'S FIXED COSTS AND VARIABLE OPERATING EXPENSES. THE THREE UNITS THAT COMPRISE STONY BROOK I ARE ALL CAPABLE OF BURNING OIL. TWO OF THE UNITS ARE ALSO CAPABLE OF BURNING NATURAL GAS. THE NATURAL GAS SYSTEM AT THE PLANT WAS MODIFIED IN 1985 TO ALLOW TWO UNITS TO OPERATE SIMULTANEOUSLY ON NATURAL GAS. DURING 1999, WE USED 99,962 MWH FROM THIS PLANT TO MEET 4.1% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.042 PER KWH. SEE NOTE I AND K OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 10 WYMAN UNIT #4. THE W. F. WYMAN UNIT #4, WHICH IS LOCATED IN YARMOUTH, MAINE, IS AN OIL-FIRED STEAM PLANT WITH A CAPACITY OF 620 MW. CENTRAL MAINE POWER COMPANY SPONSORED THE CONSTRUCTION OF THIS PLANT. WE HAVE A JOINT-OWNERSHIP SHARE OF 1.1% (7.1 MW) IN THE WYMAN #4 UNIT, WHICH BEGAN COMMERCIAL OPERATION IN DECEMBER 1978. DURING 1999, WE USED 20,426 MWH FROM THIS UNIT TO MEET 0.8% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.034 PER KWH, BASED ONLY ON OPERATION, MAINTENANCE, AND FUEL COSTS INCURRED DURING 1999. SEE NOTE I OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. MCNEIL STATION. THE J.C. MCNEIL STATION, WHICH IS LOCATED IN BURLINGTON, VERMONT, IS A WOOD CHIP AND GAS-FIRED STEAM PLANT WITH A CAPACITY OF 53.0 MW. WE HAVE AN 11.0% OR 5.8 MW INTEREST IN THE J. C. MCNEIL PLANT, WHICH BEGAN OPERATION IN JUNE 1984. IN 1989, THE PLANT ADDED THE CAPABILITY TO BURN NATURAL GAS ON AN AS-AVAILABLE/INTERRUPTIBLE SERVICE BASIS. DURING 1999, WE USED 24,890 MWH FROM THIS UNIT TO MEET 1.0% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.041 PER KWH, BASED ONLY ON OPERATION, MAINTENANCE, AND FUEL COSTS INCURRED DURING 1999. SEE NOTE I OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. INDEPENDENT POWER PRODUCERS. THE VPSB HAS ADOPTED RULES THAT IMPLEMENT FOR VERMONT THE PURCHASE REQUIREMENTS ESTABLISHED BY FEDERAL LAW IN THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 (PURPA). UNDER THE RULES, QUALIFYING FACILITIES HAVE THE OPTION TO SELL THEIR OUTPUT TO A CENTRAL STATE-PURCHASING AGENT UNDER A VARIETY OF LONG- AND SHORT-TERM, FIRM AND NON-FIRM PRICING SCHEDULES. EACH OF THESE SCHEDULES IS BASED UPON THE PROJECTED VERMONT COMPOSITE SYSTEM'S POWER COSTS THAT WOULD BE REQUIRED BUT FOR THE PURCHASES FROM INDEPENDENT PRODUCERS. THE STATE PURCHASING AGENT ASSIGNS THE ENERGY SO PURCHASED, AND THE COSTS OF PURCHASE, TO EACH VERMONT RETAIL ELECTRIC UTILITY BASED UPON ITS PRO RATA SHARE OF TOTAL VERMONT RETAIL ENERGY SALES. UTILITIES MAY ALSO CONTRACT DIRECTLY WITH PRODUCERS. THE RULES PROVIDE THAT ALL REASONABLE COSTS INCURRED BY A UTILITY UNDER THE RULES WILL BE INCLUDED IN THE UTILITIES' REVENUE REQUIREMENTS FOR RATE-MAKING PURPOSES. CURRENTLY, THE STATE PURCHASING AGENT, VERMONT ELECTRIC POWER PRODUCERS, INC. (VEPPI), IS AUTHORIZED TO SEEK 150 MW OF POWER FROM QUALIFYING FACILITIES UNDER PURPA, OF WHICH OUR AVERAGE PRO RATA SHARE IN 1999 WAS APPROXIMATELY 32.9% OR 49.3 MW. THE RATED CAPACITY OF THE QUALIFYING FACILITIES CURRENTLY SELLING POWER TO VEPPI IS APPROXIMATELY 74.5 MW. THESE FACILITIES WERE ALL ONLINE BY THE SPRING OF 1993, AND NO OTHER PROJECTS ARE UNDER DEVELOPMENT. WE DO NOT EXPECT ANY NEW PROJECTS TO COME ONLINE IN THE FORESEEABLE FUTURE BECAUSE THE EXCESS CAPACITY IN THE REGION HAS ELIMINATED THE NEED FOR AND VALUE OF ADDITIONAL QUALIFYING FACILITIES. IN 1999, THROUGH BOTH OUR DIRECT CONTRACTS AND VEPPI, WE PURCHASED 115,906 MWH OF QUALIFYING FACILITIES PRODUCTION TO MEET 4.8% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.113 PER KWH. SHORT TERM OPPORTUNITY PURCHASES AND SALES. WE HAVE ARRANGEMENTS WITH NUMEROUS UTILITIES AND POWER MARKETERS ACTIVELY TRADING POWER IN NEW ENGLAND AND NEW YORK UNDER WHICH WE MAY MAKE PURCHASES OR SALES OF POWER ON SHORT NOTICE AND GENERALLY FOR BRIEF PERIODS OF TIME WHEN IT APPEARS ECONOMIC TO DO SO. OPPORTUNITY PURCHASES ARE ARRANGED WHEN IT IS POSSIBLE TO PURCHASE POWER FOR LESS THAN IT WOULD COST US TO GENERATE THE POWER WITH OUR OWN SOURCES. PURCHASES ALSO HELP US SAVE ON REPLACEMENT POWER COSTS DURING AN OUTAGE OF ONE OF OUR BASE LOAD SOURCES. OPPORTUNITY SALES ARE ARRANGED WHEN WE HAVE SURPLUS ENERGY AVAILABLE AT A PRICE THAT IS ECONOMIC TO OTHER REGIONAL UTILITIES AT ANY GIVEN TIME. THE SALES ARE ARRANGED BASED ON FORECASTED COSTS OF SUPPLYING THE INCREMENTAL POWER NECESSARY TO SERVE THE SALE. PRICES ARE SET SO AS TO RECOVER ALL OF THE FORECASTED FUEL OR PRODUCTION COSTS AND TO RECOVER SOME, IF NOT ALL, ASSOCIATED CAPACITY COSTS. DURING 1999, WE PURCHASED 417,208 MWH, MEETING 17.3% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES, AT AN AVERAGE COST OF $0.049 PER KWH. COMPANY HYDROELECTRIC POWER. THE COMPANY WHOLLY OWNS AND OPERATES EIGHT HYDROELECTRIC GENERATING FACILITIES LOCATED ON RIVER SYSTEMS WITHIN ITS SERVICE AREA, THE LARGEST OF WHICH HAS A GENERATING OUTPUT OF 7.8 MW. IN 1999, THESE PLANTS PROVIDED 115,794 MWH OF LOW-COST ENERGY, MEETING 4.8% OF OUR RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.048 PER KWH BASED ON TOTAL EMBEDDED COSTS AND MAINTENANCE. SEE STATE AND FEDERAL REGULATION - LICENSING. 11 VELCO. THE COMPANY AND SIX OTHER VERMONT ELECTRIC DISTRIBUTION UTILITIES OWN VELCO. SINCE COMMENCING OPERATION IN 1958, VELCO HAS TRANSMITTED POWER FOR ITS OWNERS IN VERMONT, INCLUDING POWER FROM NYPA AND OTHER POWER CONTRACTED FOR BY VERMONT UTILITIES. VELCO ALSO PURCHASES BULK POWER FOR RESALE AT COST TO ITS OWNERS, AND AS A MEMBER OF NEPOOL, REPRESENTS ALL VERMONT ELECTRIC UTILITIES IN POOL ARRANGEMENTS AND TRANSACTIONS. SEE NOTE B OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. FUEL. DURING 1999, OUR RETAIL AND REQUIREMENTS WHOLESALE SALES WERE PROVIDED BY THE FOLLOWING FUEL SOURCES: * 43.0% FROM HYDRO (4.8% COMPANY-OWNED, 0.1% NYPA, 35.7% HYDRO-QUEBEC AND 2.4% FROM SMALL POWER PRODUCERS); * 30.3% FROM NUCLEAR; * 3.2% FROM WOOD; * 3.6% FROM NATURAL GAS; * 2.1% FROM OIL; * 0.6% FROM WIND; AND * 17.2% PURCHASED ON A SHORT-TERM BASIS FROM OTHER UTILITIES AND THROUGH NEPOOL AND ISO. VERMONT YANKEE HAS SEVERAL REQUIREMENT-BASED CONTRACTS FOR THE FOUR COMPONENTS (URANIUM, CONVERSION ENRICHMENT AND FABRICATION) USED TO PRODUCE NUCLEAR FUEL. THESE CONTRACTS ARE EXECUTED ONLY IF THE NEED OR REQUIREMENT FOR FUEL ARISES. UNDER THESE CONTRACTS, ANY DISRUPTION OF OPERATING ACTIVITY WOULD ALLOW VERMONT YANKEE TO CANCEL OR POSTPONE DELIVERIES UNTIL ACTUALLY REQUIRED. THE CONTRACTS EXTEND THROUGH VARIOUS TIME PERIODS AND CONTAIN CLAUSES TO ALLOW VERMONT YANKEE THE OPTION TO EXTEND THE AGREEMENTS. NEGOTIATION OF NEW CONTRACTS AND RENEGOTIATIONS OF EXISTING CONTRACTS ROUTINELY OCCURS, OFTEN FOCUSING ON ONE OF THE FOUR COMPONENTS AT A TIME. THE 1999 RELOAD COST APPROXIMATELY $20.8 MILLION. FUTURE RELOAD COSTS WILL DEPEND ON MARKET AND CONTRACT PRICES ON JANUARY 20, 1997, VERMONT YANKEE ENTERED INTO AN AGREEMENT WITH A FORMER URANIUM SUPPLIER WHEREBY THE SUPPLIER COULD OPT TO TERMINATE A PRODUCTION PURCHASE AGREEMENT DATED AUGUST 4, 1978. ALTHOUGH THERE HAD BEEN NO TRANSACTIONS UNDER THE PRODUCTION PURCHASE AGREEMENT FOR SEVERAL YEARS, VERMONT YANKEE MAINTAINED CERTAIN FINANCIAL RIGHTS. IN CONSIDERATION FOR THE OPTION TO TERMINATE THE PRODUCTION PURCHASE AGREEMENT AND THE SUBSEQUENT EXERCISE OF THE OPTION, VERMONT YANKEE RECEIVED $600,000 IN 1997, WHICH WAS RECORDED AS AN OFFSET TO NUCLEAR FUEL EXPENSE. THE POTENTIAL FUTURE PAYMENTS OVER A TEN-YEAR PERIOD RANGE FROM ZERO TO $2.4 MILLION. NO PAYMENTS WERE RECEIVED IN 1999 UNDER THIS AGREEMENT. DUE TO THE UNCERTAINTY OF THIS TRANSACTION, ANY BENEFITS RECEIVED WILL BE RECORDED ON A CASH BASIS. VERMONT YANKEE HAS A CONTRACT WITH THE UNITED STATES DEPARTMENT OF ENERGY (DOE) FOR THE PERMANENT DISPOSAL OF SPENT NUCLEAR FUEL. UNDER THE TERMS OF THIS CONTRACT, IN EXCHANGE FOR THE ONE-TIME FEE DISCUSSED BELOW AND A QUARTERLY FEE OF 1 MIL PER KWH OF ELECTRICITY GENERATED AND SOLD, THE DOE AGREES TO PROVIDE DISPOSAL SERVICES WHEN A FACILITY FOR SPENT NUCLEAR FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE IS AVAILABLE, WHICH IS REQUIRED BY CONTRACT TO BE PRIOR TO JANUARY 31, 1998. THE ACTUAL DATE FOR THESE DISPOSAL SERVICES IS EXPECTED TO BE DELAYED MANY YEARS. DOE CURRENTLY ESTIMATES THAT A PERMANENT DISPOSAL FACILITY WILL NOT BEGIN OPERATION BEFORE 2010. A DOE TEMPORARY DISPOSAL SITE MAY BE PROVIDED IN A FEW YEARS, BUT NO DECISION HAS BEEN MADE TO PROCEED ON PROVIDING A TEMPORARY DISPOSAL SITE AT THIS TIME. THE DOE CONTRACT OBLIGATES VERMONT YANKEE TO PAY A ONE-TIME FEE OF APPROXIMATELY $39.3 MILLION FOR DISPOSAL COSTS FOR ALL SPENT FUEL DISCHARGED THROUGH APRIL 7, 1983. ALTHOUGH SUCH AMOUNT HAS BEEN COLLECTED IN RATES FROM THE VERMONT YANKEE PARTICIPANTS, VERMONT YANKEE HAS ELECTED TO DEFER PAYMENT OF THE FEE TO THE DOE AS PERMITTED BY THE DOE CONTRACT. THE FEE MUST BE PAID NO LATER THAN THE FIRST DELIVERY OF SPENT NUCLEAR FUEL TO THE DOE. INTEREST ACCRUES ON THE UNPAID OBLIGATION BASED ON THE THIRTEEN-WEEK TREASURY BILL RATE AND IS COMPOUNDED QUARTERLY. THROUGH 1999 VERMONT YANKEE ACCUMULATED APPROXIMATELY $102.2 MILLION IN AN IRREVOCABLE TRUST TO BE USED EXCLUSIVELY FOR SETTLING THIS OBLIGATION AT SOME FUTURE DATE, PROVIDED THE DOE COMPLIES WITH THE TERMS OF THE AFOREMENTIONED CONTRACT. WE DO NOT MAINTAIN LONG-TERM CONTRACTS FOR THE SUPPLY OF OIL FOR OUR WHOLLY-OWNED OIL-FIRED PEAK GENERATING STATIONS (80 MW). WE DID NOT EXPERIENCE DIFFICULTY IN OBTAINING OIL FOR OUR OWN UNITS DURING 1999, AND, WHILE NO ASSURANCE CAN BE GIVEN, WE DO NOT ANTICIPATE ANY SUCH DIFFICULTY DURING 2000. NONE OF THE UTILITIES FROM WHICH WE EXPECT TO PURCHASE OIL- OR GAS-FIRED CAPACITY IN 1999 HAS ADVISED US OF GROUNDS FOR DOUBT ABOUT MAINTENANCE OF SECURE SOURCES OF OIL AND GAS DURING THE YEAR. WOOD FOR THE MCNEIL PLANT IS FURNISHED TO THE BURLINGTON ELECTRIC DEPARTMENT FROM A VARIETY OF SOURCES UNDER SHORT-TERM CONTRACTS RANGING FROM SEVERAL WEEKS' TO SIX MONTHS' DURATION. THE MCNEIL PLANT USED 291,002 TONS OF WOOD CHIPS AND MILL RESIDUE AND 220.9 MILLION CUBIC FEET OF NATURAL GAS IN 1999. THE MCNEIL PLANT, ASSUMING ANY NEEDED REGULATORY APPROVALS ARE OBTAINED, IS FORECASTING YEAR 2000 CONSUMPTION OF WOOD CHIPS TO BE 300,000 TONS AND NATURAL GAS CONSUMPTION OF 600 MILLION CUBIC FEET. THE STONY BROOK COMBINED-CYCLE GENERATING STATION IS CAPABLE OF BURNING EITHER NATURAL GAS OR OIL IN TWO OF ITS TURBINES. NATURAL GAS IS SUPPLIED TO THE PLANT SUBJECT TO ITS AVAILABILITY. DURING PERIODS OF EXTREMELY COLD WEATHER, THE SUPPLIER RESERVES THE RIGHT TO DISCONTINUE DELIVERIES TO THE PLANT IN ORDER TO SATISFY THE DEMAND OF ITS RESIDENTIAL CUSTOMERS. WE ASSUME, FOR PLANNING AND BUDGETING PURPOSES, THAT THE PLANT WILL BE SUPPLIED WITH GAS DURING THE MONTHS OF APRIL THROUGH NOVEMBER, AND THAT IT WILL RUN SOLELY ON OIL DURING THE MONTHS OF DECEMBER THROUGH MARCH. THE PLANT MAINTAINS AN OIL SUPPLY SUFFICIENT TO MEET APPROXIMATELY ONE-HALF OF ITS ANNUAL NEEDS. 12 WIND PROJECT. THE COMPANY WAS SELECTED BY THE UNITED STATES DEPARTMENT OF ENERGY (DOE) AND THE ELECTRIC POWER RESEARCH INSTITUTE (EPRI) TO BUILD A COMMERCIAL SCALE WIND-POWERED FACILITY. THE DOE AND EPRI PROVIDED PARTIAL FUNDING FOR THE WIND PROJECT OF APPROXIMATELY $3.9 MILLION. THE NET COST TO THE COMPANY OF THE PROJECT, LOCATED IN THE SOUTHERN VERMONT TOWN OF SEARSBURG, WAS $7.8 MILLION. THE ELEVEN WIND TURBINES HAVE A RATING OF 6 MW AND WERE COMMISSIONED JULY 1, 1997. IN 1999, THE PLANT PROVIDED 13,605 MWH, MEETING 0.6% OF THE COMPANY'S RETAIL AND REQUIREMENTS WHOLESALE SALES AT AN AVERAGE COST OF $0.07 PER KWH. ENERGY EFFICIENCY IN 1999, GMP CONTINUED TO FOCUS ITS ENERGY EFFICIENCY SERVICES ON PROGRAMS THAT ENCOURAGED CUSTOMERS TO INSTALL ENERGY EFFICIENT EQUIPMENT WHEN THEY ARE PLANNING TO REPLACE OR BUY NEW EQUIPMENT RATHER THAN ATTEMPTING TO CONVINCE THEM TO REPLACE EQUIPMENT THAT IS STILL IN GOOD WORKING ORDER. THIS STRATEGY, ALONG WITH CAREFUL MANAGEMENT, HAS HELPED US TO DROP OUR COST-PER-LIFETIME-KILOWATT-HOUR SAVED TO 1.4 CENTS, WHICH IS A 70% REDUCTION IN COSTS SINCE 1992. IN 1999, OUR ENERGY EFFICIENCY PROGRAMS SAVED APPROXIMATELY 9,400 MEGAWATTHOURS, 13% ABOVE TARGETED SAVINGS FOR THE YEAR. DURING THE PAST EIGHT YEARS OUR EFFICIENCY PROGRAMS HAVE ACHIEVED A CUMULATIVE ANNUAL SAVINGS OF 88,600 MEGAWATTHOURS, SAVING APPROXIMATELY $7.85 MILLION PER YEAR FOR OUR CUSTOMERS. IN 1999, WE SPENT APPROXIMATELY $1.7 MILLION ON ENERGY EFFICIENCY PROGRAMS, APPROXIMATELY .7% OF OUR OPERATING REVENUE IN 1999. A STATEWIDE ENERGY EFFICIENCY UTILITY (EEU) WAS CREATED BY THE VPSB IN 1999 TO MANAGE ENERGY EFFICIENCY PROGRAMS FOR ALL UTILITIES IN VERMONT. THE COMPANY'S CUSTOMERS ARE NOW BILLED A SEPARATE EEU CHARGE THAT WE REMIT DIRECTLY TO THE EEU. RATE DESIGN THE COMPANY SEEKS TO DESIGN RATES TO ENCOURAGE THE SHIFTING OF ELECTRICAL USE FROM PEAK HOURS TO OFF-PEAK HOURS. SINCE 1976, WE HAVE OFFERED OPTIONAL TIME-OF-USE RATES FOR RESIDENTIAL AND COMMERCIAL CUSTOMERS. CURRENTLY, APPROXIMATELY 2,160 OF THE COMPANY'S RESIDENTIAL CUSTOMERS CONTINUE TO BE BILLED ON THE ORIGINAL 1976 TIME-OF-USE RATE BASIS. IN 1987, THE COMPANY RECEIVED REGULATORY APPROVAL FOR A RATE DESIGN THAT PERMITTED IT TO CHARGE PRICES FOR ELECTRIC SERVICE THAT REFLECTED AS ACCURATELY AS POSSIBLE THE COST BURDEN IMPOSED BY EACH CUSTOMER CLASS. THE COMPANY'S RATE DESIGN OBJECTIVES ARE TO PROVIDE A STABLE PRICING STRUCTURE AND TO ACCURATELY REFLECT THE COST OF PROVIDING ELECTRIC SERVICES. THIS RATE STRUCTURE HELPS TO ACHIEVE THESE GOALS. SINCE INEFFICIENT USE OF ELECTRICITY INCREASES ITS COST, CUSTOMERS WHO ARE CHARGED PRICES THAT REFLECT THE COST OF PROVIDING ELECTRICAL SERVICE HAVE REAL INCENTIVES TO FOLLOW THE MOST EFFICIENT USAGE PATTERNS. INCLUDED IN THE VPSB'S ORDER APPROVING THIS RATE DESIGN WAS A REQUIREMENT THAT THE COMPANY'S LARGEST CUSTOMERS BE CHARGED TIME-OF-USE RATES ON A PHASED-IN BASIS BY 1994. AT DECEMBER 31, 1999, APPROXIMATELY 1,365 OF THE COMPANY'S LARGEST CUSTOMERS, COMPRISING 52% OF RETAIL REVENUES, CONTINUE TO RECEIVE SERVICE ON MANDATORY TIME-OF-USE RATES. IN MAY 1994, THE COMPANY FILED ITS CURRENT RATE DESIGN WITH THE VPSB. THE PARTIES, INCLUDING THE DEPARTMENT, IBM AND A LOW-INCOME ADVOCACY GROUP, ENTERED INTO A SETTLEMENT THAT WAS APPROVED BY THE VPSB ON DECEMBER 2, 1994. UNDER THE SETTLEMENT, THE REVENUE ALLOCATION TO EACH RATE CLASS WAS ADJUSTED TO REFLECT CLASS-BY-CLASS COST CHANGES SINCE 1987, THE DIFFERENTIAL BETWEEN THE WINTER AND SUMMER RATES WAS REDUCED, THE CUSTOMER CHARGE WAS INCREASED FOR MOST CLASSES, AND USAGE CHARGES WERE ADJUSTED TO BE CLOSER TO THE ASSOCIATED MARGINAL COSTS. NO MODIFICATIONS TO BASE RATE REDESIGN HAVE TAKEN PLACE SINCE THE VPSB ORDER ISSUED ON DECEMBER 2, 1994. DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS IN 1999, WE HAD INTERRUPTIBLE/DISPATCHABLE POWER CONTRACTS WITH TWO MAJOR SKI AREAS AND DISPATCHABLE-ONLY CONTRACTS WITH AN ADDITIONAL TWENTY-SIX CUSTOMERS. THE INTERRUPTIBLE PORTION OF THE CONTRACTS ALLOWS THE COMPANY TO CONTROL POWER SUPPLY CAPACITY CHARGES BY REDUCING OUR CAPACITY REQUIREMENTS. DURING 1999, WE DID NOT REQUEST ANY INTERRUPTIONS DUE TO THE SURPLUS CAPACITY IN THE REGION. THE DISPATCHABLE PORTION OF THE CONTRACTS ALLOWS CUSTOMERS TO PURCHASE ELECTRICITY DURING TIMES DESIGNATED BY THE COMPANY WHEN LOW COST POWER IS AVAILABLE. THE CUSTOMER'S DEMAND DURING THESE PERIODS IS NOT CONSIDERED IN CALCULATING THE MONTHLY BILLING. THIS PROGRAM ENABLES THE COMPANY AND THE CUSTOMERS TO BENEFIT FROM LOAD CONTROL. WE SHIFT LOAD FROM OUR HIGH COST PEAK PERIODS AND THE CUSTOMER USES INEXPENSIVE POWER AT A TIME WHEN ITS USE PROVIDES MAXIMUM VALUE. THESE PROGRAMS ARE AVAILABLE BY TARIFF FOR QUALIFYING CUSTOMERS. 13 CONSTRUCTION AND CAPITAL REQUIREMENTS OUR CAPITAL EXPENDITURES FOR 1997 THROUGH 1999 AND PROJECTION FOR 2000 ARE SET FORTH IN ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES-CONSTRUCTION. CONSTRUCTION PROJECTIONS ARE SUBJECT TO CONTINUING REVIEW AND MAY BE REVISED FROM TIME-TO-TIME IN ACCORDANCE WITH CHANGES IN THE COMPANY'S FINANCIAL CONDITION, LOAD FORECASTS, THE AVAILABILITY AND COST OF LABOR AND MATERIALS, LICENSING AND OTHER REGULATORY REQUIREMENTS, CHANGING ENVIRONMENTAL STANDARDS AND OTHER RELEVANT FACTORS. FOR THE PERIOD 1997-1999, INTERNALLY GENERATED FUNDS, AFTER PAYMENT OF DIVIDENDS, PROVIDED APPROXIMATELY 80 PERCENT OF TOTAL CAPITAL REQUIREMENTS FOR CONSTRUCTION, SINKING FUND OBLIGATIONS AND OTHER REQUIREMENTS. INTERNALLY GENERATED FUNDS PROVIDED 87 PERCENT OF SUCH REQUIREMENTS FOR 1999. WE ANTICIPATE THAT FOR 2000, INTERNALLY GENERATED FUNDS WILL PROVIDE APPROXIMATELY 90 PERCENT OF TOTAL CAPITAL REQUIREMENTS FOR REGULATED OPERATIONS, THE REMAINDER TO BE DERIVED FROM BANK LOANS. IN CONNECTION WITH THE FOREGOING, SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES. ENVIRONMENTAL MATTERS WE HAD BEEN NOTIFIED BY THE ENVIRONMENTAL PROTECTION AGENCY (EPA) THAT WE WERE ONE OF SEVERAL POTENTIALLY RESPONSIBLE PARTIES FOR CLEAN UP AT THE PINE STREET BARGE CANAL SITE IN BURLINGTON, VERMONT. IN SEPTEMBER 1999, WE NEGOTIATED A FINAL SETTLEMENT WITH THE UNITED STATES, THE STATE OF VERMONT, AND OTHER PARTIES OVER TERMS OF A CONSENT DECREE THAT COVERS CLAIMS ADDRESSED IN EARLIER NEGOTIATIONS AND IMPLEMENTATION OF THE SELECTED REMEDY. IN OCTOBER 1999, THE FEDERAL DISTRICT COURT APPROVED THE CONSENT DECREE THAT ADDRESSES CLAIMS BY THE EPA FOR PAST PINE STREET BARGE CANAL SITE COSTS, NATURAL RESOURCE DAMAGE CLAIMS AND CLAIMS FOR PAST AND FUTURE OVERSIGHT COSTS. THE CONSENT DECREE ALSO PROVIDES FOR THE DESIGN AND IMPLEMENTATION OF RESPONSE ACTIONS AT THE SITE. FOR INFORMATION REGARDING THE PINE STREET CANAL SITE AND OTHER ENVIRONMENTAL MATTERS SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ENVIRONMENTAL MATTERS, AND NOTE I OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. UNREGULATED BUSINESSES IN 1998, WE SOLD THE ASSETS OF OUR WHOLLY OWNED SUBSIDIARY, GREEN MOUNTAIN PROPANE GAS COMPANY. IN 1999, GREEN MOUNTAIN RESOURCES, INC. SOLD ITS REMAINING INTEREST IN GREEN MOUNTAIN ENERGY RESOURCES TO GREEN FUNDING I. FOR INFORMATION REGARDING OUR REMAINING UNREGULATED BUSINESSES, SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS- FUTURE OUTLOOK - UNREGULATED BUSINESSES. 14 EXECUTIVE OFFICERS THE EXECUTIVE OFFICERS NAMES, AGES, AND POSITIONS OF THE COMPANY AS OF MARCH 15, 2000 ARE: NANCY ROWDEN BROCK 44 VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND TREASURER SINCE DECEMBER 1998, AND SECRETARY SINCE AUGUST 1999. CHIEF CORPORATE STRATEGIC PLANNING OFFICER FROM MARCH 1998 TO DECEMBER 1998. PRIOR TO JOINING THE COMPANY, SHE WAS CHIEF FINANCIAL OFFICER OF SAL, INC., 1997; AND SENIOR VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND TREASURER FOR THE CHITTENDEN CORPORATION FROM 1988 TO 1996. CHRISTOPHER L. DUTTON 51 PRESIDENT, CHIEF EXECUTIVE OFFICER OF THE COMPANY AND CHAIRMAN OF THE EXECUTIVE COMMITTEE OF THE CORPORATION SINCE AUGUST 1997. VICE PRESIDENT, FINANCE AND ADMINISTRATION, CHIEF FINANCIAL OFFICER AND TREASURER FROM 1995 TO 1997. VICE PRESIDENT AND GENERAL COUNSEL FROM 1993 TO JANUARY 1995. VICE PRESIDENT, GENERAL COUNSEL AND CORPORATE SECRETARY FROM 1989 TO 1993. ROBERT J. GRIFFIN 43 CONTROLLER SINCE OCTOBER 1996. MANAGER OF GENERAL ACCOUNTING FROM 1990 TO 1996. WALTER S. OAKES 53 VICE PRESIDENT-FIELD OPERATIONS SINCE AUGUST 1999. ASSISTANT VICE PRESIDENT-CUSTOMER OPERATIONS FROM JUNE 1994 TO AUGUST 1999. ASSISTANT VICE PRESIDENT, HUMAN RESOURCES FROM AUGUST 1993 TO JUNE 1994. ASSISTANT VICE PRESIDENT-CORPORATE SERVICES FROM 1988 TO 1993. MARY G. POWELL 39 SENIOR VICE PRESIDENT-CUSTOMER AND ORGANIZATIONAL DEVELOPMENT SINCE DECEMBER 1999. VICE PRESIDENT-ADMINISTRATION FROM FEBRUARY 1999 THROUGH DECEMBER 1999. VICE PRESIDENT, HUMAN RESOURCES AND ORGANIZATIONAL DEVELOPMENT FROM MARCH 1998 TO FEBRUARY 1999. PRIOR TO JOINING THE COMPANY, SHE WAS PRESIDENT OF HRWORKS, A HUMAN RESOURCES MANAGEMENT FIRM, FROM JANUARY 1997 TO MARCH 1998. FROM 1992 TO JANUARY 1997 SHE WORKED FOR KEYCORP IN VERMONT, MOST RECENTLY AS SENIOR VICE PRESIDENT COMMUNITY BANKING. AT KEYCORP SHE ALSO SERVED AS VICE PRESIDENT ADMINISTRATION AND VICE PRESIDENT OF HUMAN RESOURCES. STEPHEN C. TERRY 57 SENIOR VICE PRESIDENT-GOVERNMENT AND LEGAL RELATIONS SINCE AUGUST 1999. SENIOR VICE PRESIDENT, CORPORATE DEVELOPMENT FROM AUGUST 1997 TO AUGUST 1999. VICE PRESIDENT AND GENERAL MANAGER, RETAIL ENERGY SERVICES FROM 1995 TO 1997. VICE PRESIDENT-EXTERNAL AFFAIRS FROM 1991 TO JANUARY 1995. JONATHAN H. WINER 48 PRESIDENT OF MOUNTAIN ENERGY, INC. SINCE MARCH 1997. VICE PRESIDENT AND CHIEF OPERATING OFFICER OF MOUNTAIN ENERGY, INC. FROM 1989 TO MARCH 1997. OFFICERS ARE ELECTED BY THE BOARD OF DIRECTORS OF THE COMPANY AND ITS WHOLLY-OWNED SUBSIDIARIES, AS APPROPRIATE, FOR ONE-YEAR TERMS AND SERVE AT THE PLEASURE OF SUCH BOARDS OF DIRECTORS. ITEM 2. PROPERTY GENERATING FACILITIES OUR VERMONT PROPERTIES ARE LOCATED IN FIVE AREAS AND ARE INTERCONNECTED BY TRANSMISSION LINES OF VELCO AND NEW ENGLAND POWER COMPANY. WE WHOLLY OWN AND OPERATE EIGHT HYDROELECTRIC GENERATING STATIONS WITH A TOTAL NAMEPLATE RATING OF 36.1 MW AND AN ESTIMATED CLAIMED CAPABILITY OF 35.7 MW. WE ALSO OWN TWO GAS-TURBINE GENERATING STATIONS WITH AN AGGREGATE NAMEPLATE RATING OF 59.9 MW AND AN ESTIMATED AGGREGATE CLAIMED CAPABILITY OF 73.2 MW. WE HAVE TWO DIESEL GENERATING STATIONS WITH AN AGGREGATE NAMEPLATE RATING OF 8.0 MW AND AN ESTIMATED AGGREGATE CLAIMED CAPABILITY OF 8.6 MW. WE ALSO HAVE A WIND GENERATING FACILITY WITH A NAMEPLATE RATING OF 6.1 MW. WE ALSO OWN: * 17.9% OF THE OUTSTANDING COMMON STOCK, AND ARE ENTITLED TO 17.662% (93.8 MW OF A TOTAL 531 MW) OF THE CAPACITY, OF VERMONT YANKEE, * 1.1% (7.1 MW OF A TOTAL 620 MW) JOINT-OWNERSHIP SHARE OF THE WYMAN #4 PLANT LOCATED IN MAINE, * 8.8% (31.0 MW OF A TOTAL 352 MW) JOINT-OWNERSHIP SHARE OF THE STONY BROOK I INTERMEDIATE UNITS LOCATED IN MASSACHUSETTS, AND * 11.0% (5.8 MW OF A TOTAL 53 MW) JOINT-OWNERSHIP SHARE OF THE J.C. MCNEIL WOOD-FIRED STEAM PLANT LOCATED IN BURLINGTON, VERMONT. SEE ITEM 1. BUSINESS - POWER RESOURCES FOR PLANT DETAILS AND THE TABLE HEREINAFTER SET FORTH FOR GENERATING FACILITIES PRESENTLY AVAILABLE. 15 TRANSMISSION AND DISTRIBUTION THE COMPANY HAD, AT DECEMBER 31, 1999, APPROXIMATELY 1.5 MILES OF 115 KV TRANSMISSION LINES, 9.4 MILES OF 69 KV TRANSMISSION LINES, 5.4 MILES OF 44 KV AND 284.6 MILES OF 34.5 KV TRANSMISSION LINES. OUR DISTRIBUTION SYSTEM INCLUDES APPROXIMATELY ABOUT 2,430 MILES OF OVERHEAD LINES OF 2.4 KV TO 34.5 KV, AND ABOUT 461 MILES OF UNDERGROUND CABLE OF 2.4 KV TO 34.5 KV. AT SUCH DATE, WE OWNED APPROXIMATELY 158,820 KVA OF SUBSTATION TRANSFORMER CAPACITY IN TRANSMISSION SUBSTATIONS, 569,750 KVA OF SUBSTATION TRANSFORMER CAPACITY IN DISTRIBUTION SUBSTATIONS AND 1,085,000 KVA OF TRANSFORMERS FOR STEP-DOWN FROM DISTRIBUTION TO CUSTOMER USE. THE COMPANY OWNS 34.8% OF THE HIGHGATE TRANSMISSION INTER-TIE, A 225-MW CONVERTER AND TRANSMISSION LINE USED TO TRANSMIT POWER FROM HYDRO-QUEBEC. WE ALSO OWN 29.5% OF THE COMMON STOCK AND 30% OF THE PREFERRED STOCK OF VELCO, WHICH OPERATES A HIGH-VOLTAGE TRANSMISSION SYSTEM INTERCONNECTING ELECTRIC UTILITIES IN THE STATE OF VERMONT. PROPERTY OWNERSHIP THE COMPANY'S WHOLLY-OWNED PLANTS ARE LOCATED ON LANDS THAT WE OWN IN FEE. WATER POWER AND FLOODAGE RIGHTS ARE CONTROLLED THROUGH OWNERSHIP OF THE NECESSARY LAND IN FEE OR UNDER EASEMENTS. TRANSMISSION AND DISTRIBUTION FACILITIES THAT ARE NOT LOCATED IN OR OVER PUBLIC HIGHWAYS ARE, WITH MINOR EXCEPTIONS, LOCATED EITHER ON LAND OWNED IN FEE OR PURSUANT TO EASEMENTS WHICH, IN NEARLY ALL CASES, ARE PERPETUAL. TRANSMISSION AND DISTRIBUTION LINES LOCATED IN OR OVER PUBLIC HIGHWAYS ARE SO LOCATED PURSUANT TO AUTHORITY CONFERRED ON PUBLIC UTILITIES BY STATUTE, SUBJECT TO REGULATION BY STATE OR MUNICIPAL AUTHORITIES. INDENTURE OF FIRST MORTGAGE THE COMPANY'S INTERESTS IN SUBSTANTIALLY ALL OF ITS PROPERTIES AND FRANCHISES ARE SUBJECT TO THE LIEN OF THE MORTGAGE SECURING ITS FIRST MORTGAGE BONDS. THE COMPANY HAS ALSO PROVIDED A SECOND MORTGAGE, LIEN AND SECURITY INTEREST IN THE COLLATERAL PLEDGED UNDER THE FIRST MORTGAGE BOND INDENTURE TO THE TWO BANKS PARTICIPATING IN THE REVOLVING CREDIT AGREEMENT. GENERATING FACILITIES OWNED THE FOLLOWING TABLE GIVES INFORMATION WITH RESPECT TO GENERATING FACILITIES PRESENTLY AVAILABLE IN WHICH THE COMPANY HAS AN OWNERSHIP INTEREST. SEE ALSO ITEM 1. BUSINESS - "POWER RESOURCES." 16
Winter Capability LOCATION NAME FUEL MW(1) --------------- --------------- -------- ------- Wholly Owned Hydro . . . . . . . . . Middlesex, VT Middlesex #2 Hydro 3.3 Hydro . . . . . . . . . Marshfield, VT Marshfield #6 Hydro 4.9 Hydro . . . . . . . . . Vergennes, VT Vergennes #9 Hydro 2.1 Hydro . . . . . . . . . W. Danville, VT W. Danville #15 Hydro 1.1 Hydro . . . . . . . . . Colchester, VT Gorge #18 Hydro 3.3 Hydro . . . . . . . . . Essex Jct., VT Essex #19 Hydro 7.8 Hydro . . . . . . . . . Waterbury, VT Waterbury #22 Hydro 5.0 Hydro . . . . . . . . . Bolton, VT DeForge #1 Hydro 7.8 Diesel. . . . . . . . . Vergennes, VT Vergennes #9 Oil 4.2 Diesel. . . . . . . . . Essex Jct., VT Essex #19 Oil 4.4 Gas . . . . . . . . . . Berlin, VT Berlin #5 Oil 56.6 Turbine . . . . . . . . Colchester, VT Gorge #16 Oil 16.1 Wind. . . . . . . . . . Searsburg, VT Wind 1.2 Jointly Owned Steam . . . . . . . . . Vernon, VT Vermont Yankee Nuclear 93.8(2) Steam . . . . . . . . . Yarmouth, ME Wyman #4 Oil 7.1 Steam . . . . . . . . . Burlington, VT McNeil Wood/Gas 6.6(3) Combined. . . . . . . . Ludlow, MA Stony Brook #1 Oil/Gas 31.0(2) Total Winter Capability 256.3 ========
(1) WINTER CAPABILITY QUANTITIES ARE USED SINCE THE COMPANY'S PEAK USAGE OCCURS DURING THE WINTER MONTHS. SOME UNIT RATINGS ARE REDUCED IN THE SUMMER MONTHS DUE TO HIGHER AMBIENT TEMPERATURES. CAPABILITY SHOWN INCLUDES CAPACITY AND ASSOCIATED ENERGY SOLD TO OTHER UTILITIES. (2) FOR A DISCUSSION OF THE IMPACT OF VARIOUS POWER SUPPLY SALES ON THE AVAILABILITY OF GENERATING FACILITIES, SEE ITEM 1. BUSINESS - POWER RESOURCES - LONG-TERM POWER SALES." (3) THE COMPANY'S ENTITLEMENT IN MCNEIL IS 5.8 MW. HOWEVER, WE RECEIVE UP TO 6.6 MW AS A RESULT OF OTHER OWNERS' LOSSES ON THIS SYSTEM. CORPORATE HEADQUARTERS THE COMPANY TERMINATED AN OPERATING LEASE FOR ITS CORPORATE HEADQUARTERS BUILDING AND TWO OF ITS SERVICE CENTER BUILDINGS IN THE FIRST QUARTER OF 1999. DURING 1998, THE COMPANY RECORDED A LOSS OF APPROXIMATELY $1.9 MILLION BEFORE APPLICABLE INCOME TAXES TO REFLECT THE PROBABLE LOSS RESULTING FROM THIS TRANSACTION. THE COMPANY SOLD ITS CORPORATE HEADQUARTERS BUILDING IN 1999, BUT RETAINED OWNERSHIP OF THE TWO SERVICE CENTERS. ITEM 3. LEGAL PROCEEDINGS THE COMPANY IS INVOLVED IN SEVERAL LEGAL PROCEEDINGS, THE OUTCOME OF WHICH WILL SIGNIFICANTLY AFFECT THE VIABILITY AND OR POTENTIAL PROFITABILITY OF THE COMPANY. THE MOST SIGNIFICANT LEGAL PROCEEDINGS ARE OUR 1997 AND 1998 RETAIL RATE REQUESTS, AND ARBITRATION ABOUT HYDRO-QUEBEC'S NON-DELIVERY OF POWER AS A RESULT OF THE JANUARY 1998 ICE STORM IN EASTERN NORTH AMERICA. SEE THE DISCUSSION UNDER ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - "ENVIRONMENTAL MATTERS" RATE MATTERS AND NOTE I OF THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR MORE DETAILED INFORMATION. 17 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. NONE. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS OUTSTANDING SHARES OF THE COMMON STOCK ARE LISTED AND TRADED ON THE NEW YORK STOCK EXCHANGE UNDER THE SYMBOL GMP. THE FOLLOWING TABULATION SHOWS THE HIGH AND LOW SALES PRICES FOR THE COMMON STOCK ON THE NEW YORK STOCK EXCHANGE DURING 1998 AND 1999:
HIGH LOW -------- -------- 1998 First Quarter. 20 1/16 18 Second Quarter 19 1/16 14 1/8 Third Quarter. 14 9/16 11 1/8 Fourth Quarter 15 1/16 10 1/16 1999 First Quarter. 11 3/16 9 3/4 Second Quarter 11 5/16 8 11/16 Third Quarter. 14 10 1/4 Fourth Quarter 10 1/4 7 1/8
THE NUMBER OF COMMON STOCKHOLDERS OF RECORD AS OF MARCH 21, 2000 WAS 65,012. QUARTERLY CASH DIVIDENDS WERE PAID AS FOLLOWS DURING THE PAST TWO YEARS:
First Second Third Fourth Quarter Quarter Quarter Quarter -------- -------- -------- -------- 1998 $ 0.2750 $ 0.2750 $ 0.2750 $ 0.1375 1999 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1375
DIVIDEND POLICY ON NOVEMBER 23, 1998, THE COMPANY'S BOARD OF DIRECTORS ANNOUNCED A REDUCTION IN THE QUARTERLY DIVIDEND FROM $0.275 PER SHARE TO $0.1375 PER SHARE ON THE COMPANY'S COMMON STOCK. THE CURRENT INDICATED ANNUAL DIVIDEND IS $0.55 PER SHARE OF COMMON STOCK. OUR CURRENT DIVIDEND POLICY REFLECTS CHANGES AFFECTING THE ELECTRIC UTILITY INDUSTRY, WHICH IS MOVING AWAY FROM THE TRADITIONAL COST-OF-SERVICE REGULATORY MODEL TO A COMPETITION BASED MARKET FOR POWER SUPPLY, AND THE RATE CASE DEVELOPMENTS DISCUSSED IN ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, RATES-1998 RETAIL RATE CASE. THE CURRENT ENVIRONMENT PROMPTED US TO REASSESS THE APPROPRIATENESS OF OUR TRADITIONAL DIVIDEND POLICY. HISTORICALLY, WE BASED OUR DIVIDEND POLICY ON THE CONTINUED VALIDITY OF THREE ASSUMPTIONS: THE ABILITY TO ACHIEVE EARNINGS GROWTH, THE RECEIPT OF AN ALLOWED RATE OF RETURN THAT ACCURATELY REFLECTS OUR COST OF CAPITAL, AND THE RETENTION OF OUR EXCLUSIVE FRANCHISE. THE COMPANY'S BOARD OF DIRECTORS WILL CONTINUE TO ASSESS AND ADJUST THE DIVIDEND, WHEN APPROPRIATE, AS THE VERMONT ELECTRIC INDUSTRY EVOLVES TOWARDS COMPETITION. IN ADDITION, IF OTHER EVENTS BEYOND OUR CONTROL CAUSE THE COMPANY'S FINANCIAL SITUATION TO DETERIORATE FURTHER, THE BOARD OF DIRECTORS WILL ALSO CONSIDER WHETHER THE CURRENT DIVIDEND LEVEL IS APPROPRIATE OR IF THE DIVIDEND SHOULD BE REDUCED OR ELIMINATED. SEE ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-FUTURE OUTLOOK, COMPETITION AND RESTRUCTURING, AND NOTE C OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, FOR A DISCUSSION OF DIVIDEND RESTRICTIONS. 18 ITEM 6. SELECTED FINANCIAL DATA
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, - -------------------------------------------------------------- 1999 1998 1997 1996 1995 --------- --------- --------- --------- --------- In thousands, except per share data Operating Revenues . . . . . . . . . . . . . $251,048 $184,304 $179,323 $179,009 $161,544 Operating Expenses . . . . . . . . . . . . . 243,102 178,832 163,808 162,882 146,249 --------- --------- --------- --------- --------- Operating Income . . . . . . . . . . . . 7,946 5,472 15,515 16,127 15,295 --------- --------- --------- --------- --------- Other Income AFUDC - equity . . . . . . . . . . . . . . 134 104 357 175 27 Other. . . . . . . . . . . . . . . . . . . 3,319 1,509 1,074 1,739 2,225 --------- --------- --------- --------- --------- Total other income . . . . . . . . . . . 3,453 1,613 1,431 1,914 2,252 --------- --------- --------- --------- --------- Interest Charges AFUDC - borrowed . . . . . . . . . . . . . (91) (131) (315) (468) (547) Other. . . . . . . . . . . . . . . . . . . 7,274 8,007 7,965 7,866 7,973 --------- --------- --------- --------- --------- Total interest charges . . . . . . . . . 7,183 7,876 7,650 7,398 7,426 --------- --------- --------- --------- --------- Net Income (Loss) from continuing. . . . . . 4,216 (791) 9,296 10,643 10,121 operations before preferred dividends Net Income (Loss) from discontinued operations, including provisions for loss on disposal . . . . . . . . . . . (7,279) (2,086) 142 1,316 1,382 Dividends on Preferred Stock . . . . . . . . 1,155 1,296 1,433 1,010 771 --------- --------- --------- --------- --------- Net Income (Loss)Applicable to Common Stock. . . . . . . . . . . . . . $ (4,218) $ (4,173) $ 8,005 $ 10,949 $ 10,732 ========= ========= ========= ========= ========= Common Stock Data Earnings per share-continuing operations . $ 0.57 $ (0.40) $ 1.54 $ 1.95 $ 1.97 Earnings per share-discontinued operations $ (1.36) $ (0.40) $ 0.03 $ 0.27 $ 0.29 Earnings per share-basic and diluted . . . $ (0.79) $ (0.80) $ 1.57 $ 2.22 $ 2.26 Cash dividends declared per share. . . . . $ 0.55 $ 0.96 $ 1.61 $ 2.12 $ 2.12 Weighted average shares outstanding. . . . 5,361 5,243 5,112 4,933 4,747
FINANCIAL CONDITION AS OF DECEMBER 31 - ------------------------------------------ 1999 1998 1997 1996 1995 -------- -------- -------- -------- -------- ASSETS Utility Plant, Net. . . . . . . . . . . $192,896 $195,556 $196,720 $189,853 $181,999 Other Investments . . . . . . . . . . . 20,665 20,678 21,997 20,634 20,248 Current Assets. . . . . . . . . . . . . 33,238 35,700 29,125 30,901 30,216 Deferred Charges. . . . . . . . . . . . 41,853 35,576 35,831 43,224 42,951 Non-Utility Assets. . . . . . . . . . . 11,099 27,314 42,060 39,927 37,868 -------- -------- -------- -------- -------- Total Assets. . . . . . . . . . . . . $299,751 $314,824 $325,733 $324,539 $313,282 ======== ======== ======== ======== ======== CAPITALIZATION AND LIABILITIES Common Stock Equity . . . . . . . . . . $100,645 $106,755 $114,377 $111,554 $106,408 Redeemable Cumulative Preferred Stock . 14,435 16,085 17,735 19,310 8,930 Long-Term Debt, Less Current Maturities 88,500 88,500 93,200 94,900 91,134 Capital Lease Obligation. . . . . . . . 7,038 7,696 8,342 9,006 9,778 Current Liabilities . . . . . . . . . . 30,008 28,825 25,286 21,037 32,629 Deferred Credits and Other. . . . . . . 59,125 59,889 53,723 54,968 52,041 Non-Utility Liabilities . . . . . . . . - 7,074 13,070 13,764 12,362 -------- -------- -------- -------- -------- Total Capitalization and Liabilities. $299,751 $314,824 $325,733 $324,539 $313,282 ======== ======== ======== ======== ========
19 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. In this section, we explain the general financial condition and the results of operations for Green Mountain Power Corporation (the Company) and its subsidiaries. This explanation includes: * factors that affect our business; * our earnings and costs in the periods presented and why they changed between periods; * the source of our earnings; * our expenditures for capital projects and what we expect they will be in the future; * where we expect to get cash for future capital expenditures; and * how all of the above affects our overall financial condition. There are statements in this section that contain projections or estimates and that are considered to be forward-looking as defined by the Securities and Exchange Commission. In these statements, you may find words such as believes, expects, plans, or similar words. These statements are not guarantees of our future performance. There are risks, uncertainties and other factors that could cause actual results to be different from those projected. Some of the reasons the results may be different are discussed under "Future Outlook", "Transmission Issues", "Environmental Matters", "Rates" and "Liquidity and Capital Resources" in this section, and include: * regulatory and judicial decisions or legislation; * weather; * energy supply and demand and pricing; * contractual commitments; * availability, terms, and use of capital; * general economic and business environment; * nuclear and environmental issues; and * industry restructuring and cost recovery (including stranded costs). These forward-looking statements represent our estimates and assumptions only as of the date of this report. EARNINGS SUMMARY The Company lost $0.79 per average share of common stock in 1999, compared to a loss per share of $0.80 in 1998 and earnings per share of $1.57 in 1997. The 1999 loss represents a negative return on average common equity of 4.0 percent. The return on average common equity was negative 3.8 percent in 1998 and positive 7.1 percent in 1997. Earnings from continuing operations were $0.57 per share in 1999, compared to a loss of $0.40 per share in 1998. Certain subsidiary operations, classified as discontinued in 1999, lost $1.36 per share in 1999, compared to a loss of $0.40 per share in 1998. The 1999 loss was primarily due to a charge of $6.7 million for the discontinuation of operations of Mountain Energy, Inc. (MEI), a subsidiary of the Company that operates wastewater, energy efficiency and generation businesses. The Company anticipates that it will sell these operations during 2000. The 1999 improvement in results from continuing operations is primarily due to three factors: * retail operating revenues increased by $15.1 million, reflecting a 5.5 percent temporary rate increase that went into effect on December 15, 1998, and a 3.9 percent increase in sales to commercial and industrial customers in 1999; * operating costs were $3.7 million lower in 1999 due to the Company's termination of its corporate headquarters lease, reduced costs associated with the Company's headquarters facilities and lower payroll expense reflecting mid-year reductions in the number of employees; * results for 1998 reflected pretax charges of $9.8 million in disallowed Hydro-Quebec power costs for both 1998 and 1999, compared to disallowed power costs of $7.5 million for 2000 recorded in 1999. The ultimate rate treatment of the Hydro-Quebec power costs is expected to be determined in the Company's pending rate case. 20 The 1999 earnings improvements were partially offset by: * a $4.3 million increase in the capacity costs in 1999 associated with our long-term Hydro-Quebec power supply contract; * an increase in the costs of short-term power following the deregulation of energy markets in New England, as well as an increase in our costs to serve increased local loads and an increase of approximately $5.4 million to supply power to meet contractual obligations under the Company's sell-back agreement of December 1997 with Hydro-Quebec; and * a $1.9 million increase in Vermont Yankee capacity costs. The decrease in earnings in 1998 resulted primarily from the following: * a rate decision by the Vermont Public Service Board (VPSB) in February 1998 that disallowed recovery of $6 million for Hydro-Quebec power supply expenses and other costs; * a $5.25 million loss accrued in 1998 resulting from the assumed continued disallowance of Hydro-Quebec power costs during 1999; * higher 1998 power supply expenses resulting from a one-time $8 million payment received from Hydro-Quebec in 1997 that reduced 1997 power supply expenses accordingly; * a $3.2 million charge associated with terminating the Company's corporate headquarters lease and with workforce reductions in 1998; and * a $2.1 million (after-tax) loss experienced by Mountain Energy, Inc. in 1998, as compared to earnings of $142,0000 in 1997, resulting from a $1.2 million net write-off of a wind power investment and continued start-up operating losses incurred by Micronair LLC, a wholly-owned wastewater treatment investment. This loss was substantially offset by a $1.7 million reduction in losses experienced by Green Mountain Resources, Inc. (GMRI) due to the absence of start-up expenses in 1998, as compared to 1997. FUTURE OUTLOOK COMPETITION AND RESTRUCTURING-The electric utility business is experiencing rapid and substantial changes. These changes are the result of the following trends: * surplus generating capacity; * disparity in electric rates among and within various regions of the country; * improvements in generation efficiency; * increasing demand for customer choice; and * new regulations and legislation intended to foster competition, also known as restructuring. Electric utilities historically have had exclusive franchises for the retail sale of electricity in specified service territories. As a result, competition for retail customers has been limited to: * competition with alternative fuel suppliers, primarily for heating and cooling; * competition with customer-owned generation; and * direct competition among electric utilities to attract major new facilities to their service territories. These competitive pressures have led the Company and other utilities to offer, from time to time, special discounts or service packages to certain large customers. 21 In certain states across the country, including the New England states, legislation has been enacted to allow retail customers to choose their electricity suppliers, with incumbent utilities required to deliver that electricity over their transmission and distribution systems (also known as retail wheeling). Increased competitive pressure in the electric utility industry may restrict the Company's ability to charge energy prices sufficient to recover embedded costs, such as the cost of purchased power obligations or of generation facilities owned by the Company. The amount by which such costs might exceed market prices is commonly referred to as stranded costs. Regulatory and legislative authorities at the federal level and in some states, including Vermont where legislation has not been enacted, are considering how to facilitate competition for electricity sales at the wholesale and retail levels. In the future, the Vermont General Assembly through legislation, or the VPSB through a subsequent report, action or proceeding, may allow customers to choose their electric supplier. If this happens without providing for recovery of a significant portion of the costs associated with our power supply contracts, the Company's franchise, including our operating results, cash flows and ability to pay dividends at the current level, would be adversely affected. If actions by the Vermont General Assembly or the VPSB imperil the Company's financial integrity, we will evaluate all potential alternatives available to us at that time, including, but not limited to, eliminating common stock dividends, or the filing of a petition for reorganization under the United States Bankruptcy Code. ITEM 7A. RISK FACTORS-The major risk factors for the Company arising from electric industry restructuring, including risks pertaining to the recovery of stranded costs, are: * regulatory and legal decisions; * the market price of power; and * the amount of market share retained by the Company. There can be no assurance that any final restructuring plan ordered by the VPSB, the courts, or through legislation will include a mechanism that would allow for full recovery of our stranded costs and include a fair return on those costs as they are being recovered. If laws are enacted or regulatory decisions are made that do not offer an adequate opportunity to recover stranded costs, we believe we have compelling legal arguments to challenge such laws or decisions. The largest category of our potential stranded costs is future costs under long-term power purchase contracts, which, based on current forecasts, are above-market. The magnitude of our stranded costs is largely dependent upon the future market price of power. We have discussed various market price scenarios with interested parties for the purpose of identifying stranded costs. Preliminary market price assumptions, which are likely to change, have resulted in estimates of the Company's stranded costs of between $300 million and $450 million. We intend to aggressively pursue mitigation efforts in order to maximize the recovery of these costs. If retail competition is implemented in Vermont, it cannot now be predicted what the impact would be on the Company's revenues from electricity sales. Historically, electric utility rates have been based on a utility's cost of service. As a result, electric utilities are subject to certain accounting standards that apply only to regulated businesses. Statement of Financial Accounting Standards Number 71, (SFAS 71), Accounting for the Effects of Certain Types of Regulation, allows regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. The Company has established regulatory assets and liabilities under SFAS 71. See "Liquidity and Capital Resources" and "Rates" for additional information related to SFAS 71. The Company currently complies with the provisions of SFAS 71. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that would be material. Factors that could give rise to the discontinuance of SFAS 71 include: * deregulation; * a change in the regulator's approach to setting rates from cost-based regulation to another form of regulation; 22 * increasing competition that limits our ability to sell utility services or products at rates that will recover costs; * regulatory actions that limit rate relief to a level insufficient to recover costs. Under Statement of Financial Accounting Standards Number 5 (SFAS 5), Accounting for Contingencies, the enactment of restructuring legislation or issuance of a regulatory order containing provisions that do not allow for the recovery of above-market power costs would require the Company to estimate and record losses immediately, on an undiscounted basis, for any above-market power purchase contracts and other costs which are probable of not being recoverable from customers, to the extent that those costs are estimable. We are unable to predict what form enacted legislation or such an order will take, and we cannot predict if or to what extent SFAS 71 will continue to be applicable in the future. In addition, members of the staff of the Securities and Exchange Commission have raised questions concerning the continued applicability of SFAS 71 to certain other electric utilities facing restructuring. Statement of Financial Accounting Standards Number 121 (SFAS 121), Accounting for the Impairment of Long Lived Assets, requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues be revalued based upon future cash flows. SFAS 121 requires that a rate-regulated enterprise recognize an impairment loss for regulatory assets that are no longer probable of recovery. As of December 31, 1999, based upon the regulatory environment within which we currently operate, no impairment loss was recorded. Competitive influences or regulatory developments, including issues pending in the Company's currently stayed rate case, may impact this status in the future. We cannot predict whether restructuring legislation enacted by the Vermont General Assembly or any subsequent report or actions of, or proceedings before, the VPSB or the Vermont General Assembly would have a material adverse effect on our operations, financial condition or credit ratings. The failure to recover a significant portion of our purchased power costs, or to retain and attract customers in a competitive environment, would likely have a material adverse effect on our business, including our operating results, cash flows and ability to pay dividends at current levels. For a discussion of a major risk factor arising from Vermont regulatory treatment of the Company's recent rate filings, see "Liquidity and Capital Resources" and "Rates". UNREGULATED BUSINESSES In 1999, we continued to significantly reduce our investment in unregulated businesses. In June 1999, we decided to sell or otherwise dispose of the assets of MEI, and report its results as income (loss) from operations of a discontinued segment. MEI, which has invested in energy generation, energy efficiency and waste water treatment projects, lost $7.3 million in 1999, compared to a loss of $2.6 million in 1998. The 1999 loss results primarily from provisions to recognize our estimate of future losses from the expected sale of MEI's businesses, including anticipated operating losses. The 1998 decrease in earnings was due primarily to additional start-up operating losses incurred by Micronair, LLC and a write-off related to a wind facility in California. Green Mountain Resources, Inc. (GMRI) was formed in April 1996 to explore opportunities in the emerging competitive retail energy market. In 1999, GMRI earned $583,000 compared to a loss of $247,000 in 1998. GMRI's earnings in 1999 was primarily due to the sale of its remaining interest in Green Mountain Energy Resources (GMER) to Green Funding I, LLC. The Company's unregulated rental water heater business earned $500,000 in 1999, an increase from 1998's net income of $416,000. The 1999 and 1998 results contributed 9 cents and 8 cents of earnings, respectively, per share to the Company's consolidated results. 23 RESULTS OF OPERATIONS OPERATING REVENUES AND MWH SALES-Operating revenues and megawatthour (MWh) sales for the years ended 1999, 1998 and 1997 consisted of:
Years ended December 31, 1999 1998 1997 ------------------------- ---------- ---------- (dollars in thousands) Operating revenues Retail. . . . . . . . $ 179,997 $ 164,855 $ 158,790 Sales for Resale. . . 68,305 16,529 17,847 Other . . . . . . . . 2,746 2,920 2,686 ------------------------- ---------- ---------- Total Operating Revenues. $ 251,048 $ 184,304 $ 179,323 ========================= ========== ========== MWH Sales-Retail. . . . . 1,900,188 1,839,522 1,806,580 MWH Sales for Resale. . . 2,172,849 543,846 588,525 ------------------------- ---------- ---------- Total MWH Sales . . . . . 4,073,037 2,383,368 2,395,105 ========================= ========== ==========
Average Number of Customers Years ended December 31, 1999 1998 1999 ------------------------ ------ ------ Residential . . . . . . . 71,476 71,301 70,671 Commercial and Industrial 12,458 12,193 12,012 Other . . . . . . . . . . 66 70 75 ------------------------ ------ ------ Total Number of Customers. . 84,000 83,564 82,758 ======================== ====== ======
Differences in operating revenues were due to changes in the following:
Change in Operating Revenues 1998 TO 1999 1997 TO 1998 ------------ ------------- (In thousands) Retail Rates $ 9,395 $ 3,114 Retail Sales Volume 5,747 2,952 Resales and Other Revenues 51,602 (1,085) ------------- -------- Increase in Operating Revenues $ 66,744 $ 4,981 ============= ========
In 1999, total electricity sales increased 70.9 percent due principally to sales for resale executed pursuant to the Morgan Stanley (MS) agreement, described in more detail below under the heading "Power Supply Expense". Total operating revenues increased $66.7 million or 36.2 percent in 1999 for the same reason. Total retail revenues increased $15.1 million or 9.2 percent in 1999 primarily due to: * a 5.5 percent retail rate increase for service rendered on or after December 15, 1998; * a 3.9 percent increase in sales of electricity to our commercial and industrial customers resulting from customer growth and increased use of air conditioning during the spring and summer months; and * a 3.3 percent increase in sales of electricity to residential customers, a result of customer growth and a warmer than normal summer. 24 Total operating revenues increased 2.8 percent in 1998. Total retail revenues increased 3.8 percent in 1998 primarily due to: * a 3.9 percent increase in sales of electricity to our commercial and industrial customers resulting from increased use of air conditioning during the spring and summer months; and * a 3.79 percent retail rate increase for service rendered on or after March 1, 1998. The increase was partially offset by a 2.8 percent reduction in sales to residential customers caused by warmer than normal winter months. Wholesale revenues decreased 7.4 percent in 1998 primarily due to a reduction in low-margin, off-system sales. International Business Machines (IBM), the Company's single largest customer, operates manufacturing facilities in Essex Junction, Vermont. IBM's electricity requirements for its main plant and an adjacent plant accounted for 11.8, 14.7, and 14.0 percent of the Company's operating revenues in 1999, 1998 and 1997, respectively. No other retail customer accounted for more than one percent of the Company's revenue in any such year. The percentage decrease from 1998 to 1999 reflects MS agreement transactions; Revenues from IBM actually increased in 1999. Since 1995, the Company has had agreements with IBM with respect to electricity sales above agreed-upon base-load levels. In August 1999, the agreement was renewed for the year 2000. The agreement's price of power for the renewal period continues to be above our marginal costs of providing incremental service to IBM. We have agreed to negotiate with IBM for a new agreement covering a three-year period beginning January 2001, with terms and conditions similar to those existing. Any new agreement will be subject to approval by the VPSB. POWER SUPPLY EXPENSES-Power supply expenses constituted 75.4, 67.7, and 61.3 percent of total operating expenses for the years 1999, 1998, and 1997, respectively. Power supply expenses increased by $62.2 million or 51.4 percent in 1999 and $20.7 million or 20.6 percent in 1998. The increase in power supply expenses from 1998 to 1999 resulted from the following: * a $57.0 million increase reflecting the power purchase and supply contract discussed below, whereby we buy power from MS that is sufficient to serve pre-established load requirements at a pre-defined price; * a $4.3 million increase in the capacity costs in 1999 associated with our long-term Hydro-Quebec power supply contract; * an increase in the costs of short-term power following the deregulation of energy markets in New England, as well as an increase in our costs to serve increased local loads and to supply power to meet contractual obligations under the Company's sell-back agreement of December 1997 with Hydro-Quebec (net cost approximately $5.4 million); and * a $1.9 million increase in Vermont Yankee capacity costs. These amounts were partially offset by a reduction of $2.3 million in losses accrued for the Hydro-Quebec power cost disallowance. Results for 1998 reflected pretax charges of $9.8 million in disallowed Hydro-Quebec power costs for both 1998 and 1999, compared to disallowed power costs of $7.5 million for 2000 recorded in 1999. Ultimate disposition of the disallowance associated with Hydro- Quebec power costs is expected to be determined in the Company's pending rate case. The power supply costs of Company-owned generation decreased 13.0 percent in 1999 due to the severe 1998 ice storm in New England that caused increased usage of peak generation resources to replace power that was unavailable from Hydro-Quebec. Total power supply expenses increased 20.6 percent from 1997 to 1998 primarily due to: * the absence in 1998 of the $8 million reduction of Hydro-Quebec power costs resulting from the rate treatment of a payment received from Hydro-Quebec in 1997; * a $5.25 million loss accrued in 1998 resulting from the continued disallowance of Hydro-Quebec power costs during 1999; and * a $4.8 million increase in scheduled Hydro-Quebec contract capacity costs in 1998. 25 Company-owned generation costs increased 20.4 percent in 1998 due to an increase in the use of high-cost generating facilities that replaced power that was unavailable from Hydro-Quebec during a severe ice storm that affected much of Vermont, the Northeast United States and Qu bec in January 1998. An Independent System Operator in New England (ISO) replaced the New England Power Pool (NEPOOL) effective May 1, 1999. The ISO works as a clearinghouse for purchasers and sellers of electricity in the new deregulated markets. Sellers place bids for the sale of their generation or purchased power resources and if demand is high enough the output from those resources is sold. We must purchase electricity to meet customer demand during periods of high usage and to replace energy repurchased by Hydro-Quebec under an arrangement negotiated in 1997. Our costs to serve demand during periods of warmer than normal temperatures in summer months and to replace such energy repurchases by Hydro-Quebec rose substantially after the ISO replaced NEPOOL as the governing power supply. The cost of securing future power supplies has also risen substantially in tandem with higher summer supply costs. The Company cannot predict the duration or the extent to which future prices will continue to trade above historical levels of cost. If the new markets continue to experience the volatility evident in the second and third quarters of 1999, our earnings and cash flow could be adversely impacted by a material amount. POWER CONTRACT COMMITMENTS- During 1994, we negotiated an arrangement with Hydro-Quebec that reduced the cost under the 1987 Contract over the November 1995 through October 1999 period (the July 1994 Agreement). As part of the July 1994 Agreement, we were obligated to purchase $4.0 million (in 1994 dollars) worth of research and development work from Hydro-Quebec over a four-year period, and made a $6.5 million (in 1994 dollars) payment to Hydro-Quebec in 1995. Hydro-Quebec retains the right to curtail annual energy deliveries by 10 percent up to five times, over the 2000 to 2015 period, if documented drought conditions exist in Qu bec. Under an arrangement executed in January 1996, we received payments from Hydro-Quebec of $3.0 million in 1996 and $1.1 million in 1997. The $3.0 million payment reduced purchase power expense by $1.75 million in 1996; the balance of the payment reduced power costs in 1997. The $1.1 million payment reduced purchase power expense ratably over the period beginning June 1997 and ending May 1998. We received VPSB approval of this accounting treatment in an Accounting Order dated December 31, 1996. Under the 1996 arrangement we are required to shift up to 40 megawatts of deliveries to an alternate transmission path, and use the associated portion of the NEPOOL/Hydro-Quebec interconnection facilities to purchase power for the period from September 1996 through June 2001 at prices that vary based upon conditions in effect when the purchases are made. The 1996 arrangement also provides for minimum payments by the Company to Hydro-Quebec for periods in which power is not purchased under the arrangement. Although our level of benefits will depend on various factors, we estimate that the 1996 arrangement will provide a benefit of approximately $3.0 million on a net present value basis. Under a separate agreement executed on December 5, 1997, Hydro-Quebec paid $8.0 million to the Company in 1997. In return for this payment, we provided Hydro-Quebec an option for the purchase of power. Commencing April 1, 1998 and effective through the term of the 1987 contract, Hydro-Quebec may purchase up to 52,500 MWh on an annual basis, at energy prices established in accordance with the 1987 Contract. The cumulative amount of energy that may be purchased over the remaining term of the 1987 Contract shall not exceed 950,000 MWh. Hydro-Quebec's option to curtail energy deliveries pursuant to the July 1994 Agreement can be exercised in addition to these purchase options. Over the same period, Hydro-Quebec may exercise an option on an annual basis to purchase a total of 600,000 MWh at the 1987 Contract energy price. Hydro-Quebec may purchase no more than 200,000 MWh in any given year. In 1999, Hydro-Quebec called for deliveries to third parties at a net cost of approximately $5.4 million. In 1998, Hydro-Quebec called on us to deliver 51,968 MWh to a third party at a net cost to us of $232,958, which was due to higher energy replacement costs. (See Note K of the Notes to Consolidated Financial Statements). 26 In 1999, the Company and the other Vermont Joint Owners (VJO) of the Hydro-Quebec contract initiated an arbitration against Hydro-Quebec, pursuant to the 1987 contract terms, to determine whether the suspension of deliveries of power to Vermont during and after the January 1998 ice storm evidenced a default by Hydro-Quebec under the terms of the contract. Hydro-Quebec maintains that the "force majeure" (superior or irreversible force) provision in the contract applies, which could excuse its non-delivery of power under these circumstances. Arbitration of the dispute may lead to remedies having a material impact on our contractual obligation, including the possibility that the contract be declared terminated or void. On February 11, 1999, we entered into a contract with Morgan Stanley Capital Group, Inc. (MS) as a result of our power requirements solicitation in 1998. A master power purchase and sales agreement (PPSA) dated February 11, 1999 defines the general contract terms under which the parties may transact. The sales under the PPSA commenced on February 12, 1999 and will terminate after all obligations under each transaction entered into by MS and the Company has been fulfilled, currently anticipated to be January 31, 2002. The PPSA has been noticed to the VPSB and filed with the Federal Energy Regulatory Commission (FERC). * The PPSA provides us with a means of managing price risks associated with changing fossil fuel prices. On a daily basis, and at MS's discretion, we sell power to MS from either (i) all or part of our portfolio of power resources at predefined operating and pricing parameters or (ii) any power resources available to us, provided that sales of power from sources other than Company-owned generation comply with the predefined operating and pricing parameters. * MS then sells to us, at a predefined price, power sufficient to serve pre-established load requirements. MS is also responsible for balancing supply resources when actual loads vary from the pre-established load requirements. We remain responsible for resource performance and availability, however MS provides coverage against major unscheduled outages, up to $5.5 million annually, contingent upon both the price and availability of power resources. The parties have agreed to the protocols that are used to schedule power sales and purchases between the parties and to secure necessary transmission with respect to the two transactions described above. OTHER OPERATING EXPENSES- Other operating expenses decreased $3.7 million or 17.4 percent in 1999. The decrease results from: * a $1.9 million estimated loss in 1998 to recognize the cost of terminating the corporate headquarters operating lease. The facilities were sold in April 1999; * a $1.4 million reduction in administrative and general salaries related to a workforce reduction plan; * the elimination in 1999 a regulatory liability of $1.2 million relating to former corporate headquarters; * reductions in lease expense and facility carrying costs resulting from the disposal of the former headquarters; and * these savings were partially offset by increased costs of approximately $1.8 million associated with our reorganization. TRANSMISSION EXPENSES-Transmission expenses increased $1.4 million or 15.0 percent in 1999 due to costs associated with the creation of the ISO as the clearing house for power trades in New England and due to refunds in 1998 from Central Vermont Public Service Corp. (CVPS) and New England Power Company. Transmission expenses decreased 15.6 percent in 1998 primarily due to a refund received from CVPS in 1998 as a result of reduced levels of demand on the CVPS transmission system in 1997. We also received a refund in 1998 for charges that were incorrectly assessed to us during 1997 by New England Power Company. 27 MAINTENANCE EXPENSES-Maintenance expenses increased $1.5 million or 29.6 percent in 1999, reflecting increased expenditures on right-of-way maintenance programs. Maintenance expenses increased 8.5 percent in 1998 primarily due to scheduled plant maintenance activities at the Stony Brook plant and the repair of damage caused by lightning at our wind facility. DEPRECIATION AND AMORTIZATION- In 1999, depreciation and amortization were nearly identical to that of 1998. In 1998, depreciation and amortization expenses decreased 1.8 percent primarily due to a decrease in the amortization of expenditures related to the Pine Street Barge Canal site as a result of the VPSB Order of February 27, 1998, which suspended the amortization charges. This decrease was partially offset by an increase in depreciation expenses associated with additional investment in our utility plant. INCOME TAXES- The total effective federal and state income tax rates for the years 1999, 1998 and 1997 were (68.2) percent, 32.2 percent, and 43.2 percent, respectively. Income taxes decreased for 1999 due to a decrease in taxable income. Income taxes decreased in 1998 due to a decrease in taxable income. OTHER INCOME- Other income increased $1.9 million in 1999, due to the 1999 gain on sale of the remaining interest in GMER discussed previously under "Unregulated business", and a $0.9 million write-off in 1998 of disallowed costs of our Searsburg wind project. Other income decreased $2 million in 1998, primarily due to a $2.1 million loss experienced by Mountain Energy, Inc. resulting from a $1.3 million net write-off of a wind power investment in California and start up operating losses incurred by Micronair LLC, and a $0.9 million disallowance in costs associated with the Vermont wind facility ordered by the VPSB in its February 27, 1998 Order. In addition, the allowance for funds used during construction decreased in 1998 resulting from lower construction work in progress balances during the period. These decreases were partially offset by $1.7 million reduction in losses experienced by GMRI due to the absence of start-up expenses in 1998 as compared to 1997. INTEREST CHARGES-Interest expense decreased $0.7 million or 8.7 percent in 1999, consistent with reductions in average long-term and short-term debt outstanding during the year. Interest charges increased $0.2 million or 3.0 percent in 1998 primarily due to an increase in short-term interest expense related to a higher amount of short-term debt outstanding during the year, and a decrease in the allowance for funds used during construction. The increases were partially offset by a decrease in long-term interest charges related to a lower amount of long-term debt outstanding in 1998. DIVIDENDS ON PREFERRED STOCK- Dividends on preferred stock decreased $141,000, or 10.9 percent in 1999 due to repurchases of preferred stock. In 1998, the dividends on preferred stock also decreased $137,000 or 9.6 percent for the same reason. TRANSMISSION ISSUES FEDERAL OPEN ACCESS TARIFF ORDERS-On April 24, 1996, the Federal Energy Regulatory Commission issued Orders 888 and 889 which, among other things, required the filing of open access transmission tariffs by electric utilities, and the functional separation by utilities of their transmission operations from power marketing operations. Order 888 also supports the full recovery of legitimate and verifiable wholesale power costs previously incurred under federal or state regulation. 28 On July 17, 1997, the FERC approved our Open Access Transmission Tariff, and on August 30, 1997 we filed our compliance refund report. In accordance with Order 889, we have also functionally separated our transmission operations and filed with the FERC a code of conduct for our transmission operations. We do not anticipate any material adverse effects or loss of wholesale customers due to the FERC orders mentioned above. ENVIRONMENTAL MATTERS The electric industry typically uses or generates a range of potentially hazardous products in its operations. We must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. We believe that we are in substantial compliance with these requirements, and that there are no outstanding material complaints about our compliance with present environmental protection regulations, except for developments related to the Pine Street Barge Canal site. We maintain programs to ensure that we are in compliance with environmental regulations. These programs include employee training, regular inspection of our facilities, research and development projects, waste handling and spill prevention procedures, program monitoring and other activities. PINE STREET BARGE CANAL SITE-The Federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), commonly known as the "Superfund" law, generally imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. We have previously been notified by the Environmental Protection Agency (EPA) that we are one of several potentially responsible parties (PRPs) for cleanup of the Pine Street Barge Canal site in Burlington, Vermont, where coal tar and other industrial materials were deposited. In September 1999, we negotiated a final settlement with the United States, the State of Vermont (State), and other parties to a Consent Decree that covers claims with respect to the site and implementation of the selected site cleanup remedy. In November 1999, the Consent Decree was filed in the federal district court. The Consent Decree addresses claims by the EPA for past Pine Street Barge Canal site costs, natural resource damage claims and claims for past and future oversight costs. The Consent Decree also provides for the design and implementation of response actions at the site. As of December 31, 1999, our total expenditures related to the Pine Street Barge Canal site since 1982 were approximately $22.2 million. This includes amounts not recovered in rates, amounts recovered in rates, and amounts for which rate recovery has been sought but which are presently awaiting further VPSB action. The bulk of these expenditures consisted of transaction costs. Transaction costs include legal and consulting costs associated with the Company's opposition to the EPA's earlier proposals for a more expensive remedy at the site, litigation and related costs necessary to obtain settlements with insurers and other PRP's to provide amounts required to fund the clean up (remediation costs), and to address liability claims at the site. A smaller amount of past expenditures was for site-related response costs, including costs incurred pursuant to EPA and state orders that resulted in funding response activities at the site, and to reimbursing the EPA and the State for oversight and related response costs. The EPA and the State have asserted and affirmed that all costs related to these orders are appropriate costs of response under CERCLA for which the Company and other PRPs were legally responsible. We estimate that we have recovered or secured, or will recover, through settlements of litigation claims against insurers and other parties, amounts that exceed estimated future remediation costs, future federal and state government oversight costs and past EPA response costs. We have recently concluded that our unrecovered transaction costs mentioned above, which were necessary to recover settlements sufficient to remediate the site, to oppose much more costly solutions proposed by the EPA, and to resolve monetary claims of the EPA and the State, together with our remediation costs, are more likely to be in the range of $8.7 to $12.5 million, rather than the previous estimate of $5.0 to $9.0 million. In 1998, we recorded a liability of $5 million to recognize the low end of the initial range of costs. In 1999 we recorded an 29 additional liability of $3.7 million to reflect revised estimates of site monitoring costs to be incurred over the next 33 years. The estimated liability is not discounted, and it is possible that our estimate of future costs could change by a material amount. We also have recorded an offsetting regulatory asset and we believe that it is probable that we will receive future revenues to recover these costs. Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and received recovery for ongoing expenses associated with the Pine Street Barge Canal site. While reserving the right to argue in the future about the appropriateness of full rate recovery of the site related costs, the Company and the Vermont Department of Public Service, (the Department), and as applicable, other parties, reached agreements in these cases that the full amount of the site-related costs reflected in those rate cases should be recovered in rates. We proposed in our rate filing made on June 16, 1997 recovery of an additional $3.0 million in such expenditures. In an Order in that case released March 2, 1998, the VPSB suspended the amortization of expenditures associated with the Pine Street Barge Canal site pending further proceedings. Although it did not eliminate the rate base deferral of these expenditures, or make any specific order in this regard, the VPSB indicated that it was inclined to agree with other parties in the case that the ultimate costs associated with the Pine Street Barge Canal site, taking into account recoveries from insurance carriers and other PRP's, should be shared between customers and shareholders of the Company. In response to our Motion for Reconsideration, the VPSB on June 8, 1998 stated its intent was "to reserve for a future docket issues pertaining to the sharing of remediation-related costs between the Company and its customers". See "Rates-1997 Retail Rate Case" below. CLEAN AIR ACT-Because we purchase most of our power supply from other utilities, we do not anticipate that we will incur any material direct cost increases as a result of the Federal Clean Air Act or proposals to make more stringent regulations under that Act. Furthermore, only one of our power supply purchase contracts, which expired in early 1998, related to a generating plant that was affected by Phase I of the acid rain provisions of this legislation, which went into effect January 1, 1995. RATES 1997 RETAIL RATE CASE-On June 16, 1997, the Company filed a request with the VPSB to increase retail rates by 16.7 percent ($26 million in additional annual revenues) and to increase the target return on common equity from 11.25 percent to 13 percent. In our final submissions to the VPSB we asked for an increase of 14.4 percent ($22 million in additional annual revenues) due to changed estimates of costs to be incurred in the rate year. On March 2, 1998, the VPSB released its Order dated February 27, 1998 in the then pending rate case. The VPSB authorized us to increase our rates by 3.61 percent, which gave us increased annual revenues of $5.6 million. The difference between the $22 million we asked for and the $5.6 million the VPSB authorized was due to the following: * disallowance of the cost of power associated with the Hydro-Quebec contract discussed below; * the VPSB's modification of our calculation of rate base; * the exclusion of future capital projects from rate base; * suspension of recovery of Pine Street Barge Canal site expenditures; * various cost of service reductions in payroll and operations and maintenance; and * a reduction in our requested allowed return on equity from 13 percent to 11.25 percent. The VPSB Order denied us the right to charge customers $5.48 million of the annual costs for power purchased under our contract with Hydro-Quebec. The VPSB denied recovery of these costs for the following reasons: 30 * the VPSB claimed that we had acted imprudently by committing to the power contract with Hydro-Quebec in August 1991 (the imprudence disallowance); and * to the extent that the costs of power to be purchased from Hydro-Quebec are now higher than current estimates of market prices for power during the Contract term, after accounting for the imprudence disallowance, the contract power is not "used and useful". Generally accepted accounting principles required that we record in the first quarter of 1998 the losses resulting from the disallowed recovery of a portion of the 1998 Hydro-Quebec power contract costs. The amount charged to first quarter income of $4.6 million (pre-tax) was less than the full disallowance because we expected that new rates would become effective in January 1999 as the result of our May 8, 1998 rate filing, discussed below. In its February 27, 1998 Order, the VPSB talked about its policies that do not allow a utility to recover imprudent expenditures and the costs of power supply contract purchases that the VPSB decides are not used and useful. The VPSB stated in its Order that the methods and measures used in this rate case were provisional and applied to this rate case only. If the VPSB were to apply the same, or similar, methods and measures that they used in the 1997 rate case Order to future power contract costs in our 1998 Retail Rate Case, we would likely be required to recognize a charge to income of approximately $154 million before income taxes. The $154 million estimate represents primarily the 20 percent disallowance for Hydro-Quebec power costs that the VPSB considered imprudent in its 1997 order. We are unable to estimate the loss (from disallowance) to be recorded for power purchased after December 31, 2000, if any, until the pending 1998 rate case is completed. SFAS 71 provides guidance in preparing financial statements for public utilities that meet certain criteria of SFAS 71. The three criteria that we must meet in order to follow that accounting guidance are: * our rates for regulated services and products provided to our customers must be established by or be subject to approval by an independent, third-party regulator; * the regulated rates are designed to recover our specific costs of providing the regulated services or products; and * depending on demand for regulated services and products, and the level of competition, direct and indirect, it is reasonable to assume that our rates are set at levels that will recover our costs and that these rates can be charged to and collected from our customers. This criterion must also take into account anticipated changes in levels of demand or competition during the recovery period for any capitalized costs. We meet these criteria presently, and under SFAS 71 we are required to defer certain costs that would typically be accounted for as expense in an unregulated entity; these costs are referred to as deferred charges or regulatory assets. Our ability to defer a cost is subject to our ability to provide evidence that the following additional criteria are met: * it is probable that the inclusion of the capitalized (deferred) cost in allowed costs for rate making purposes will provide future revenue in an amount at least equal to the capitalized (deferred) cost; and * the future revenue will be provided to permit recovery of the previously incurred cost rather than to provide for expected levels of similar future costs. If the VPSB does not modify its ruling that the costs of power purchased from Hydro-Quebec are above estimated market rates and are not used and useful and, therefore, a portion of such costs is not recoverable, we would likely conclude that the VPSB has changed its approach to setting rates from cost-based rate making to another form of regulation. We would then be required to discontinue application of SFAS 71 and eliminate all regulatory assets and liabilities that arose from prior actions of the VPSB. The write-off of these 31 regulatory assets and liabilities, net of any tax effects, would be charged to income as an extraordinary item for the financial reporting period in which the discontinuation of SFAS 71 occurs. Based on the December 31, 1999 balance sheet, if we were required to discontinue the application of SFAS 71, we would be required to recognize an after-tax charge to earnings of approximately $27.0 million attributable to net regulatory assets. On March 20, 1998, we filed with the VPSB a Motion for Reconsideration of and to Alter or Amend certain aspects of the VPSB's Order released on March 2, 1998. Immediately following the issuance of the June 8, 1998 VPSB order on our Motion for Reconsideration, which mainly reaffirmed the earlier order, Duff & Phelps and Standard & Poor's lowered our securities credit ratings. Moody's also subsequently lowered our securities credit ratings. In June 1998, we appealed the VPSB's February 27, 1998 order and the June 8, 1998 reconsideration order to the Vermont Supreme Court. The briefing of the case by all parties was completed in January 1999. A number of other Vermont utilities submitted briefs in support of the Company. Oral arguments were presented to the Vermont Supreme Court on March 16, 1999. We believe that the decisions in the VPSB's February 27, 1998 Order and June 8, 1998 Reconsideration Order are factually inaccurate and legally incorrect. Specifically, we are appealing the VPSB's determination that we were imprudent in committing to the Hydro-Quebec contract in August, 1991, and its ruling that because the contract power is priced over-market under current forecasts of market prices, it is therefore considered "not used and useful". The Company asserts, among other arguments, that the VPSB's order deprives the Company's shareholders of their property in an unconstitutional manner. If not changed, the VPSB's decision could have a significant negative impact on our reported financial condition, and could impact our credit ratings, dividend policy and financial viability. 1998 RETAIL RATE CASE-On May 8, 1998, we filed a request with the VPSB to increase our retail rates by 12.93 percent due to higher power costs, the cost of the January 1998 ice storm, and investments in new plant and equipment. The VPSB suspended the tariff filings on June 15, 1998. We submitted testimony in the case that included analysis of viable alternatives to the Hydro-Quebec contract at various times in 1991 and 1992. The VPSB had taken the viewpoint in our 1997 rate case that we would have been able to terminate the Hydro-Quebec contract without penalty during that time period, and would have been able to access the market for power at that time. Our analysis showed that, based on price only, the Hydro-Quebec contract was less expensive than virtually all other long-term power resources available at that time. The analysis also showed that when other non-price benefits, like environmental benefits and the reliability of a system power resource, are taken into account, the Hydro-Quebec contract was still less costly than alternatives. We have testified that even today, when costs and benefits for society are accounted for, as Vermont regulators and statutes require, the Hydro-Quebec power is not more costly than market power. In testimony submitted on September 21, 1998, the Department argued for a $22 million disallowance of Hydro-Quebec contract costs, a rate decrease of 3.6 percent, the elimination of our common stock dividend, and various other restrictions. IBM, our largest customer, argued for a rate decrease of 0.2 percent, a disallowance of Hydro-Quebec power costs in the amount of $13 million, and the elimination of the common stock dividend. On November 18, 1998, by Memorandum of Understanding (MOU), the Company, the Department and IBM agreed to stay rate proceedings in the 1998 rate case until or after September 1, 1999, or such earlier date as the parties may later agree to or the VPSB may order. The agreement to suspend our 1998 rate case delayed the date of a final decision on the 1998 rate case to December 15, 1999, and we recognized an additional loss of $5.25 million in the last quarter of 1998 representing the effect of the continued disallowance of Hydro-Quebec costs through December 15, 1999. The MOU provided for a 5.5% temporary retail rate increase, to produce $8.9 million in annualized additional revenue, effective with service rendered December 15, 1998. In the event that the VPSB issues a final order that allows a retail rate increase that is less than the temporary 32 rates, all sums collected in excess of such final rates would be refunded by adjusting rates on a prospective basis, by customer class, to reflect the appropriate refund amounts. At December 31, 1999, total revenues subject to refund are approximately $9.2 million. An additional surcharge was permitted, without further VPSB order, in order to produce additional revenues necessary to provide the Company with the capacity to finance 1999 Pine Street Barge Canal site expenditures. The MOU was approved by the VPSB on December 11, 1998. The MOU did not provide for any specific disallowance of power costs under our purchase power contract with Hydro-Quebec. Issues respecting recovery of such power costs were preserved for future proceedings. The temporary rates included $1.0 million that is to be used for enhanced right of way maintenance and pole testing and treatment. Also, in the event that the Vermont Supreme Court issues an order reversing the VPSB's orders in our 1997 rate case prior to issuance of a final order in the 1998 rate case, any resulting adjustments in rates will not become effective until the VPSB issues a final order in the 1998 rate case. The MOU provides that nothing in it will reduce or limit our entitlement to full recovery of any amounts due us if we should prevail on the appeal. The stay and suspension of this pending rate case and the temporary rate levels agreed to in the MOU were designed to allow us to continue to provide adequate and efficient service to our customers while we seek mitigation of power supply costs. On September 7 and December 17, 1999, the VPSB issued Orders approving two amendments to the MOU that the Company had entered into with the Department and IBM. The two amendments continued the stay of proceedings until September 1, 2000, with a final decision expected by December 31, 2000. The amendments maintained the other features of the original MOU, and the second amendment provides for a temporary rate increase of 3 percent, in addition to the current temporary rate level, to become effective as of January 1, 2000. The temporary rates are still subject to refund in the final rate case decision, if the final rates set are lower than the temporary rates. One party to the rate case, the American Association of Retired Persons (AARP), has filed an appeal to the Vermont Supreme Court of the VPSB's order of December 17, 1999, arguing that the VPSB should have ordered the Company to post a bond or escrow for the temporary rate increase. The Company has moved to dismiss the appeal. Notwithstanding the interim rate settlement, we are unable to predict whether the MOU or other future events, singularly or in combination, could cause our lending banks to refuse to allow further borrowings under our revolving loan agreement, to seek to enter into a new credit agreement with us and/or to immediately call in all outstanding loans. If we are unable to borrow on a short-term basis, we will evaluate all potential alternatives available at the time, including, but not limited to, the reduction or elimination of common stock dividends or the filing of a petition for reorganization under the United States Bankruptcy Code. LIQUIDITY AND CAPITAL RESOURCES CONSTRUCTION-Our capital requirements result from the need to construct facilities or to invest in programs to meet anticipated customer demand for electric service. If restructuring does occur, we will reassess our capital expenditures for generation and other projects and the terms of financing thereof. Capital expenditures over the past three years and forecasted for 2000 are as follows: 33
Generation Transmission Distribution Conservation Other Total ----------- ------------- ------------- ------------- ------ ------- (Dollars in thousands, net of AFUDC and customer advances for construction) Actual: - --------- 1997* . . $ 3,462 $ 986 $ 9,680 $ 2,094 $3,291 $19,513 1998. . . 543 751 6,063 1,244 4,568 13,169 1999**. . 210 144 7,283 1,943 9,039 18,619 Forecast: - --------- 2000. . . 1,941 1,335 8,155 *** 3,043 14,474
* includes $2.7 million for Searsburg wind farm ** includes $6.1 million for Pine Street Barge Canal site ***A statewide Energy Efficiency Utility (EEU) has been set up by the VPSB to manage all energy efficiency programs. The Company's customers are now billed a separate EEU charge that we remit directly to the EEU DIVIDEND POLICY-On November 23, 1998, the Board of Directors of the Company announced a reduction in the quarterly dividend on the Company's common stock from $0.275 per share to $0.1375 per share. The annual dividend rate was $0.55 per share at December 31, 1999. Our current dividend policy reflects changes affecting the electric utility industry, which is moving away from the traditional cost-of-service regulatory model to a competition based market for power supply, as well as earnings projections associated with the rate case developments referred to above. Our current environment has prompted us to reassess the appropriateness of our traditional dividend policy. The Board of Directors will continue to assess and adjust the dividend, when appropriate as the Vermont electricity industry evolves towards competition. In addition, if other events beyond our control cause our financial situation to deteriorate further, the Board of Directors will also consider whether the current dividend level is appropriate or if the dividend should be reduced or eliminated. FINANCING AND CAPITALIZATION-Internally generated funds provided approximately 80 percent of requirements for 1999, 1998 and 1997 combined. Internally generated funds, after payment of dividends, provide capital requirements for construction, sinking funds and other requirements. We anticipate that for 2000, internally generated funds will provide approximately 90 percent of total capital requirements for regulated operations. At December 31, 1999, our capitalization consisted of 49.4 percent common equity, 43.5 percent long-term debt and 7.1 percent preferred equity. On June 23, 1999, we renewed a revolving credit agreement with two banks. The agreement is for a period of 364 days and will expire on June 21, 2000. The commitment of $15 million represents a reduction from the previous commitment of $45 million. We believe the amounts available under the new agreement will be sufficient to meet our forecasted borrowing requirements during the 364-day period. The terms continue the requirement that loans made under the agreement will be secured by granting the banks a second priority mortgage, lien and security interest in the collateral pledged under the Company's first mortgage bond indenture. We also have an uncommitted line of credit in the amount of $500,000, under which no amounts were outstanding at December 31, 1999. The revolving credit agreement requires us to certify on a quarterly basis that we have not suffered a "material adverse change." Similarly, as a condition to further borrowings, we must certify that nothing has happened that has had or could reasonably be expected to have a materially adverse effect on us since the date that we last borrowed under this agreement. Our agreement allows us to continue to borrow until such time that: 34 * a "material adverse effect" has occurred; * we are no longer in compliance with all other provisions of the agreement, in which case further borrowing will not be permitted; or * there has been a "material adverse change", in which case the banks may declare us in default. There are a number of future events that, singularly or in combination, could lead the banks to refuse to allow further borrowings under the existing credit agreement, to seek to enter into a new credit agreement with us and/or to immediately call in all outstanding loans. Some of those events are: * the VPSB issues an order in our pending 1998 rate case that triggers a "material adverse change" for us; or * Hydro-Quebec is unwilling to make new arrangements regarding the cost of power that we purchase under our contract with them. On November 19, 1999, while negotiations for an additional temporary rate increase with Department and IBM were ongoing but before any agreement was reached, the banks requested that the total amount available to the Company under the existing revolving credit agreement be reduced from $15 million to $8.5 million. In order to have access to borrowed funds needed at that time, the Company agreed to the banks' request. Subsequent to the VPSB approval of an additional 3 percent rate increase in December 1999, the banks agreed to maintain the total amount available at $15 million. The total amount available will be reduced by the net proceeds from certain sales of the Company's assets, such as the assets of MEI. If we are unable to borrow on a short-term basis, we will evaluate all potential alternatives available to us at the time, including, but not limited to, the filing of a petition for reorganization under the United States Bankruptcy Code. The credit ratings of the Company's securities are:
DUFF AND PHELPS MOODY'S STANDARD & POOR'S --------------- ------- ----------------- First mortgage bonds . . . BBB Baa3 BBB Unsecured medium term debt BBB- -- -- Preferred stock. . . . . . BB+ ba2 BB
On August 25, 1999, Moody's Investor Service downgraded the rating of the Company's outstanding preferred stock to "ba2" from "ba1". Duff & Phelps', Moody's and Standard & Poor's credit ratings for the Company remain on Rating watch-down, Review for possible further downgrade, and Credit watch negative, respectively, due to the high level of regulatory and public policy uncertainty in Vermont and certain positions argued by the Department in our rate cases. See Note F of the Notes to Consolidated Financial Statements for a discussion of the bank credit facilities available to the Company. YEAR 2000 COMPUTER COMPLIANCE-We experienced no interruption in the delivery of electricity due to the transition from December 31, 1999 to January 1, 2000. We also have not experienced any significant events related to the year 2000 transition on any of our software applications or embedded systems. Potential problems with future dates continue to pose risk to the Company. Our ability to deliver electricity to our customers could also be impacted if one of our major power suppliers or vendors of telecommunication service experienced a date-related system failure. An interruption in power supplied by other delivery systems, such as the independent system operator (ISO) for New England, could also cause power delivery problems for us. The contingency planning process implemented by the Company during 1999 remains in place. The phases of our contingency planning process include business impact analysis and contingency planning and testing, and include testing of year 2000 dates that pose continual risk. Business impact analysis 35 requires business unit personnel to evaluate the impact of mission-critical systems failure on our core business operations, focusing on specific failure scenarios and how they can be mitigated. The necessary conditions for enacting the plans were documented along with the appropriate personnel responsible in each of the business units should a Year 2000 failure occur. Additionally, we have participated in system readiness drills to stimulate major outages and restart capability. The total cost of upgrading software that would not otherwise have been replaced in accordance with our business plans is approximately $310,000. Approximately $260,000 has been expended as of December 31, 1999 for external labor, hardware and software costs, and for the costs of employees who are dedicated to the Year 2000 project. The foregoing amounts do not include the cost of new software applications installed as a result of strategic replacement projects. Such replacement projects were not accelerated because of Year 2000 issues. We believe that our planning was adequate to secure Year 2000 readiness of our critical systems. Nevertheless, maintaining Year 2000 security is subject to various risks and uncertainties, many of which are described above. We are not able to predict all the factors that could cause actual results to differ materially form our current expectations as to our Year 2000 readiness. However, if we, or third parties with whom we have significant business relationships, fail to maintain Year 2000 readiness with respect to critical systems, there could be a material adverse effect on our results of operations, financial position and cash flows. NUCLEAR DECOMMISSIONING-The staff of the SEC has questioned certain current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in financial statements. In response to these questions, the Financial Accounting Standards Board had agreed to review the accounting for closure and removal costs, including decommissioning. We do not believe that changes in such accounting, if required, would have an adverse effect on the results of operations due to our current and future ability to recover decommissioning costs through rates. EFFECTS OF INFLATION-Financial statements are prepared in accordance with generally accepted accounting principles and report operating results in terms of historic costs. This accounting provides reasonable financial statements but does not always take inflation into consideration. As rate recovery is based on these historical costs and known and measurable changes, the Company is able to receive some rate relief for inflation. It does not receive immediate rate recovery relating to fixed costs associated with Company assets. Such fixed costs are recovered based on historic figures. Any effects of inflation on plant costs are generally offset by the fact that these assets are financed through long-term debt. 36 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA GREEN MOUNTAIN POWER CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES PAGE FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF INCOME 38 FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997 CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE 39 YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 CONSOLIDATED BALANCE SHEETS AS OF 40 DECEMBER 31, 1999 AND 1998 CONSOLIDATED CAPITALIZATION DATA AS OF 42 DECEMBER 31, 1999 AND 1998 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 43 QUARTERLY FINANCIAL INFORMATION 63 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 64 SCHEDULES FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997: II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES 65 ALL OTHER SCHEDULES ARE OMITTED AS THEY ARE EITHER NOT REQUIRED, NOT APPLICABLE OR THE INFORMATION IS OTHERWISE PROVIDED. CONSENT AND REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ARTHUR ANDERSEN LLP 66 37
GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED COMPARATIVE INCOME STATEMENTS FOR THE YEARS ENDED DECEMBER 31, --------------------- 1999 1998 1997 --------------------- --------- --------- (In thousands, except per share data) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . $ 251,048 $184,304 $179,323 --------------------- --------- --------- OPERATING EXPENSES Power Supply Vermont Yankee Nuclear Power Corporation . . . . . . . . . . . 34,987 32,910 32,817 Company-owned generation . . . . . . . . . . . . . . . . . . . 5,582 6,412 5,327 Purchases from others. . . . . . . . . . . . . . . . . . . . . 142,699 81,706 62,222 Other operating. . . . . . . . . . . . . . . . . . . . . . . . . 17,582 21,291 16,780 Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . 10,800 9,389 11,122 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . 6,728 5,190 4,785 Depreciation and amortization. . . . . . . . . . . . . . . . . . 16,187 16,059 16,359 Taxes other than income. . . . . . . . . . . . . . . . . . . . . 7,295 7,242 7,205 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 1,242 (1,367) 7,191 --------------------- --------- --------- Total operating expenses . . . . . . . . . . . . . . . . . . . 243,102 178,832 163,808 --------------------- --------- --------- OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 7,946 5,472 15,515 --------------------- --------- --------- OTHER INCOME Equity in earnings of affiliates and non-utility operations. . . 2,919 2,058 285 Allowance for equity funds used during construction. . . . . . . 134 104 357 Other income (deductions), net . . . . . . . . . . . . . . . . . 400 (549) 789 --------------------- --------- --------- Total other income (deductions). . . . . . . . . . . . . . . . 3,453 1,613 1,431 --------------------- --------- --------- INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 11,399 7,085 16,946 --------------------- --------- --------- INTEREST CHARGES Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . 6,716 6,991 7,274 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 558 1,016 691 Allowance for borrowed funds used during construction. . . . . . (91) (131) (315) --------------------- --------- --------- Total interest charges . . . . . . . . . . . . . . . . . . . . 7,183 7,876 7,650 --------------------- --------- --------- INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . . 4,216 (791) 9,296 Dividends on preferred stock . . . . . . . . . . . . . . . . . . . 1,155 1,296 1,433 --------------------- --------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS . . . . . . . . . . . . . 3,061 (2,087) 7,863 Net income(loss) from discontinued segment operations . . . . . . . . . . . . . . . . . . . . . . . . . . . (603) (2,086) 142 Loss on disposal, including provisions for operating losses during phaseout period. . . . . . . . . . . . (6,676) - - --------------------- --------- --------- NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . . . . $ (4,218) $ (4,173) $ 8,005 ===================== ========= ========= COMMON STOCK DATA Basic and diluted earnings per share from discontinued operations. $ (1.36) $ (0.40) $ 0.03 Basic and diluted earnings per share from continuing operations. . 0.57 (0.40) 1.54 Basic and diluted earnings per share . . . . . . . . . . . . . . . (0.79) (0.80) 1.57 Cash dividends declared per share. . . . . . . . . . . . . . . . . 0.55 0.96 1.61 Weighted average shares outstanding. . . . . . . . . . . . . . . . 5,361 5,243 5,112
The accompanying notes are an integral part of the consolidated financial statements. 38
CONSOLIDATED STATEMENTS OF CASH FLOWS GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31, 1999 1998 1997 ---------------------------------- --------- --------- (In thousands) OPERATING ACTIVITIES: Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . $ (4,218) $ (4,173) $ 8,005 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization . . . . . . . . . . . . . 16,187 16,059 16,359 Dividends from associated companies less equity income. 169 812 (90) Allowance for funds used during construction. . . . . . (224) (235) (672) Amortization of purchased power costs . . . . . . . . . 5,725 6,405 5,212 Deferred income taxes . . . . . . . . . . . . . . . . . 1,812 (112) (2,715) Provision for loss on segment disposal. . . . . . . . . 6,676 - - Deferred purchased power costs. . . . . . . . . . . . . (6,590) (7,830) (331) Deferred arbitration costs. . . . . . . . . . . . . . . (1,684) - - Amortization of investment tax credits. . . . . . . . . (282) (282) (282) Environmental proceedings costs . . . . . . . . . . . . (6,105) 3,010 (2,123) Conservation expenditures . . . . . . . . . . . . . . . (1,943) (1,833) (2,411) Changes in: Accounts receivable . . . . . . . . . . . . . . . . . 474 (1,611) 368 Accrued utility revenues. . . . . . . . . . . . . . . (358) (105) 156 Fuel, materials and supplies. . . . . . . . . . . . . (150) 122 359 Prepayments and other current assets. . . . . . . . . 4,009 (983) (6,749) Accounts payable. . . . . . . . . . . . . . . . . . . 665 (1,893) 1,728 Taxes accrued . . . . . . . . . . . . . . . . . . . . (1,611) (2,473) 1,856 Interest accrued. . . . . . . . . . . . . . . . . . . (34) (108) (71) Other current liabilities . . . . . . . . . . . . . . 1,722 3,229 (164) Other . . . . . . . . . . . . . . . . . . . . . . . . . 865 1,940 7,663 ---------------------------------- --------- --------- Net cash provided by continuing operations. . . . . . . . 15,105 9,939 26,098 Net cash provided (used) by discontinued segment. . . . . (138) - - ---------------------------------- --------- --------- Net cash provided by operating activities . . . . . . . . 14,967 9,939 26,098 INVESTING ACTIVITIES: Construction expenditures . . . . . . . . . . . . . . . . . (9,174) (10,900) (16,409) Investment in nonutility property . . . . . . . . . . . . . (190) (1,442) 218 Proceeds from sale of propane subsidiary. . . . . . . . . . - 11,500 - ---------------------------------- --------- --------- Net cash provided by (used in) investing activities . . . (9,364) (842) (16,191) ---------------------------------- --------- --------- FINANCING ACTIVITIES: Issuance of common stock. . . . . . . . . . . . . . . . . . 1,054 1,587 3,428 Short-term debt, net. . . . . . . . . . . . . . . . . . . . 900 4,384 1,600 Cash dividends. . . . . . . . . . . . . . . . . . . . . . . (4,101) (6,332) (9,637) Reduction in preferred stock. . . . . . . . . . . . . . . . (1,650) (1,650) (1,575) Reduction in long-term debt . . . . . . . . . . . . . . . . (1,700) (6,767) (4,201) ---------------------------------- --------- --------- Net cash provided by (used in) financing activities . . . (5,497) (8,778) (10,385) ---------------------------------- --------- --------- Net increase in cash and cash equivalents . . . . . . . . . 106 319 (478) Cash and cash equivalents at beginning of period. . . . . . 590 271 749 ---------------------------------- --------- --------- Cash and cash equivalents at end of period. . . . . . . . . $ 696 $ 590 $ 271 ================================== ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid year-to-date for: Interest (net of amounts capitalized) . . . . . . . . . . $ 7,034 $ 7,857 $ 7,800 Income taxes, net . . . . . . . . . . . . . . . . . . . . 997 2,285 5,853
The accompanying notes are an integral part of the consolidated financial statements. 39
CONSOLIDATED BALANCE SHEETS GREEN MOUNTAIN POWER CORPORATION DECEMBER 31 ------------ 1999 1998 ------------ -------- (In thousands) ASSETS UTILITY PLANT Utility plant, at original cost . . . . . . . . $ 283,917 $276,853 Less accumulated depreciation . . . . . . . . . 102,854 94,604 ------------ -------- Net utility plant . . . . . . . . . . . . . . 181,063 182,249 Property under capital lease. . . . . . . . . . 7,038 7,696 Construction work in progress . . . . . . . . . 4,795 5,611 ------------ -------- Total utility plant, net. . . . . . . . . . 192,896 195,556 ------------ -------- OTHER INVESTMENTS Associated companies, at equity . . . . . . . . 14,545 15,048 Other investments . . . . . . . . . . . . . . . 6,120 5,630 ------------ -------- Total other investments . . . . . . . . . . 20,665 20,678 ------------ -------- CURRENT ASSETS Cash and cash equivalents . . . . . . . . . . . 656 439 Accounts receivable, customers and others, less allowance for doubtful accounts of $398 and $449. . . . . . . . . . . . . . . 18,503 18,977 Accrued utility revenues. . . . . . . . . . . . 6,969 6,611 Fuel, materials and supplies, at average cost . 3,290 3,139 Prepayments . . . . . . . . . . . . . . . . . . 3,438 6,091 Other . . . . . . . . . . . . . . . . . . . . . 382 443 ------------ -------- Total current assets. . . . . . . . . . . . 33,238 35,700 ------------ -------- DEFERRED CHARGES Demand side management programs . . . . . . . . 7,640 10,590 Purchased power costs . . . . . . . . . . . . . 7,435 5,708 Pine Street Barge Canal . . . . . . . . . . . . 8,700 5,000 Other . . . . . . . . . . . . . . . . . . . . . 18,078 14,278 ------------ -------- Total deferred charges. . . . . . . . . . . 41,853 35,576 ------------ -------- NON-UTILITY Cash and cash equivalents . . . . . . . . . . . 40 151 Other current assets. . . . . . . . . . . . . . 8 3,409 Property and equipment. . . . . . . . . . . . . 253 1,213 Intangible assets . . . . . . . . . . . . . . . - 1,658 Equity investment in energy related businesses. - 12,357 Business segment held for disposal. . . . . . . 9,477 - Other assets. . . . . . . . . . . . . . . . . . 1,321 8,526 ------------ -------- Total non-utility assets. . . . . . . . . . 11,099 27,314 ------------ -------- TOTAL ASSETS. . . . . . . . . . . . . . . . . . . $ 299,751 $314,824 ============ ========
The accompanying notes are an integral part of the consolidated financial statements. 40
CONSOLIDATED BALANCE SHEETS GREEN MOUNTAIN POWER CORPORATION DECEMBER 31 1999 1998 ------------- --------- CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity Common stock, $3.33 1/3 par value, authorized 10,000,000 shares (issued 5,425,571 and 5,313,296) . . . . . . . . . . $ 18,085 $ 17,711 Additional paid-in capital . . . . . . . . . . 72,594 71,914 Retained earnings. . . . . . . . . . . . . . . 10,344 17,508 Treasury stock, at cost (15,856 shares). . . . (378) (378) ------------- --------- Total common stock equity. . . . . . . . . . 100,645 106,755 Redeemable cumulative preferred stock. . . . . . 12,795 14,435 Long-term debt, less current maturities. . . . . 81,800 88,500 ------------- --------- Total capitalization . . . . . . . . . . . . 195,240 209,690 ------------- --------- CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 7,038 7,696 ------------- --------- CURRENT LIABILITIES Current maturities of preferred stock. . . . . . 1,640 1,650 Current maturities of long-term debt . . . . . . 6,700 1,700 Short-term debt. . . . . . . . . . . . . . . . . 7,900 7,000 Accounts payable, trade and accrued liabilities. 6,684 5,453 Accounts payable to associated companies . . . . 6,577 7,143 Dividends declared . . . . . . . . . . . . . . . 285 362 Customer deposits. . . . . . . . . . . . . . . . 361 336 Taxes accrued. . . . . . . . . . . . . . . . . . - 370 Interest accrued . . . . . . . . . . . . . . . . 1,169 1,203 Other. . . . . . . . . . . . . . . . . . . . . . 7,032 5,258 ------------- --------- Total current liabilities. . . . . . . . . . 38,348 30,475 ------------- --------- DEFERRED CREDITS Accumulated deferred income taxes. . . . . . . . 25,201 23,389 Unamortized investment tax credits . . . . . . . 3,978 4,260 Pine Street Barge Canal site cleanup . . . . . . 8,815 11,220 Other. . . . . . . . . . . . . . . . . . . . . . 21,132 21,020 ------------- --------- Total deferred credits . . . . . . . . . . . 59,126 59,889 ------------- --------- COMMITMENTS AND CONTINGENCIES NON-UTILITY Current liabilities. . . . . . . . . . . . . . . - 720 Other liabilities. . . . . . . . . . . . . . . . - 6,354 ------------- --------- Total non-utility liabilities. . . . . . . . - 7,074 ------------- --------- TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $ 299,752 $314,824 ============= =========
The accompanying notes are an integral part of the consolidated financial statements. 41
CONSOLIDATED CAPITALIZATION DATA GREEN MOUNTAIN POWER CORPORATION At December 31, ISSUED AND OUTSTANDING AUTHORIZED 1999 1998 1999 1998 - --------------------------------- ---------------- --------- --------- ------- CAPITAL STOCK . . . . . . . . . . (In thousands) Common Stock, $3.33 1/3 par value 10,000,000 5,425,571 5,313,296 $18,085 $17,711 ======= =======
SHARES ----------- OUTSTANDING AUTHORIZED ISSUED 1999 1998 1999 1998 ----------- -------- -------- ------- ------- ------- (In thousands) REDEEMABLE CUMULATIVE PREFERRED STOCK, $100 PAR VALUE 4.75%, Class B, redeemable at $101 per share 15,000 15,000 1,800 2,250 $ 180 $ 225 7%, Class C, redeemable at $101 per share 15,000 15,000 3,750 4,200 375 420 9.375%, Class D, Series 1, redeemable at $101 per share 40,000 40,000 4,800 6,400 480 640 8.625%, Class D, Series 3, redeemable at $100916 per share 70,000 70,000 14,000 28,000 1,400 2,800 7.32%, Class E, Series 1 200,000 120,000 120,000 120,000 12,000 12,000 ------- ------- TOTAL PREFERRED STOCK $ 14,435 $ 16,085 ======== ========
1999 1998 --------------- ------- LONG-TERM DEBT. . . . . . . . . . . . . . . . . . . . . . . . . . (In thousands) FIRST MORTGAGE BONDS 5.71% Series due 2000 . . . . . . . . . . . . . . . . . . . . . $ 5,000 $ 5,000 6.21% Series due 2001 . . . . . . . . . . . . . . . . . . . . . 8,000 8,000 6.29% Series due 2002 . . . . . . . . . . . . . . . . . . . . . 8,000 8,000 6.41% Series due 2003 . . . . . . . . . . . . . . . . . . . . . 8,000 8,000 10.0% Series due 2004 - Cash sinking fund, $1,700,000 annually. 8,500 10,200 7.05% Series due 2006 . . . . . . . . . . . . . . . . . . . . . 4,000 4,000 7.18% Series due 2006 . . . . . . . . . . . . . . . . . . . . . 10,000 10,000 6.7% Series due 2018. . . . . . . . . . . . . . . . . . . . . . 15,000 15,000 9.64% Series due 2020 . . . . . . . . . . . . . . . . . . . . . 9,000 9,000 8.65% Series due 2022 - Cash sinking fund, commences 2012 . . . 13,000 13,000 --------------- ------- Total Long-term Debt Outstanding. . . . . . . . . . . . . . . . . 88,500 90,200 Less Current Maturities (due within one year) . . . . . . . . . 6,700 1,700 --------------- ------- TOTAL LONG-TERM DEBT, NET . . . . . . . . . . . . . . . . . . . . $ 81,800 $88,500 =============== =======
The accompanying notes are an integral part of these consolidated financial statements. 42 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A. SIGNIFICANT ACCOUNTING POLICIES 1. THE COMPANY. GREEN MOUNTAIN POWER CORPORATION (THE COMPANY) IS AN INVESTOR-OWNED ELECTRIC SERVICES COMPANY LOCATED IN VERMONT THAT SERVES APPROXIMATELY ONE-QUARTER OF VERMONT'S POPULATION. THE MOST SIGNIFICANT PORTION OF THE COMPANY'S NET INCOME IS GENERATED FROM ITS REGULATED ELECTRIC UTILITY OPERATION, WHICH PURCHASES AND GENERATES ELECTRIC POWER AND DISTRIBUTES IT TO APPROXIMATELY 84,000 RETAIL AND WHOLESALE CUSTOMERS. AT DECEMBER 31, 1999, THE COMPANY'S PRIMARY SUBSIDIARY INVESTMENT WAS MOUNTAIN ENERGY INC. (MEI), WHICH HAS INVESTED IN ENERGY GENERATION, ENERGY EFFICIENCY AND WASTEWATER TREATMENT PROJECTS ACROSS THE UNITED STATES. ON JUNE 30, 1999, THE COMPANY DECIDED TO SELL OR DISPOSE OF THE ASSETS OF MEI, AND REPORT ITS RESULTS AS INCOME (LOSS) FROM OPERATIONS OF A DISCONTINUED SEGMENT. IN 1998 THE COMPANY SOLD THE ASSETS OF ITS WHOLLY OWNED SUBSIDIARY, GREEN MOUNTAIN PROPANE GAS COMPANY (GMPG). THE COMPANY'S REMAINING WHOLLY-OWNED SUBSIDIARIES (WHICH ARE NOT REGULATED BY THE VERMONT PUBLIC SERVICE BOARD (VPSB)), ARE GREEN MOUNTAIN RESOURCES, INC. (GMRI), WHICH WAS CREATED TO PARTICIPATE IN THE EMERGING RETAIL ENERGY MARKET, AND GMP REAL ESTATE CORPORATION AND LEASE-ELEC, INC. THE RESULTS OF THESE SUBSIDIARIES, EXCLUDING MEI, AND THE COMPANY'S UNREGULATED RENTAL WATER HEATER PROGRAM ARE INCLUDED IN EARNINGS OF AFFILIATES AND NON-UTILITY OPERATIONS IN THE OTHER INCOME SECTION OF THE CONSOLIDATED STATEMENTS OF INCOME. SUMMARIZED FINANCIAL INFORMATION FOR THESE SUBSIDIARIES IS AS FOLLOWS:
For the years ended December 31, 1999 1998 1997 --------------------------------- ------ ------ (In thousands) Revenue. . . . . $ 1,286 $2,876 $7,497 Expense. . . . . 184 2,857 6,849 --------------------------------- ------ ------ Net Income . . . $ 1,102 $ 19 $ 648 ================================= ====== ======
THE COMPANY CARRIES ITS INVESTMENTS IN VARIOUS ASSOCIATED COMPANIES, VERMONT YANKEE NUCLEAR POWER CORPORATION (VERMONT YANKEE), VERMONT ELECTRIC POWER COMPANY, INC. (VELCO), NEW ENGLAND HYDRO-TRANSMISSION CORPORATION, AND NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY USING THE EQUITY METHOD OF ACCOUNTING. THE COMPANY'S SHARE OF THE NET EARNINGS OR LOSSES OF THESE COMPANIES IS ALSO INCLUDED IN THE OTHER INCOME SECTION OF THE CONSOLIDATED STATEMENTS OF INCOME. SEE NOTE B AND NOTE L FOR ADDITIONAL INFORMATION. 2. BASIS OF PRESENTATION. THE COMPANY'S UTILITY OPERATIONS, INCLUDING ACCOUNTING RECORDS, RATES, OPERATIONS AND CERTAIN OTHER PRACTICES OF ITS ELECTRIC UTILITY BUSINESS, ARE SUBJECT TO THE REGULATORY AUTHORITY OF THE FEDERAL ENERGY REGULATORY COMMISSION (FERC) AND THE VPSB. THE ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS CONFORM TO GENERALLY ACCEPTED ACCOUNTING PRINCIPLES APPLICABLE TO RATE-REGULATED ENTERPRISES IN ACCORDANCE WITH STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NUMBER 71, (SFAS 71), ACCOUNTING FOR CERTAIN TYPES OF REGULATION. UNDER SFAS 71, THE COMPANY ACCOUNTS FOR CERTAIN TRANSACTIONS IN ACCORDANCE WITH PERMITTED REGULATORY TREATMENT. AS SUCH, REGULATORS MAY PERMIT INCURRED COSTS, TYPICALLY TREATED AS EXPENSES, TO BE DEFERRED AND RECOVERED IN FUTURE REVENUES. CONDITIONS THAT GIVE RISE TO THE DISCONTINUANCE OF SFAS 71 INCLUDE (1) INCREASING COMPETITION THAT RESTRICTS THE COMPANY'S ABILITY TO ESTABLISH PRICES TO RECOVER SPECIFIC COSTS, AND (2) A CHANGE IN THE MANNER IN WHICH RATES ARE SET BY REGULATORS FROM COST-BASED REGULATION TO ANOTHER FORM OF REGULATION. IN THE EVENT THAT THE COMPANY NO LONGER MEETS THE CRITERIA UNDER SFAS 71, THE COMPANY WOULD BE REQUIRED TO WRITE OFF RELATED REGULATORY ASSETS AND LIABILITIES. THE COMPANY CONTINUES TO BELIEVE, BASED ON CURRENT REGULATORY CIRCUMSTANCES, THAT THE USE OF REGULATORY ACCOUNTING UNDER SFAS 71 REMAINS APPROPRIATE AND THAT ITS REGULATORY ASSETS ARE PROBABLE OF RECOVERY. THE COMPANY IS REQUIRED TO EVALUATE LONG-LIVED ASSETS, INCLUDING REGULATORY ASSETS, FOR POTENTIAL IMPAIRMENT. ASSETS THAT ARE NO LONGER PROBABLE OF RECOVERY THROUGH FUTURE REVENUES WOULD BE REVALUED BASED UPON FUTURE CASH FLOWS. REGULATORY ASSETS ARE CHARGED TO EXPENSE IN THE PERIOD IN WHICH THEY ARE NO LONGER PROBABLE OF FUTURE RECOVERY. AS OF DECEMBER 31, 1999, BASED UPON THE REGULATORY ENVIRONMENT WITHIN WHICH THE COMPANY CURRENTLY OPERATES, THE COMPANY DOES NOT BELIEVE THAT AN IMPAIRMENT LOSS NEED BE RECORDED. COMPETITIVE INFLUENCES OR REGULATORY DEVELOPMENTS MAY IMPACT THIS STATUS IN THE FUTURE. 43 IN JUNE 1998, THE FINANCIAL ACCOUNTING STANDARDS BOARD ISSUED STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NUMBER 133 (SFAS 133), ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. SFAS 133 ESTABLISHES ACCOUNTING AND REPORTING STANDARDS REQUIRING THAT DERIVATIVE INSTRUMENTS (INCLUDING CERTAIN DERIVATIVE INSTRUMENTS EMBEDDED IN OTHER CONTRACTS) BE RECORDED IN THE BALANCE SHEET AS EITHER AN ASSET OR A LIABILITY AND MEASURED AT ITS FAIR VALUE. SFAS 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 FORMALLY DOCUMENT, DESIGNATE, AND ASSESS THE EFFECTIVENESS OF TRANSACTIONS THAT RECEIVE HEDGE ACCOUNTING. SFAS 133 IS EFFECTIVE FOR THE COMPANY BEGINNING THE FIRST QUARTER OF 2001 AND MUST BE APPLIED TO DERIVATIVE INSTRUMENTS AND EMBEDDED DERIVATIVES THAT WERE ISSUED, ACQUIRED, OR SUBSTANTIVELY MODIFIED ON OR AFTER JANUARY 1, 1998 OR JANUARY 1, 1999 (AS ELECTED BY THE COMPANY). THE COMPANY HAS A CONTRACT WITH MORGAN STANLEY TO HEDGE THE FAIR VALUE OF FOSSIL FUEL PRICES. WE ALSO SOMETIMES USE FUTURE CONTRACTS TO HEDGE FORECASTED WHOLESALE SALES OF ELECTRIC POWER, INCLUDING MATERIAL SALES COMMITMENTS AS DISCUSSED UNDER NOTE K. UNDER SFAS 133, THE COMPANY WOULD RECOGNIZE IN EARNINGS THE VALUE OF THESE HEDGING INSTRUMENTS TO THE EXTENT THAT THEY ARE INEFFECTIVE IN HEDGING EXPOSURES RELATED TO THESE CONTRACTS. THE COMPANY HAS NOT YET QUANTIFIED THE IMPACTS OF ADOPTING SFAS 133 ON ITS FINANCIAL STATEMENTS AND HAS NOT DETERMINED THE TIMING OF OR THE METHOD OF ADOPTION OF SFAS 133. HOWEVER, IT IS POSSIBLE THAT SFAS 133 COULD INCREASE VOLATILITY IN EARNINGS AND OTHER COMPREHENSIVE INCOME. 3. UTILITY PLANT. THE COST OF PLANT ADDITIONS INCLUDES ALL CONSTRUCTION-RELATED DIRECT LABOR AND MATERIALS, AS WELL AS INDIRECT CONSTRUCTION COSTS, INCLUDING THE COST OF MONEY (ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION OR AFUDC). THE COSTS OF RENEWALS AND IMPROVEMENTS OF PROPERTY UNITS ARE CAPITALIZED. THE COSTS OF MAINTENANCE, REPAIRS AND REPLACEMENTS OF MINOR PROPERTY ITEMS ARE CHARGED TO MAINTENANCE EXPENSE. THE COSTS OF UNITS OF PROPERTY REMOVED FROM SERVICE, NET OF REMOVAL COSTS AND SALVAGE, ARE CHARGED TO ACCUMULATED DEPRECIATION OVER THE ESTIMATED SERVICE LIFE OF THE UNITS. 4. DEPRECIATION. THE COMPANY PROVIDES FOR DEPRECIATION USING THE STRAIGHT-LINE METHOD BASED ON THE COST AND ESTIMATED REMAINING SERVICE LIFE OF THE DEPRECIABLE PROPERTY OUTSTANDING AT THE BEGINNING OF THE YEAR AND ADJUSTED FOR SALVAGE VALUE AND COST OF REMOVAL OF THE PROPERTY. THE ANNUAL DEPRECIATION PROVISION WAS APPROXIMATELY 3.3 PERCENT OF TOTAL DEPRECIABLE PROPERTY AT THE BEGINNING OF 1999, AND 3.4 PERCENT AT THE BEGINNING OF 1998 AND 3.2 PERCENT AT THE BEGINNING OF 1997. 5. CASH AND CASH EQUIVALENTS. CASH AND CASH EQUIVALENTS INCLUDE SHORT-TERM INVESTMENTS WITH MATURITIES LESS THAN NINETY DAYS. 6. OPERATING REVENUES. OPERATING REVENUES CONSIST PRINCIPALLY OF SALES OF ELECTRIC ENERGY. THE COMPANY RECORDS ACCRUED UTILITY REVENUES, BASED ON ESTIMATES OF ELECTRIC SERVICE RENDERED AND NOT BILLED AT THE END OF AN ACCOUNTING PERIOD, IN ORDER TO MATCH REVENUES WITH RELATED COSTS. 7. DEFERRED CHARGES. IN A MANNER CONSISTENT WITH AUTHORIZED OR EXPECTED RATEMAKING TREATMENT, THE COMPANY DEFERS AND AMORTIZES CERTAIN REPLACEMENT POWER, MAINTENANCE AND OTHER COSTS ASSOCIATED WITH THE VERMONT YANKEE NUCLEAR PLANT. IN ADDITION, THE COMPANY ACCRUES AND AMORTIZES OTHER REPLACEMENT POWER EXPENSES TO REFLECT MORE ACCURATELY ITS COST OF SERVICE TO BETTER MATCH REVENUES AND EXPENSES CONSISTENT WITH REGULATORY TREATMENT. THE COMPANY ALSO DEFERS AND AMORTIZES COSTS ASSOCIATED WITH ITS INVESTMENT IN THE DEMAND SIDE MANAGEMENT PROGRAM. AT DECEMBER 31, 1999, OTHER DEFERRED CHARGES TOTALED $18.1 MILLION, CONSISTING OF REGULATORY PROCEEDINGS EXPENSES, REGULATORY DEFERRALS OF STORM DAMAGES, RIGHTS-OF-WAY MAINTENANCE, OTHER EMPLOYEE BENEFITS, PRELIMINARY SURVEY AND INVESTIGATION CHARGES, TRANSMISSION INTERCONNECTION CHARGES AND VARIOUS OTHER PROJECTS AND DEFERRALS. 44 8. EARNINGS PER SHARE. EARNINGS PER SHARE ARE BASED ON THE WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING DURING EACH YEAR. SINCE THE COMPANY HAS NOT ISSUED ANY POTENTIALLY DILUTIVE SECURITIES, BASIC AND DILUTED EARNINGS PER SHARE ARE THE SAME. 9. MAJOR CUSTOMERS. THE COMPANY HAD ONE MAJOR RETAIL CUSTOMER, IBM, METERED AT TWO LOCATIONS, THAT ACCOUNTED FOR 11.8 PERCENT, 14.7 PERCENT, AND 14.0 PERCENT OF OPERATING REVENUES IN 1999, 1998 AND 1997, RESPECTIVELY. IBM'S PERCENT OF REVENUES IN 1999 DECREASED DUE TO AN INCREASE IN TOTAL OPERATING REVENUES CAUSED BY SALES FOR RESALE PURSUANT TO THE MORGAN STANLEY AGREEMENT. SEE NOTE K FOR FURTHER INFORMATION REGARDING THE MORGAN STANLEY AGREEMENT. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS. THE PRESENT VALUE OF THE FIRST MORTGAGE BONDS AND PREFERRED STOCK OUTSTANDING, IF REFINANCED USING PREVAILING MARKET RATES OF INTEREST, WOULD DECREASE FROM THE BALANCES OUTSTANDING AT DECEMBER 31, 1999 BY APPROXIMATELY 5.0 PERCENT. IN THE EVENT OF SUCH A REFINANCING, THERE WOULD BE NO GAIN OR LOSS, BECAUSE UNDER ESTABLISHED REGULATORY PRECEDENT, ANY SUCH DIFFERENCE WOULD BE REFLECTED IN RATES AND HAVE NO EFFECT UPON INCOME. 11. DEFERRED CREDITS. AT DECEMBER 31, 1999, THE COMPANY HAD OTHER DEFERRED CREDITS AND LONG-TERM LIABILITIES OF $30.4 MILLION, CONSISTING OF RESERVES FOR DAMAGE CLAIMS AND ENVIRONMENTAL LIABILITIES, AND ACCRUALS FOR EMPLOYEE BENEFITS. 12. USE OF ESTIMATES. THE PREPARATION OF FINANCIAL STATEMENTS IN CONFORMITY WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES REQUIRES THE USE OF ESTIMATES AND ASSUMPTIONS THAT AFFECT ASSETS AND LIABILITIES, THE DISCLOSURE OF CONTINGENT ASSETS AND LIABILITIES, AND REVENUES AND EXPENSES. ACTUAL RESULTS COULD DIFFER FROM THOSE ESTIMATES. 13. RECLASSIFICATION. CERTAIN ITEMS ON THE PRIOR YEAR'S CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN RECLASSIFIED TO BE CONSISTENT WITH THE CURRENT YEAR PRESENTATION. B. INVESTMENTS IN ASSOCIATED COMPANIES THE COMPANY ACCOUNTS FOR INVESTMENTS IN THE FOLLOWING COMPANIES BY THE EQUITY METHOD:
PERCENT INVESTMENT IN EQUITY OWNERSHIP AT DECEMBER 31 DECEMBER 31,1999 1999 1998 ------------------ --------------------- ------ (In thousands) VELCO-common. . . . . . . . . . . . . . . 29.50% $ 1,839 $1,828 VELCO-preferred . . . . . . . . . . . . . 30.00% 690 829 --------------------- ------ Total VELCO . . . . . . . . . . . . . . . 2,529 2,657 Vermont Yankee- Common. . . . . . . . . . 17.90% 9,641 9,759 New England Hydro Transmission-Common . . 3.18% 911 1,016 New England Hydro Transmission Electric- Common. . . . . . . . . . . . . . . . 3.18% 1,464 1,616 --------------------- ------ Total investment in associated companies. $ 14,545 $15,048 =========================
UNDISTRIBUTED EARNINGS IN ASSOCIATED COMPANIES TOTALED $530,000 AT DECEMBER 31, 1999. VELCO. VELCO IS A CORPORATION ENGAGED IN THE TRANSMISSION OF ELECTRIC POWER WITHIN THE STATE OF VERMONT. VELCO HAS ENTERED INTO TRANSMISSION AGREEMENTS WITH THE STATE OF VERMONT AND OTHER ELECTRIC UTILITIES, AND UNDER THESE AGREEMENTS, VELCO BILLS ALL COSTS, INCLUDING INTEREST ON DEBT AND A FIXED RETURN ON EQUITY, TO THE STATE AND OTHERS USING VELCO'S TRANSMISSION SYSTEM. THE COMPANY'S PURCHASES OF TRANSMISSION SERVICES FROM VELCO WERE $7.9 MILLION, $7.1 MILLION, AND $7.6 MILLION FOR THE YEARS 1999, 1998 AND 1997, RESPECTIVELY. 45 PURSUANT TO VELCO'S AMENDED ARTICLES OF ASSOCIATION, THE COMPANY IS ENTITLED TO APPROXIMATELY 30 PERCENT OF THE DIVIDENDS DISTRIBUTED BY VELCO. THE COMPANY HAS RECORDED ITS EQUITY IN EARNINGS ON THIS BASIS AND ALSO IS OBLIGATED TO PROVIDE ITS PROPORTIONATE SHARE OF THE EQUITY CAPITAL REQUIREMENTS OF VELCO THROUGH CONTINUING PURCHASES OF ITS COMMON STOCK, IF NECESSARY.
Summarized financial information for VELCO is as follows: AT AND FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997 --------------------------- ------- ------- (In thousands) Company's equity in net income. $ 357 $ 338 $ 354 =========================== ======= ======= Total assets. . . . . . . . . . 67,294 67,658 70,566 Less: Liabilities and long-term debt. 58,731 58,690 61,162 --------------------------- ------- ------- Net assets. . . . . . . . . . . 8,563 8,968 9,404 =========================== ======= ======= Company's equity in net assets. $ 2,529 $ 2,657 $ 2,794 =========================== ======= =======
VERMONT YANKEE. THE COMPANY IS RESPONSIBLE FOR 17.9 PERCENT OF VERMONT YANKEE'S EXPENSES OF OPERATIONS, INCLUDING COSTS OF EQUITY CAPITAL AND ESTIMATED COSTS OF DECOMMISSIONING, AND IS ENTITLED TO A SIMILAR SHARE OF THE POWER OUTPUT OF THE NUCLEAR PLANT, WHICH HAS A NET CAPACITY OF 531 MEGAWATTS. VERMONT YANKEE'S CURRENT ESTIMATE OF DECOMMISSIONING COSTS IS APPROXIMATELY $430 MILLION, OF WHICH $247 MILLION HAS BEEN FUNDED. AT DECEMBER 31, 1999, THE COMPANY'S PORTION OF THE NET UNFUNDED LIABILITY WAS $33 MILLION, WHICH IT EXPECTS WILL BE RECOVERED THROUGH RATES OVER VERMONT YANKEE'S REMAINING OPERATING LIFE. AS A SPONSOR OF VERMONT YANKEE, THE COMPANY ALSO IS OBLIGATED TO PROVIDE 20 PERCENT OF CAPITAL REQUIREMENTS NOT OBTAINED BY OUTSIDE SOURCES. DURING 1999, THE COMPANY INCURRED $33.6 MILLION IN VERMONT YANKEE ANNUAL CAPACITY CHARGES, WHICH INCLUDED $2.0 MILLION FOR INTEREST CHARGES. THE COMPANY'S SHARE OF VERMONT YANKEE'S LONG-TERM DEBT AT DECEMBER 31, 1999 WAS $17.4 MILLION. ON OCTOBER 15, 1999, THE OWNERS OF VERMONT YANKEE NUCLEAR POWER CORPORATION ACCEPTED A BID FROM AMERGEN ENERGY COMPANY FOR THE VERMONT YANKEE GENERATING PLANT. THE ASSET SALE WILL REQUIRE NUMEROUS REGULATORY APPROVALS, INCLUDING THE FEDERAL ENERGY REGULATORY COMMISSION, THE NUCLEAR REGULATORY COMMISSION, THE SECURITIES AND EXCHANGE COMMISSION AND THE VPSB. ASSUMING A FINAL CLOSING DATE FOR THE TRANSACTION OF JULY 1, 2000, AMERGEN WILL PAY VERMONT YANKEE APPROXIMATELY $23.5 MILLION FOR THE PLANT AND PROPERTY. AS A CONDITION OF THE SALE, VERMONT YANKEE'S CURRENT OWNERS WILL MAKE A ONE-TIME AND FINAL PAYMENT OF $54.3 MILLION TO PRE-PAY THE PLANT'S DECOMMISSIONING FUND. IN RETURN, AMERGEN WILL ASSUME FULL RESPONSIBILITY FOR ALL FUTURE OPERATING COSTS AND THE OBLIGATION TO DECOMMISSION THE PLANT AT THE END OF ITS LIFE. THE COMPANY HAS AGREED TO BUY POWER FROM THE PLANT FOR PERIODS THAT MAY EXTEND UP TO TWELVE YEARS. THE COMPANY AND THE OTHER CURRENT OWNERS ARE ALSO RESPONSIBLE TO VERMONT YANKEE FOR THEIR SHARE OF THE UNRECOVERED PLANT AND OTHER COSTS RESULTING FROM THE SALE. THE PRICE-ANDERSON ACT CURRENTLY SETS PUBLIC LIABILITY FROM A SINGLE INCIDENT AT A NUCLEAR POWER PLANT TO $9.5 BILLION. ANY DAMAGES BEYOND $9.5 BILLION ARE INDEMNIFIED UNDER THE PRICE-ANDERSON ACT, BUT SUBJECT TO CONGRESSIONAL APPROVAL. THE FIRST $200 MILLION OF LIABILITY COVERAGE IS THE MAXIMUM PROVIDED BY PRIVATE INSURANCE. THE SECONDARY FINANCIAL PROTECTION PROGRAM IS A RETROSPECTIVE INSURANCE PLAN PROVIDING ADDITIONAL COVERAGE UP TO $9.3 BILLION PER INCIDENT BY ASSESSING EACH OF THE 106 REACTOR UNITS THAT ARE CURRENTLY SUBJECT TO THE PROGRAM IN THE UNITED STATES A TOTAL OF $88.1 MILLION, LIMITED TO A MAXIMUM ASSESSMENT OF $10 MILLION PER INCIDENT PER NUCLEAR UNIT IN ANY ONE YEAR. THE MAXIMUM ASSESSMENT IS ADJUSTED AT LEAST EVERY FIVE YEARS TO REFLECT INFLATIONARY CHANGES. THE ABOVE INSURANCE COVERS ALL WORKERS EMPLOYED AT NUCLEAR FACILITIES FOR BODILY INJURY CLAIMS. VERMONT YANKEE RETAINS A POTENTIAL OBLIGATION FOR RETROSPECTIVE ADJUSTMENTS DUE TO PAST OPERATIONS OF SEVERAL SMALLER FACILITIES THAT DID NOT JOIN THE ABOVE INSURANCE PROGRAM. THESE EXPOSURES WILL CEASE TO EXIST NO LATER THAN DECEMBER 31, 2007. VERMONT YANKEE'S MAXIMUM RETROSPECTIVE OBLIGATION REMAINS AT $3.1 MILLION. INSURANCE HAS BEEN PURCHASED FROM NUCLEAR ELECTRIC INSURANCE LIMITED (NEIL) TO COVER THE COSTS OF PROPERTY DAMAGE, 46 DECONTAMINATION OR PREMATURE DECOMMISSIONING RESULTING FROM A NUCLEAR INCIDENT. ALL COMPANIES INSURED WITH NEIL ARE SUBJECT TO RETROACTIVE ASSESSMENTS IF LOSSES EXCEED THE ACCUMULATED FUNDS AVAILABLE. THE MAXIMUM POTENTIAL ASSESSMENT AGAINST VERMONT YANKEE WITH RESPECT TO NEIL LOSSES ARISING DURING THE CURRENT POLICY YEAR IS $10.7 MILLION. VERMONT YANKEE'S LIABILITY FOR THE RETROSPECTIVE PREMIUM ADJUSTMENT FOR ANY POLICY YEAR CEASES SIX YEARS AFTER THE END OF THAT POLICY YEAR UNLESS PRIOR DEMAND HAS BEEN MADE.
Summarized financial information for Vermont Yankee is as follows: At and for the years ended December 31, 1999 1998 1997 --------------------------- -------- -------- (In thousands) Earnings: Operating revenues . . . . . . . . . . $ 208,812 $195,249 $173,106 Net income applicable to common stock. 6,471 7,125 6,834 Company's equity in net income . . . . $ 1,165 $ 1,267 $ 1,244 =========================== ======== ======== Total assets . . . . . . . . . . . . . . $ 685,292 $635,874 $610,024 Less: Liabilities and long-term debt . . . . 631,365 581,231 555,735 --------------------------- -------- -------- Net Assets . . . . . . . . . . . . . . . $ 53,927 $ 54,643 $ 54,289 =========================== ======== ======== Company's equity in net assets . . . . . $ 9,641 $ 9,759 $ 9,701 =========================== ======== ========
C. COMMON STOCK EQUITY THE COMPANY MAINTAINS A DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN (DRIP) UNDER WHICH 232,979 SHARES WERE RESERVED AND UNISSUED AT DECEMBER 31, 1999. THE COMPANY ALSO FUNDS AN EMPLOYEE SAVINGS AND INVESTMENT PLAN (ESIP). AT DECEMBER 31, 1999, THERE WERE 38,530 SHARES RESERVED AND UNISSUED UNDER THE ESIP. DURING 1995, THE COMPANY'S BOARD OF DIRECTORS, WITH SUBSEQUENT APPROVAL OF THE COMPANY'S COMMON SHAREHOLDERS, ADOPTED THE COMPENSATION PROGRAM FOR OFFICERS AND CERTAIN KEY MANAGEMENT PERSONNEL. THE PROGRAM LINKS A PORTION OF THE OFFICERS AND KEY MANAGEMENT PERSONNEL COMPENSATION TO CORPORATE PERFORMANCE RESULTS. PARTICIPANTS ARE ENTITLED TO RECEIVE CASH, AND RESTRICTED AND UNRESTRICTED STOCK GRANTS IN PREDETERMINED PROPORTIONS. PARTICIPANTS WHO RECEIVE RESTRICTED STOCK ARE ENTITLED TO RECEIVE DIVIDENDS AND HAVE VOTING RIGHTS BUT ASSUMPTION OF FULL BENEFICIAL OWNERSHIP IS CONTINGENT UPON TWO RESTRICTIONS OF A FIVE YEAR DURATION, INCLUDING NO TRANSFERABILITY AND FORFEITURE OF THE STOCK UPON TERMINATION OF EMPLOYMENT WITH THE COMPANY. PARTICIPANTS WHO RECEIVE UNRESTRICTED STOCK ASSUME FULL BENEFICIAL OWNERSHIP UPON GRANT AND MAY RETAIN OR SELL SUCH SHARES. DURING 1999, 3,527 SHARES WERE RETURNED TO THE COMPANY RESULTING FROM THE TERMINATION OF EMPLOYMENT OF SEVERAL PARTICIPANTS. AT DECEMBER 31, 1999, THERE WERE 30,141 SHARES RESERVED AND UNISSUED UNDER THE COMPENSATION PROGRAM. 47
Changes in common stock equity for the years ended December 31, 1997, 1998 and 1999 are as follows: COMMON STOCK PAID-IN RETAINED TREASURY STOCK STOCK SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT EQUITY ------------- -------- --------- ---------- -------------- -------- --------- (Dollars in thousands) BALANCE, DECEMBER 31, 1996 . . . . 5,037,143 $16,790 $ 68,226 $ 26,916 15,856 $ (378) $111,554 ------------- -------- --------- ---------- -------------- -------- --------- Common Stock Issuance: DRIP . . . . . . . . . . . . . . . 120,631 402 2,182 2,584 ESIP . . . . . . . . . . . . . . . 26,702 89 507 596 Compensation Program: Restricted Shares . . . . . . . 6,190 21 119 140 Stock Grant . . . . . . . . . . 4,766 16 92 108 Net Income 9,438 9,438 Cash Dividends Common Stock (8,204) (8,204) Preferred Stock:$4.75 per share (13) (13) 7.00 per share (33) (33) 9.375 per share (86) (86) 8.625 per share (423) (423) 7.32 per share (878) (878) Preferred Stock Issuance Expense (406) (406) --------- --------- BALANCE, DECEMBER 31, 1997 . . . . 5,195,432 17,318 70,720 26,717 15,856 (378) 114,377 ------------- -------- --------- ---------- -------------- -------- --------- Common Stock Issuance: DRIP . . . . . . . . . . . . . . . 88,004 293 928 1,221 ESIP . . . . . . . . . . . . . . . 36,391 121 427 548 Compensation Program: - Restricted Shares . . . . . . . (6,531) (21) (161) (182) Net Loss (2,877) (2,877) Cash Dividends - Common Stock (5,036) (5,036) Preferred Stock:$4.75 per share (12) (12) 7.00 per share (32) (32) 9.375 per share (72) (72) 8.625 per share (302) (302) 7.32 per share (878) (878) ---------- --------- BALANCE, DECEMBER 31, 1998 . . . . 5,313,296 17,711 71,914 17,508 15,856 (378) 106,755 ------------- -------- --------- ---------- -------------- -------- --------- Common Stock Issuance: DRIP . . . . . . . . . . . . . . . 67,525 225 418 643 ESIP . . . . . . . . . . . . . . . 48,277 161 345 506 Compensation Program: Restricted Shares . . . . . . . (3,527) (12) (83) (95) Net Loss (3,063) (3,063) Cash Dividends Common Stock (2,946) (2,946) Preferred Stock:$4.75 per share (10) (10) 7.00 per share (29) (29) 9.375 per share (57) (57) 8.625 per share (181) (181) 7.32 per share (878) (878) ---------- --------- BALANCE, DECEMBER 31, 1999 . . . . 5,425,571 $18,085 $ 72,594 $ 10,344 15,856 $ (378) $100,645 ============= ======== ========= ========== ============== ======== =========
DIVIDEND RESTRICTIONS. CERTAIN RESTRICTIONS ON THE PAYMENT OF CASH DIVIDENDS ON COMMON STOCK ARE CONTAINED IN THE COMPANY'S INDENTURES RELATING TO LONG-TERM DEBT AND IN THE RESTATED ARTICLES OF ASSOCIATION. UNDER THE MOST RESTRICTIVE OF SUCH PROVISIONS, APPROXIMATELY $10.3 MILLION OF RETAINED EARNINGS WERE FREE OF RESTRICTIONS AT DECEMBER 31, 1999. THE PROPERTIES OF THE COMPANY INCLUDE SEVERAL HYDROELECTRIC PROJECTS LICENSED UNDER THE FEDERAL POWER ACT, WITH LICENSE EXPIRATION DATES RANGING FROM 2001 TO 2025. AT DECEMBER 31, 1999, $34,000 OF RETAINED EARNINGS HAD BEEN 48 APPROPRIATED AS EXCESS EARNINGS ON HYDROELECTRIC PROJECTS AS REQUIRED BY SECTION 10(D) OF THE FEDERAL POWER ACT. D. PREFERRED STOCK THE HOLDERS OF THE PREFERRED STOCK ARE ENTITLED TO SPECIFIC VOTING RIGHTS WITH RESPECT TO CERTAIN TYPES OF CORPORATE ACTIONS. THEY ARE ALSO ENTITLED TO ELECT THE SMALLEST NUMBER OF DIRECTORS NECESSARY TO CONSTITUTE A MAJORITY OF THE BOARD OF DIRECTORS IN THE EVENT OF PREFERRED STOCK DIVIDEND ARREARAGES EQUIVALENT TO OR EXCEEDING FOUR QUARTERLY DIVIDENDS. SIMILARLY, THE HOLDERS OF THE PREFERRED STOCK ARE ENTITLED TO ELECT TWO DIRECTORS IN THE EVENT OF DEFAULT IN ANY PURCHASE OR SINKING FUND REQUIREMENTS PROVIDED FOR ANY CLASS OF PREFERRED STOCK. CERTAIN CLASSES OF PREFERRED STOCK ARE SUBJECT TO ANNUAL PURCHASE OR SINKING FUND REQUIREMENTS. THE SINKING FUND REQUIREMENTS ARE MANDATORY. THE PURCHASE FUND REQUIREMENTS ARE MANDATORY, BUT HOLDERS MAY ELECT NOT TO ACCEPT THE PURCHASE OFFER. THE REDEMPTION OR PURCHASE PRICE TO SATISFY THESE REQUIREMENTS MAY NOT EXCEED $100 PER SHARE PLUS ACCRUED DIVIDENDS. ALL SHARES REDEEMED OR PURCHASED IN CONNECTION WITH THESE REQUIREMENTS MUST BE CANCELED AND MAY NOT BE REISSUED. THE ANNUAL PURCHASE AND SINKING FUND REQUIREMENTS FOR THE YEAR 2000 FOR CERTAIN CLASSES OF PREFERRED STOCK ARE AS FOLLOWS:
Purchase and Sinking Fund Shares to Class Due dates Retire 8.625% Class D, Series 3 1-Sep 14,000 4.750% Class B . . . . . 1-Dec 350 7.000% Class C . . . . . 1-Dec 450 9.375% Class D, Series 1 1-Dec 1,600
UNDER THE RESTATED ARTICLES OF ASSOCIATION RELATING TO REDEEMABLE CUMULATIVE PREFERRED STOCK, THE ANNUAL AGGREGATE AMOUNT OF PURCHASE AND SINKING FUND REQUIREMENTS FOR THE NEXT FIVE YEARS ARE $1,640,000 FOR 2000, $235,000 EACH FOR 2001 AND 2002, $75,000 EACH FOR 2003 AND 2004, AND $175,000 THEREAFTER. CERTAIN CLASSES OF PREFERRED STOCK ARE REDEEMABLE AT THE OPTION OF THE COMPANY OR, IN THE CASE OF VOLUNTARY LIQUIDATION, AT VARIOUS PRICES ON VARIOUS DATES. THE PRICES INCLUDE THE PAR VALUE OF THE ISSUE PLUS ANY ACCRUED DIVIDENDS AND A REDEMPTION PREMIUM. THE REDEMPTION PREMIUM FOR CLASS B, C AND D, SERIES 1, IS $1.00 PER SHARE. E. LONG-TERM DEBT SUBSTANTIALLY ALL OF THE PROPERTY AND FRANCHISES OF THE COMPANY ARE SUBJECT TO THE LIEN OF THE INDENTURE UNDER WHICH FIRST MORTGAGE BONDS HAVE BEEN ISSUED. THE WEIGHTED AVERAGE RATE ON LONG TERM BORROWINGS OUTSTANDING WAS 7.5 PERCENT AT BOTH DECEMBER 31, 1999 AND 1998. THE ANNUAL SINKING FUND REQUIREMENTS (EXCLUDING AMOUNTS THAT MAY BE SATISFIED BY PROPERTY ADDITIONS) AND LONG-TERM DEBT MATURITIES FOR THE NEXT FIVE YEARS ARE:
Sinking FUND MATURITIES TOTAL --------------- ----------- ------ (In thousands) 2000 $ 1,700 $ 5,000 $6,700 2001 1,700 8,000 9,700 2002 1,700 8,000 9,700 2003 1,700 8,000 9,700 2004 1,700 1,700
49 F. SHORT-TERM DEBT THE COMPANY HAS A REVOLVING CREDIT AGREEMENT IN THE AMOUNT OF $15 MILLION WITH TWO BANKS, WITH BORROWINGS OUTSTANDING OF $7.9 MILLION AND $7.0 MILLION AT DECEMBER 31, 1999, AND 1998 RESPECTIVELY. THE COMPANY ALSO HAS AN UNCOMMITTED LINE OF CREDIT IN THE AMOUNT OF $500,000, UNDER WHICH NO AMOUNTS WERE OUTSTANDING AT DECEMBER 31, 1999 OR 1998. THE WEIGHTED AVERAGE INTEREST RATE ON SHORT-TERM BORROWINGS OUTSTANDING AT DECEMBER 31, 1999 AND DECEMBER 31, 1998 WAS 9.0 PERCENT AND 6.2 PERCENT, RESPECTIVELY. THERE WAS NO NON-UTILITY SHORT-TERM DEBT OUTSTANDING AT DECEMBER 31, 1999. THE REVOLVING CREDIT AGREEMENT REQUIRES THE COMPANY TO CERTIFY ON A QUARTERLY BASIS THAT IT HAS NOT SUFFERED A "MATERIAL ADVERSE CHANGE". SIMILARLY, AS A CONDITION TO FURTHER BORROWINGS, WE MUST CERTIFY THAT NO EVENT HAS OCCURRED OR FAILED TO OCCUR THAT HAS HAD OR WOULD REASONABLY BE EXPECTED TO HAVE A MATERIALLY ADVERSE EFFECT ON THE COMPANY SINCE THE DATE THAT WE LAST BORROWED UNDER THIS AGREEMENT. THE CURRENT AGREEMENT ALLOWS THE COMPANY TO CONTINUE TO BORROW UNTIL SUCH TIME THAT: * A "MATERIAL ADVERSE EFFECT" HAS OCCURRED; * IT IS NO LONGER IN COMPLIANCE WITH ALL OTHER PROVISIONS OF THE AGREEMENT, IN WHICH CASE FURTHER BORROWING WILL NOT BE PERMITTED; OR * THERE HAS BEEN A "MATERIAL ADVERSE CHANGE", IN WHICH CASE THE BANKS MAY DECLARE THE COMPANY IN DEFAULT. TERMS ALSO CALL IN PART FOR THE FOLLOWING: * A SECOND PRIORITY MORTGAGE, LIEN AND SECURITY INTEREST IN THE COLLATERAL PLEDGED UNDER THE FIRST MORTGAGE BOND INDENTURE GRANTED TO THE BANKS; AND * THE TOTAL AMOUNT AVAILABLE WILL BE REDUCED BY THE NET PROCEEDS FROM CERTAIN SALES, SUCH AS THE SALE OF ASSETS OF THE DISCONTINUED SEGMENT MEI. THERE ARE A NUMBER OF FUTURE EVENTS THAT, SINGULARLY OR IN COMBINATION, COULD LEAD THE BANKS TO REFUSE TO ALLOW FURTHER BORROWINGS UNDER THE EXISTING CREDIT AGREEMENT, TO SEEK TO ENTER INTO A NEW CREDIT AGREEMENT WITH THE COMPANY AND/OR TO IMMEDIATELY CALL IN ALL OUTSTANDING LOANS. SOME OF THOSE EVENTS ARE: * THE VPSB ISSUES AN ORDER IN A RATE CASE THAT TRIGGERS A "MATERIAL ADVERSE CHANGE" FOR THE COMPANY; OR * HYDRO-QUEBEC IS UNWILLING TO MAKE NEW ARRANGEMENT REGARDING THE COST OF OUR CONTRACT WITH THEM. IF WE ARE UNABLE TO BORROW ON A SHORT-TERM BASIS, WE WILL EVALUATE ALL POTENTIAL ALTERNATIVES AVAILABLE TO US AT THE TIME, INCLUDING, BUT NOT LIMITED TO, ELIMINATING COMMON STOCK DIVIDENDS AND THE FILING OF A PETITION FOR REORGANIZATION UNDER THE UNITED STATES BANKRUPTCY CODE. G. INCOME TAXES UTILITY. THE COMPANY ACCOUNTS FOR INCOME TAXES USING THE LIABILITY METHOD. THIS METHOD ACCOUNTS FOR DEFERRED INCOME TAXES BY APPLYING STATUTORY RATES TO THE DIFFERENCES BETWEEN THE BOOK AND TAX BASES OF ASSETS AND LIABILITIES. THE REGULATORY TAX ASSETS AND LIABILITIES REPRESENT TAXES THAT WILL BE COLLECTED FROM OR RETURNED TO CUSTOMERS THROUGH RATES IN FUTURE PERIODS. AS OF DECEMBER 31, 1999 AND 1998, THE NET REGULATORY ASSETS WERE $1,805,000 AND $2,214,000 RESPECTIVELY, AND INCLUDED IN OTHER DEFERRED CHARGES ON THE COMPANY'S CONSOLIDATED BALANCE SHEETS. THE TEMPORARY DIFFERENCES WHICH GAVE RISE TO THE NET DEFERRED TAX LIABILITY AT DECEMBER 31, 1999 AND DECEMBER 31, 1998, WERE AS FOLLOWS: 50
AT DECEMBER 31, 1999 1998 ----------------- -------- DEFERRED TAX ASSETS (In thousands) Contributions in aid of construction $ 9,056 $ 8,551 Deferred compensation and 3,372 4,455 postretirement benefits Alternative minimum tax credit - (56) Self insurance and other reserves 3,664 2,009 Pine Street reserve (25) 2,469 Other 1,183 995 ----------------- -------- $ 17,250 $18,423 ----------------- -------- DEFERRED TAX LIABILITIES Property related $ 37,921 $34,806 Demand side management 2,328 3,557 Deferred purch power costs 2,202 3,449 ----------------- -------- $ 42,451 $41,812 ----------------- -------- Net accumulated deferred income tax liability $ 25,201 $23,389 ================= ========
THE FOLLOWING TABLE RECONCILES THE CHANGE IN THE NET ACCUMULATED DEFERRED INCOME TAX LIABILITY TO THE DEFERRED INCOME TAX EXPENSE INCLUDED IN THE INCOME STATEMENT FOR THE PERIOD:
YEARS ENDED DECEMBER 31, 1999 1998 1997 -------------------------- ------ -------- (In thousands) Net change in deferred income tax $ 1,812 $(112) $(3,225) liability Change in income tax related regulatory assets and liabilities 176 510 509 Change in alternative minimum tax credit - (70) 567 -------------------------- ------ -------- Deferred income tax expense (benefit) $ 1,988 $ 328 $(2,149) ========================== ====== ========
THE COMPONENTS OF THE PROVISION FOR INCOME TAXES ARE AS FOLLOWS:
YEARS ENDED DECEMBER 31, 1999 1998 1997 -------------------------- -------- -------- (In thousands) Current federal income taxes . $ (339) $(1,047) $ 7,355 Current state income taxes . . (125) (366) 2,267 -------------------------- -------- -------- Total current income taxes . . (464) (1,413) 9,622 Deferred federal income taxes. 1,479 219 (1,623) Deferred state income taxes. . 509 109 (526) -------------------------- -------- -------- Total deferred income taxes. . 1,988 328 (2,149) Investment tax credits-net . . (282) (282) (282) -------------------------- -------- -------- Income tax provision (benefit) $ 1,242 $(1,367) $ 7,191 ========================== ======== ========
51 TOTAL INCOME TAXES DIFFER FROM THE AMOUNTS COMPUTED BY APPLYING THE FEDERAL STATUTORY TAX RATE TO INCOME BEFORE TAXES. THE REASONS FOR THE DIFFERENCES ARE AS FOLLOWS:
YEARS ENDED DECEMBER 31, 1999 1998 1997 -------------------------- -------- -------- (In thousands) Income (loss) before income taxes and . . . . . . . . $ (1,821) $(4,244) $16,629 preferred dividends Federal statutory rate. . . . . . . . . . . . . . . . 34.0% 34.0% 34.5% Computed "expected" federal income taxes . . . . . . . . . . . . . . . . . . . . . . . (619) (1,443) 5,730 Increase (decrease) in taxes resulting from: Tax versus book depreciation. . . . . . . . . . . . . 92 153 349 Dividends received and paid credit. . . . . . . . . . (485) (480) (575) AFUDC-equity funds. . . . . . . . . . . . . . . . . . (5) (36) (123) Amortization of ITC . . . . . . . . . . . . . . . . . (282) (282) (282) State tax (benefit) . . . . . . . . . . . . . . . . . 383 (256) 1,741 Excess deferred taxes . . . . . . . . . . . . . . . . (60) (60) (60) Tax attributable to subsidiaries. . . . . . . . . . . 2,271 845 682 Other . . . . . . . . . . . . . . . . . . . . . . . . (53) 192 (271) -------------------------- -------- -------- Total federal and state income taxes. . . . . . . . . $ 1,242 $(1,367) $ 7,191 ========================== ======== ======== Effective combined federal and state income tax rate. -68.2% 32.2% 43.2%
NON-UTILITY. THE COMPANY'S NON-UTILITY SUBSIDIARIES, EXCLUDING MEI, HAD ACCUMULATED DEFERRED INCOME TAXES OF APPROXIMATELY $40,000 ON THEIR BALANCE SHEETS AT DECEMBER 31, 1999, LARGELY ATTRIBUTABLE TO PROPERTY-RELATED TRANSACTIONS. THE COMPONENTS OF THE PROVISION FOR THE INCOME TAX EXPENSE (BENEFIT) FOR THE NON-UTILITY OPERATIONS ARE:
YEARS ENDED DECEMBER 31, 1999 1998 1997 -------------------------- ------ -------- (In thousands) State income taxes . . . . . $ 99 $(281) $ (20) Federal income taxes . . . . 310 (202) (1,122) -------------------------- ------ -------- Income tax expense (benefit) $ 409 $(483) $(1,142) ========================== ====== ========
THE EFFECTIVE COMBINED FEDERAL AND STATE INCOME TAX RATES FOR THE CONTINUING NON-UTILITY OPERATIONS WERE 34.0 PERCENT, 32.6 PERCENT, AND 37.0 PERCENT, FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997, RESPECTIVELY. SEE NOTE L FOR INCOME TAX INFORMATION ON DISCONTINUED OPERATIONS OF SUBSIDIARIES. H. PENSION AND RETIREMENT PLANS. THE COMPANY HAS A DEFINED BENEFIT PENSION PLAN COVERING SUBSTANTIALLY ALL OF ITS EMPLOYEES. THE RETIREMENT BENEFITS ARE BASED ON THE EMPLOYEES' LEVEL OF COMPENSATION AND LENGTH OF SERVICE. THE COMPANY'S POLICY IS TO FUND ALL ACCRUED PENSION COSTS. THE COMPANY RECORDS ANNUAL EXPENSE AND ACCOUNTS FOR ITS PENSION PLAN IN ACCORDANCE WITH STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NUMBER 87, EMPLOYERS' ACCOUNTING FOR PENSIONS. THE COMPANY PROVIDES CERTAIN HEALTH CARE BENEFITS FOR RETIRED EMPLOYEES AND THEIR DEPENDENTS. EMPLOYEES BECOME ELIGIBLE FOR THESE BENEFITS IF THEY REACH NORMAL RETIREMENT AGE WHILE WORKING FOR THE COMPANY. THE COMPANY ACCRUES THE COST OF THESE BENEFITS DURING THE SERVICE LIFE OF COVERED EMPLOYEES. ACCRUED POSTRETIREMENT HEALTH CARE EXPENSES ARE RECOVERED IN RATES IF THOSE EXPENSES ARE FUNDED. IN ORDER TO MAXIMIZE THE TAX-DEDUCTIBLE CONTRIBUTIONS THAT ARE ALLOWED UNDER IRS REGULATIONS, THE COMPANY AMENDED ITS PENSION PLAN TO ESTABLISH A 401-H SUB-ACCOUNT AND SEPARATE VEBA TRUSTS FOR ITS 52 UNION AND NON-UNION EMPLOYEES. THE VEBA PLAN ASSETS CONSIST PRIMARILY OF CASH EQUIVALENT FUNDS, FIXED INCOME SECURITIES AND EQUITY SECURITIES. THE FOLLOWING PROVIDES A RECONCILIATION OF BENEFIT OBLIGATIONS, PLAN ASSETS, AND FUNDED STATUS OF THE PLANS AS OF DECEMBER 31, 1999 AND 1998.
Other Pension Benefits Postretirement Benefits ------------------ ------------------------- 1999 1998 1999 1998 ------------------ -------- ------------------------- -------- (In thousands) Change in projected benefit obligation: Projected benefit obligation as of prior year end. $ 30,860 $28,630 $ 12,552 $11,046 Service cost . . . . . . . . . . . . . . . . . . . 620 787 240 282 Interest cost. . . . . . . . . . . . . . . . . . . 1,780 2,043 855 799 Special termination benefit. . . . . . . . . . . . 5,385 2,026 1,446 44 Change in actuarial assumptions. . . . . . . . . . - - (1,372) 897 Settlements. . . . . . . . . . . . . . . . . . . . (9,527) - - - Actuarial (gain) loss. . . . . . . . . . . . . . . (2,080) 438 (70) - Benefits paid. . . . . . . . . . . . . . . . . . . (4,312) (3,064) (864) (558) Curtailment. . . . . . . . . . . . . . . . . . . . (282) - (832) 42 ------------------ -------- ------------------------- -------- Projected benefit obligation as of year end. . . . $ 22,444 $30,860 $ 11,955 $12,552 ================== ======== ========================= ======== Change in plan assets: Fair value of plan assets as of prior year end . . $ 38,030 $35,773 $ 9,735 $ 7,893 Contribution . . . . . . . . . . . . . . . . . . . - - - 76 Actual return on plan assets . . . . . . . . . . . 7,286 5,321 1,327 1,766 Benefits paid. . . . . . . . . . . . . . . . . . . (13,689) (3,064) - - ------------------ -------- ------------------------- -------- Fair value of plan assets as of year end . . . . . $ 31,627 $38,030 $ 11,062 $ 9,735 ================== ======== ========================= ======== Funded status as of year end . . . . . . . . . . . $ 9,032 $ 7,170 $ (893) $(2,817) Unrecognized transition obligation (asset) . . . . (571) (1,021) 4,264 4,926 Unrecognized prior service cost. . . . . . . . . . 887 1,113 (635) (743) Unrecognized net actuarial gain. . . . . . . . . . (12,193) (7,569) (3,589) (1,471) ------------------ -------- ------------------------- -------- Accrued benefits at year end . . . . . . . . . . . $ (2,845) $ (307) $ (853) $ (105) ================== ======== ========================= ========
THE PENSION PLAN ASSETS CONSIST PRIMARILY OF CASH EQUIVALENT FUNDS, FIXED INCOME SECURITIES AND EQUITY SECURITIES. THE COMPANY ALSO HAS A SUPPLEMENTAL PENSION PLAN FOR CERTAIN EMPLOYEES. PENSION COSTS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 WERE $556,000, $397,000 AND $456,000, RESPECTIVELY, UNDER THIS PLAN. THIS PLAN IS FUNDED IN PART THROUGH INSURANCE CONTRACTS. NET PERIODIC PENSION EXPENSE AND OTHER POSTRETIREMENT BENEFIT COSTS INCLUDE THE FOLLOWING COMPONENTS: 53
For the years ended December 31, Pension Benefits Other Postretirement Benefits 1999 1998 1997 1999 1998 1997 -------- -------- -------- ------ ------ ------ (In thousands) Service cost . . . . . . . . . . . . . . . . . $ 620 $ 787 $ 720 $ 240 $ 282 $ 228 interest cost. . . . . . . . . . . . . . . . . 1,780 2,043 2,069 855 799 763 Expected return on on plan assets. . . . . . . (2,721) (3,081) (2,739) (834) (671) (539) Amortization of transition asset . . . . . . . (196) (228) (228) - - - Amortization of net gain from earlier periods. - - - - - (28) Amortization of prior service cost . . . . . . 128 134 143 (60) (61) (61) Amortization of the transition obligation. . . - - - 340 351 351 Recognized net actuarial gain. . . . . . . . . (196) (195) (83) (19) - - Special termination benefit. . . . . . . . . . 3,122 2,026 - 888 27 - Regulatory deferral. . . . . . . . . . . . . . (3,122) (2,026) (888) (27) Adjustments due to actions of regulator. . . . - - 126 - - - -------- -------- -------- ------ ------ ------ Net periodic benefit cost. . . . . $ (585) $ (540) $ 8 $ 522 $ 700 $ 714 ======== ======== ======== ====== ====== ======
ASSUMPTIONS USED TO DETERMINE POSTRETIREMENT BENEFIT COSTS AND THE RELATED BENEFIT OBLIGATION WERE:
Other Pension benefits Postretirement benefits ----------------- ------------------------ 1999 1998 1999 1998 ----------------- ----- ------------------------ ----- Weighted average assumptions as of year end: Discount rate. . . . . . . . . . . . . . . . 7.50% 6.75% 7.50% 6.75% Expected return on plan assets . . . . . . . 9.00% 9.00% 8.50% 8.50% Rate of compensation increase. . . . . . . . 4.50% 4.00%
FOR MEASUREMENT PURPOSES, A 5.6 PERCENT ANNUAL RATE OF INCREASE IN THE PER CAPITA COST OF COVERED MEDICAL BENEFITS WAS ASSUMED FOR 1999. THE RATE WAS ASSUMED TO DECLINE UNIFORMLY TO 5.0 PERCENT FOR THE YEAR 2001 AND REMAINS AT THAT LEVEL THEREAFTER. THE HEALTH CARE COST TREND RATE ASSUMPTION HAS A SIGNIFICANT EFFECT ON THE AMOUNTS REPORTED. FOR EXAMPLE, INCREASING THE ASSUMED HEALTH CARE COST TREND RATE BY ONE PERCENTAGE POINT FOR ALL FUTURE YEARS WOULD INCREASE THE ACCUMULATED POSTRETIREMENT BENEFIT OBLIGATION AS OF DECEMBER 31, 1999 BY $1.5 MILLION AND THE TOTAL OF THE SERVICE AND INTEREST COST COMPONENTS OF NET PERIODIC POSTRETIREMENT COST FOR THE YEAR ENDED DECEMBER 31, 1999 BY $172,000. DECREASING THE TREND RATE BY ONE PERCENTAGE POINT FOR ALL FUTURE YEARS WOULD DECREASE THE ACCUMULATED POSTRETIREMENT BENEFIT OBLIGATION AT DECEMBER 31, 1999 BY $1.1 MILLION, AND THE TOTAL OF THE SERVICE AND INTEREST COST COMPONENTS OF NET PERIODIC POSTRETIREMENT COST FOR 1999 BY $139,000. IN 1999, THE COMPANY DEFERRED SPECIAL TERMINATION PENSION BENEFIT COSTS OF $3,122,000 DUE TO AN EARLY RETIREMENT PROGRAM AND OTHER EMPLOYEE SEPARATION ACTIVITIES. CURTAILMENT AND SETTLEMENT GAINS OF $2.3 MILLION ARE INCLUDED IN THE SPECIAL TERMINATION PENSION BENEFIT COST. THE SPECIAL TERMINATION BENEFIT RECORDED IN 1998 RESULTED FROM THE EARLY RETIREMENT OPTION OFFERED TO EMPLOYEES IN 1998. ALSO IN 1999, THE COMPANY DEFERRED SPECIAL TERMINATION POSTRETIREMENT BENEFIT COSTS OF $888,000 DUE TO AN EARLY RETIREMENT PROGRAM. MANAGEMENT BELIEVES THAT THE AMOUNTS DEFERRED ARE PROBABLE OF RECOVERY. PRIOR TO 1998, THE COMPANY RECORDED ANNUAL EXPENSE AND PREPAID (ACCRUED) BENEFIT COST ON THE CASH BASIS IN ACCORDANCE WITH METHODS APPROVED IN THE RATE-SETTING PROCESS. THE ADJUSTMENT TO ACCOMPLISH THIS ACCOUNTING WAS THROUGH THE LINE ITEM "ADJUSTMENTS DUE TO ACTIONS OF REGULATOR". 54 I. COMMITMENTS AND CONTINGENCIES 1. INDUSTRY RESTRUCTURING. THE ELECTRIC UTILITY BUSINESS IS BEING SUBJECTED TO RAPIDLY INCREASING COMPETITIVE PRESSURES STEMMING FROM A COMBINATION OF TRENDS, INCLUDING THE PRESENCE OF SURPLUS GENERATING CAPACITY, A DISPARITY IN ELECTRIC RATES AMONG AND WITHIN VARIOUS REGIONS OF THE COUNTRY, IMPROVEMENTS IN GENERATION EFFICIENCY, INCREASING DEMAND FOR CUSTOMER CHOICE, AND NEW REGULATIONS AND LEGISLATION INTENDED TO FOSTER COMPETITION. 2. ENVIRONMENTAL MATTERS. THE ELECTRIC INDUSTRY TYPICALLY USES OR GENERATES A RANGE OF POTENTIALLY HAZARDOUS PRODUCTS IN ITS OPERATIONS. THE COMPANY MUST MEET VARIOUS LAND, WATER, AIR AND AESTHETIC REQUIREMENTS AS ADMINISTERED BY LOCAL, STATE AND FEDERAL REGULATORY AGENCIES. WE BELIEVE THAT WE ARE IN SUBSTANTIAL COMPLIANCE WITH THOSE REQUIREMENTS, AND THAT THERE ARE NO OUTSTANDING MATERIAL COMPLAINTS ABOUT OUT COMPLIANCE WITH PRESENT ENVIRONMENTAL PROTECTION REGULATIONS, EXCEPT FOR DEVELOPMENTS RELATED TO THE PINE STREET BARGE CANAL SITE. THE COMPANY MAINTAINS AN ENVIRONMENTAL COMPLIANCE AND MONITORING PROGRAM THAT INCLUDES EMPLOYEE TRAINING, REGULAR INSPECTION OF COMPANY FACILITIES, RESEARCH AND DEVELOPMENT PROJECTS, WASTE HANDLING AND SPILL PREVENTION PROCEDURES AND OTHER ACTIVITIES. PINE STREET BARGE CANAL SITE. THE FEDERAL COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION, AND LIABILITY ACT (CERCLA), COMMONLY KNOWN AS THE "SUPERFUND" LAW, GENERALLY IMPOSES STRICT, JOINT AND SEVERAL LIABILITY, REGARDLESS OF FAULT, FOR REMEDIATION OF PROPERTY CONTAMINATED WITH HAZARDOUS SUBSTANCES. THE COMPANY HAS BEEN NOTIFIED BY THE ENVIRONMENTAL PROTECTION AGENCY (EPA) THAT IT IS ONE OF SEVERAL POTENTIALLY RESPONSIBLE PARTIES (PRPS) FOR CLEANUP OF THE PINE STREET BARGE CANAL SITE IN BURLINGTON, VERMONT, WHERE COAL TAR AND OTHER INDUSTRIAL MATERIALS WERE DEPOSITED. IN SEPTEMBER 1999, WE NEGOTIATED A FINAL SETTLEMENT WITH THE UNITED STATES, THE STATE OF VERMONT, AND OTHER PARTIES OVER TERMS OF A CONSENT DECREE THAT COVERS CLAIMS ADDRESSED IN THE EARLIER NEGOTIATIONS AND IMPLEMENTATION OF THE SELECTED REMEDY. IN NOVEMBER 1999, THE CONSENT DECREE WAS FILED IN THE FEDERAL DISTRICT COURT. THE CONSENT DECREE ADDRESSES CLAIMS BY THE EPA FOR PAST PINE STREET BARGE CANAL SITE COSTS, NATURAL RESOURCE DAMAGE CLAIMS AND CLAIMS FOR PAST AND FUTURE OVERSIGHT COSTS. THE CONSENT DECREE ALSO PROVIDES FOR THE DESIGN AND IMPLEMENTATION OF RESPONSE ACTIONS AT THE SITE. AS OF DECEMBER 31, 1999, THE COMPANY'S TOTAL EXPENDITURES RELATED TO THE PINE STREET BARGE CANAL SITE SINCE 1982 WERE APPROXIMATELY $22.2 MILLION. THIS INCLUDES THOSE AMOUNTS NOT RECOVERED IN RATES, AMOUNTS RECOVERED IN RATES, AND AMOUNTS FOR WHICH RATE RECOVERY HAS BEEN SOUGHT BUT WHICH ARE PRESENTLY AWAITING FURTHER VPSB ACTION. THE BULK OF THESE EXPENDITURES CONSISTED OF TRANSACTION COSTS. TRANSACTION COSTS INCLUDE LEGAL AND CONSULTING COSTS ASSOCIATED WITH THE COMPANY'S OPPOSITION TO THE EPA'S EARLIER PROPOSALS FOR THE SITE, AS WELL AS LITIGATION AND RELATED COSTS NECESSARY TO OBTAIN SETTLEMENTS WITH INSURERS AND OTHER PRP'S TO PROVIDE AMOUNTS REQUIRED TO FUND THE CLEAN UP (REMEDIATION COSTS) AND TO ADDRESS LIABILITY CLAIMS AT THE SITE. A SMALLER AMOUNT OF PAST EXPENDITURES WAS FOR SITE-RELATED RESPONSE COSTS, INCLUDING COSTS INCURRED PURSUANT TO THE EPA AND STATE ORDERS THAT RESULTED IN FUNDING RESPONSE ACTIVITIES AT THE SITE, AND TO REIMBURSING THE EPA AND THE STATE FOR OVERSIGHT AND RELATED RESPONSE COSTS. THE EPA AND THE STATE HAVE ASSERTED AND AFFIRMED THAT ALL COSTS RELATED TO THESE ORDERS ARE APPROPRIATE COSTS OF RESPONSE UNDER CERCLA FOR WHICH THE COMPANY AND OTHER PRPS WERE LEGALLY RESPONSIBLE. WE ESTIMATE THAT WE HAVE RECOVERED OR SECURED, OR WILL RECOVER, THROUGH SETTLEMENTS OF LITIGATION CLAIMS AGAINST INSURERS AND OTHER PARTIES, AMOUNTS THAT EXCEED ESTIMATED FUTURE REMEDIATION COSTS, FUTURE FEDERAL AND STATE GOVERNMENT OVERSIGHT COSTS AND PAST EPA RESPONSE COSTS. WE HAVE RECENTLY CONCLUDED THAT OUR UNRECOVERED TRANSACTION COSTS MENTIONED ABOVE, WHICH WERE NECESSARY TO RECOVER SETTLEMENTS SUFFICIENT TO REMEDIATE THE SITE, TO OPPOSE MUCH MORE COSTLY SOLUTIONS PROPOSED BY THE EPA, TO RESOLVE MONETARY CLAIMS OF THE EPA AND THE STATE AND TO REMEDIATE THE SITE, ARE LIKELY TO BE IN THE RANGE OF $8.7 TO $12.5 MILLION, RATHER THAN THE $5.0 TO $9.0 MILLION PREVIOUSLY ESTIMATED. IN 1998, WE RECORDED A LIABILITY OF $5 MILLION TO RECOGNIZE THE LOW END OF THIS RANGE OF COSTS. IN 1999 WE RECORDED AN ADDITIONAL LIABILITY OF $3.7 MILLION TO REFLECT REVISED ESTIMATES OF SITE MONITORING COSTS TO BE INCURRED OVER THE NEXT 33 YEARS. THE ESTIMATED LIABILITY IS NOT DISCOUNTED, AND IT IS POSSIBLE THAT OUR ESTIMATE OF FUTURE COSTS COULD CHANGE BY A MATERIAL AMOUNT. WHILE THE VPSB MAY CHALLENGE FULL RATE RECOVERY OF THE DEFERRED PINE STREET COSTS, AN OFFSETTING REGULATORY ASSET HAS BEEN RECORDED BECAUSE WE BELIEVE THAT IT IS PROBABLE THAT THESE COSTS WILL BE RECOVERED IN FUTURE REVENUES. 55 CLEAN AIR ACT. THE COMPANY PURCHASES MOST OF ITS POWER SUPPLY FROM OTHER UTILITIES AND DOES NOT ANTICIPATE THAT IT WILL INCUR ANY MATERIAL DIRECT COSTS AS A RESULT OF THE FEDERAL CLEAN AIR ACT OR PROPOSALS TO MAKE MORE STRINGENT REGULATIONS UNDER THAT ACT. 3. OPERATING LEASES. THE COMPANY TERMINATED AN OPERATING LEASE FOR ITS CORPORATE HEADQUARTERS BUILDING AND TWO OF ITS SERVICE CENTER BUILDINGS IN THE FIRST QUARTER OF 1999. DURING 1998, THE COMPANY RECORDED A LOSS OF APPROXIMATELY $1.9 MILLION BEFORE APPLICABLE INCOME TAXES TO REFLECT THE PROBABLE LOSS RESULTING FROM THIS TRANSACTION. THE COMPANY SOLD ITS CORPORATE HEADQUARTERS BUILDING IN 1999, BUT RETAINED OWNERSHIP OF THE TWO SERVICE CENTERS. 4. JOINTLY-OWNED FACILITIES. THE COMPANY HAS JOINT-OWNERSHIP INTERESTS IN ELECTRIC GENERATING AND TRANSMISSION FACILITIES AT DECEMBER 31, 1999, AS FOLLOWS:
Ownership Share of Utility Accumulated INTEREST CAPACITY PLANT DEPRECIATION ---------- --------- --------------- ------------- (In %) (In MWh) (In thousands) Highgate . . . . . . . . 33.8 67.6 $ 10,299 $ 3,849 McNeil . . . . . . . . . 11.0 5.9 8,801 4,192 Stony Brook (No. 1). . . 8.8 31 10,331 7,194 Wyman (No. 4). . . . . . 1.1 6.8 1,980 1,129 Metallic Neutral Return. 59.4 - $ 1,563 $ 556
Metallic Neutral Return is a neutral conductor for NEPOOL/Hydro-Quebec Interconnection THE COMPANY'S SHARE OF EXPENSES FOR THESE FACILITIES IS REFLECTED IN THE CONSOLIDATED STATEMENTS OF INCOME. EACH PARTICIPANT IN THESE FACILITIES MUST PROVIDE ITS OWN FINANCING. 5. RATE MATTERS. 1997 RETAIL RATE CASE. ON MARCH 2, 1998, THE VPSB RELEASED ITS ORDER DATED FEBRUARY 27, 1998 IN THE THEN PENDING 1997 RETAIL RATE CASE. THE VPSB AUTHORIZED AN INCREASE IN THE COMPANY'S RATES BY 3.61 PERCENT, WHICH PROVIDED INCREASED ANNUAL REVENUES OF $5.6 MILLION. THE DIFFERENCE BETWEEN THE $22 MILLION WE ASKED FOR AND THE $5.6 MILLION THE VPSB AUTHORIZED WAS DUE TO THE FOLLOWING: * DISALLOWANCE OF A PORTION OF THE COST OF POWER ASSOCIATED WITH THE HYDRO-QUEBEC CONTRACT DISCUSSED BELOW; * THE VPSB'S MODIFICATION OF OUR CALCULATION OF RATE BASE; * THE EXCLUSION OF FUTURE CAPITAL PROJECTS FROM RATE BASE; * SUSPENSION OF RECOVERY OF PINE STREET BARGE CANAL SITE EXPENDITURES; * VARIOUS COST OF SERVICE REDUCTIONS IN PAYROLL AND OPERATIONS AND MAINTENANCE; AND * A REDUCTION IN OUR REQUESTED ALLOWED RETURN ON EQUITY FROM 13 PERCENT TO 11.25 PERCENT. THE VPSB ORDER DENIED US THE RIGHT TO CHARGE CUSTOMERS $5.48 MILLION OF THE ANNUAL COSTS FOR POWER PURCHASED UNDER OUR CONTRACT WITH HYDRO-QUEBEC. THE VPSB DENIED RECOVERY OF THESE COSTS FOR THE FOLLOWING REASONS: * THE VPSB CLAIMED THAT WE HAD ACTED IMPRUDENTLY BY COMMITTING TO THE POWER CONTRACT WITH HYDRO-QUEBEC IN AUGUST 1991 (THE IMPRUDENCE DISALLOWANCE); AND * TO THE EXTENT THAT THE COSTS OF POWER TO BE PURCHASED FROM HYDRO-QUEBEC ARE NOW HIGHER THAN CURRENT ESTIMATES OF MARKET PRICES FOR POWER DURING THE CONTRACT TERM, AFTER ACCOUNTING FOR THE IMPRUDENCE DISALLOWANCE, THE CONTRACT POWER IS NOT "USED AND USEFUL". GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP) REQUIRED THAT WE RECORD IN THE FIRST QUARTER OF 1998 THE LOSSES RESULTING FROM THE DISALLOWED RECOVERY OF A PORTION OF THE 1998 HYDRO-QUEBEC POWER CONTRACT COSTS. THE AMOUNT CHARGED TO FIRST QUARTER INCOME OF $4.6 MILLION (PRE TAX) WAS LESS THAN THE FULL DISALLOWANCE BECAUSE WE EXPECTED THAT NEW RATES WOULD BECOME EFFECTIVE IN JANUARY 1999 AS THE RESULT OF OUR MAY 8, 1998 RETAIL RATE CASE. IN ITS FEBRUARY 27, 1998 ORDER, THE VPSB TALKED ABOUT ITS POLICIES THAT DO NOT ALLOW A UTILITY TO RECOVER IMPRUDENT EXPENDITURES AND THE COSTS OF POWER SUPPLY CONTRACT PURCHASES THAT THE VPSB DECIDES ARE NOT USED AND USEFUL. THE VPSB ALSO STATED IN ITS ORDER THAT THE METHODS AND MEASURES USED IN THIS RATE CASE WERE PROVISIONAL AND APPLIED TO THIS RATE CASE ONLY. IF THE VPSB WERE TO APPLY THE SAME, OR SIMILAR, METHODS AND MEASURES THAT THEY USED IN THE 1997 RATE CASE 56 ORDER TO FUTURE POWER CONTRACT COSTS IN OUR 1998 RETAIL RATE CASE, WE WOULD LIKELY BE REQUIRED TO RECOGNIZE A CHARGE TO INCOME OF APPROXIMATELY $154 MILLION BEFORE INCOME TAXES. THE $154 MILLION ESTIMATE REPRESENTS PRIMARILY THE 20 PERCENT DISALLOWANCE FOR HYDRO-QUEBEC POWER COSTS THAT THE VPSB CONSIDERED IMPRUDENT IN ITS ORDER. AT THIS TIME WE ARE UNABLE TO ESTIMATE THE LOSSES TO BE RECORDED FOR POWER PURCHASED BEYOND THE TEMPORARY SETTLEMENT PERIOD IN OUR 1998 RETAIL RATE CASE. IF THE VPSB DOES NOT MODIFY ITS RULING THAT THE COSTS OF POWER PURCHASED FROM HYDRO-QUEBEC ARE ABOVE ESTIMATED MARKET RATES AND ARE NOT USED AND USEFUL AND, THEREFORE, A PORTION OF SUCH COSTS IS NOT RECOVERABLE, WE WOULD LIKELY CONCLUDE THAT THE VPSB HAS CHANGED ITS APPROACH TO SETTING RATES FROM COST-BASED RATE MAKING TO ANOTHER FORM OF REGULATION. WE WOULD THEN BE REQUIRED TO DISCONTINUE APPLICATION OF SFAS 71, AND ELIMINATE ALL REGULATORY ASSETS AND LIABILITIES THAT AROSE FROM PRIOR ACTIONS OF THE VPSB. THE WRITE-OFF OF THESE REGULATORY ASSETS AND LIABILITIES, NET OF ANY TAX EFFECTS, WOULD BE CHARGED TO INCOME AS AN EXTRAORDINARY ITEM FOR THE FINANCIAL REPORTING PERIOD IN WHICH THE DISCONTINUATION OF SFAS 71 OCCURS. UNDER SFAS 71 WE ARE REQUIRED TO DEFER CERTAIN COSTS THAT WOULD TYPICALLY BE EXPENSED UNDER GAAP. THESE COSTS ARE REFERRED TO AS DEFERRED CHARGES OR REGULATORY ASSETS. OUR ABILITY TO DEFER A COST IS SUBJECT TO OUR ABILITY TO PROVIDE EVIDENCE THAT THE SPECIFIC COSTS DEFERRED ARE PROBABLE OF FUTURE RATE RECOVERY. BASED ON THE DECEMBER 31, 1999 BALANCE SHEET, IF WE WERE REQUIRED TO DISCONTINUE THE APPLICATION OF SFAS 71, WE WOULD BE REQUIRED TO RECORD AN AFTER-TAX CHARGE TO EARNINGS OF APPROXIMATELY $27.0 MILLION ATTRIBUTABLE TO NET REGULATORY ASSETS. WE FILED WITH THE VPSB A MOTION FOR RECONSIDERATION OF AND TO ALTER OR AMEND THE VPSB'S ORDER RELEASED ON MARCH 2, 1998. ON JUNE 8, 1998 THE VPSB ISSUED AN ORDER ON OUR MOTION FOR RECONSIDERATION WHICH MAINLY REAFFIRMED ITS EARLIER ORDER. WE THEN APPEALED THE VPSB'S FEBRUARY 27, 1998 ORDER AND THE JUNE 8, 1998 RECONSIDERATION ORDER TO THE VERMONT SUPREME COURT. ORAL ARGUMENT BEFORE THE SUPREME COURT WAS HELD ON MARCH 16, 1999. WE BELIEVE THAT THE DECISIONS IN THE VPSB'S FEBRUARY 27, 1998 ORDER AND JUNE 8, 1998 RECONSIDERATION ORDER ARE FACTUALLY INACCURATE AND LEGALLY INCORRECT. SPECIFICALLY, WE ARE APPEALING THE VPSB'S DETERMINATION THAT WE WERE IMPRUDENT IN COMMITTING TO THE HYDRO-QUEBEC CONTRACT IN AUGUST, 1991, AND ITS RULING THAT BECAUSE THE CONTRACT POWER IS PRICED OVER-MARKET UNDER CURRENT FORECASTS OF MARKET PRICES, IT IS THEREFORE CONSIDERED "NOT USED AND USEFUL". THE COMPANY ASSERTS, AMONG OTHER ARGUMENTS, THAT THE VPSB'S ORDER DEPRIVES THE COMPANY'S SHAREHOLDERS OF THEIR PROPERTY IN AN UNCONSTITUTIONAL MANNER. THE VPSB'S DECISION, IF NOT CHANGED, COULD HAVE A SIGNIFICANT NEGATIVE IMPACT ON OUR REPORTED FINANCIAL CONDITION, AND COULD IMPACT OUR CREDIT RATINGS, DIVIDEND POLICY AND FINANCIAL VIABILITY. 1998 RETAIL RATE CASE. ON MAY 8, 1998, WE FILED A REQUEST WITH THE VPSB TO INCREASE OUR RETAIL RATES BY 12.93 PERCENT DUE TO HIGHER POWER COSTS, THE COST OF THE JANUARY 1998 ICE STORM, AND INVESTMENTS IN NEW PLANT AND EQUIPMENT. THE VPSB SUSPENDED THE TARIFF FILINGS ON JUNE 15, 1998. WE SUBMITTED TESTIMONY IN THE CASE THAT INCLUDED ANALYSIS OF VIABLE ALTERNATIVES TO THE HYDRO-QUEBEC CONTRACT AT VARIOUS TIMES IN 1991 AND 1992. THE VPSB HAD TAKEN THE VIEWPOINT IN OUR 1997 RATE CASE THAT WE WOULD HAVE BEEN ABLE TO TERMINATE THE HYDRO-QUEBEC CONTRACT WITHOUT PENALTY DURING THAT TIME PERIOD, AND WOULD HAVE BEEN ABLE TO ACCESS THE MARKET FOR POWER AT THAT TIME. OUR ANALYSIS SHOWED THAT, BASED ON PRICE ONLY, THE HYDRO-QUEBEC CONTRACT WAS LESS EXPENSIVE THAN VIRTUALLY ALL OTHER LONG TERM POWER RESOURCES AVAILABLE AT THAT TIME. THE ANALYSIS ALSO SHOWED THAT WHEN OTHER NON-PRICE BENEFITS, LIKE ENVIRONMENTAL BENEFITS AND THE RELIABILITY OF A SYSTEM POWER RESOURCE, ARE TAKEN INTO ACCOUNT, THE HYDRO-QUEBEC CONTRACT WAS STILL LESS COSTLY THAN ALTERNATIVES. WE HAVE TESTIFIED THAT EVEN TODAY, WHEN COSTS AND BENEFITS FOR SOCIETY ARE ACCOUNTED FOR, AS VERMONT REGULATORS AND STATUTES REQUIRE, THE HYDRO-QUEBEC POWER IS NOT MORE COSTLY THAN MARKET POWER. IN TESTIMONY SUBMITTED ON SEPTEMBER 21, 1998, THE VERMONT DEPARTMENT OF PUBLIC SERVICE, (THE DEPARTMENT), ARGUED FOR A $22 MILLION DISALLOWANCE OF HYDRO-QUEBEC CONTRACT COSTS, A RATE DECREASE OF 3.6 PERCENT, THE ELIMINATION OF OUR COMMON STOCK DIVIDEND, AND VARIOUS OTHER RESTRICTIONS. ADDITIONALLY, THE DEPARTMENT'S RECOMMENDATION WAS THAT APPROXIMATELY $12.5 MILLION OF THE DISALLOWANCE OF HYDRO-QUEBEC CONTRACT COSTS BE SUSPENDED FOR ONE YEAR, WHICH WOULD PROVIDE US WITH A 4.5 PERCENT RATE INCREASE ONLY FOR THAT YEAR, FOLLOWED BY AUTOMATIC REINSTATEMENT OF THE LARGER POWER COST DISALLOWANCE WITH A RESULTING DECREASE (IN 2000) FROM OUR RATE LEVELS TODAY, ABSENT FURTHER VPSB ORDER. THE DEPARTMENT RECOMMENDED THIS ONE YEAR DELAY IN THE HYDRO-QUEBEC CONTRACT COST DISALLOWANCE IN ORDER TO ALLOW US TIME TO NEGOTIATE LOWER COSTS OF POWER UNDER THE HYDRO-QUEBEC CONTRACT. IBM, OUR LARGEST CUSTOMER, ARGUED FOR A RATE DECREASE OF 0.2 PERCENT, A DISALLOWANCE OF 57 HYDRO-QUEBEC POWER COSTS IN THE AMOUNT OF $13 MILLION, AND THE ELIMINATION OF THE COMMON STOCK DIVIDEND. ON NOVEMBER 18, 1998, BY MEMORANDUM OF UNDERSTANDING (MOU), THE COMPANY, THE DEPARTMENT AND IBM AGREED TO STAY, EFFECTIVE NOVEMBER 16, 1998, RATE PROCEEDINGS IN THE 1998 RATE CASE UNTIL OR AFTER SEPTEMBER 1, 1999, OR SUCH EARLIER DATE AS THE PARTIES MAY LATER AGREE TO OR THE VPSB MAY ORDER. THE AGREEMENT TO SUSPEND OUR 1998 RATE CASE, DELAYED THE DATE OF A FINAL DECISION ON THE 1998 RATE CASE TO DECEMBER 15, 1999, AND WE RECOGNIZED AN ADDITIONAL LOSS OF $5.25 MILLION IN THE LAST QUARTER OF 1998 REPRESENTING THE EFFECT OF THE CONTINUED DISALLOWANCE OF HYDRO-QUEBEC POWER COSTS THROUGH DECEMBER 15, 1999. THE MOU PROVIDED A 5.5% TEMPORARY RETAIL RATE INCREASE, TO PRODUCE $8.9 MILLION IN ANNUALIZED ADDITIONAL REVENUE, EFFECTIVE WITH SERVICE RENDERED DECEMBER 15, 1998. IN THE EVENT THAT THE VPSB ISSUES A FINAL ORDER THAT ALLOWS A RETAIL RATE INCREASE THAT IS LESS THAN THE TEMPORARY RATES, ALL SUMS COLLECTED IN EXCESS OF SUCH FINAL RATES WOULD BE REFUNDED BY ADJUSTING RATES ON A PROSPECTIVE BASIS, BY CUSTOMER CLASS, TO REFLECT THE APPROPRIATE REFUND AMOUNTS. AT DECEMBER 31, 1999, TOTAL REVENUES SUBJECT TO REFUND ARE APPROXIMATELY $9.2 MILLION. AN ADDITIONAL SURCHARGE WAS PERMITTED, WITHOUT FURTHER VPSB ORDER, IN ORDER TO PRODUCE ADDITIONAL REVENUES NECESSARY TO PROVIDE THE COMPANY WITH THE CAPACITY TO FINANCE 1999 PINE STREET BARGE CANAL SITE EXPENDITURES. THE MOU WAS APPROVED BY THE VPSB ON DECEMBER 11, 1998. THE MOU DID NOT PROVIDE FOR ANY SPECIFIC DISALLOWANCE OF POWER COSTS UNDER OUR PURCHASE POWER CONTRACT WITH HYDRO-QUEBEC. ISSUES RESPECTING RECOVERY OF SUCH POWER COSTS WERE PRESERVED FOR FUTURE PROCEEDINGS. THE TEMPORARY RATES INCLUDED $1.0 MILLION THAT IS TO BE USED FOR ENHANCED RIGHT OF WAY MAINTENANCE AND POLE TESTING AND TREATMENT. THE STAY AND SUSPENSION OF THIS PENDING RATE CASE AND THE TEMPORARY RATE LEVELS AGREED TO IN THE MOU WERE DESIGNED TO ALLOW US TO CONTINUE TO PROVIDE ADEQUATE AND EFFICIENT SERVICE TO OUR CUSTOMERS WHILE WE SEEK MITIGATION OF POWER SUPPLY COSTS. THE MOU ALSO PROVIDES FOR AMORTIZATION OF REGULATORY ASSET ACCOUNT BALANCES OF $5.1 MILLION, WHICH ARE SUBJECT TO RECOVERY IN THIS DOCKET OVER SEVEN YEARS, BEGINNING JANUARY 1999. THESE BALANCES REFLECT ONLY THE AMOUNT FILED IN THE MAY 1998 RATE CASE, AND ARE RELATED TO REGULATORY COMMISSION EXPENSE, TREE TRIMMING, STORM DAMAGE AND THE COSTS ASSOCIATED WITH THE ICE STORM OF 1998. THIS AMORTIZATION PERIOD WILL BE SUBJECT TO REVIEW BY THE VPSB AFTER THE EXPIRATION OF THE STAY. IN THE EVENT THAT THE VERMONT SUPREME COURT ISSUES AN ORDER REVERSING THE VPSB'S ORDERS IN OUR 1997 RATE CASE PRIOR TO ISSUANCE OF A FINAL ORDER IN THE 1998 RATE CASE, ANY RESULTING ADJUSTMENTS IN RATES WILL NOT BECOME EFFECTIVE UNTIL THE VPSB ISSUES A FINAL ORDER IN THE 1998 RATE CASE. THE MOU PROVIDES THAT NOTHING IN IT WILL REDUCE OR LIMIT OUR ENTITLEMENT TO FULL RECOVERY OF ANY AMOUNTS DUE US IF WE SHOULD PREVAIL ON THE APPEAL. ON SEPTEMBER 7 AND DECEMBER 17, 1999, THE VPSB ISSUED ORDERS APPROVING TWO AMENDMENTS TO THE MOU THAT THE COMPANY HAD ENTERED INTO WITH THE DEPARTMENT AND IBM. THE TWO AMENDMENTS CONTINUED THE STAY OF PROCEEDINGS UNTIL SEPTEMBER 1, 2000, WITH A FINAL DECISION EXPECTED BY DECEMBER 31, 2000. THE AMENDMENTS MAINTAINED THE OTHER FEATURES OF THE ORIGINAL MOU, AND THE SECOND AMENDMENT PROVIDES FOR A TEMPORARY RATE INCREASE OF 3 PERCENT, IN ADDITION TO THE CURRENT TEMPORARY RATE LEVEL, TO BECOME EFFECTIVE AS OF JANUARY 1, 2000. THE TEMPORARY RATES ARE STILL SUBJECT TO REFUND IN THE FINAL RATE CASE DECISION, IF THE FINAL RATES SET ARE LOWER THAN THE TEMPORARY RATES. ONE PARTY TO THE RATE CASE, THE AMERICAN ASSOCIATION OF RETIRED PERSONS, (AARP), HAS FILED AN APPEAL TO THE VERMONT SUPREME COURT OF THE VPSB'S ORDER OF DECEMBER 17, 1999, ARGUING THAT THE VPSB SHOULD HAVE ORDERED THE COMPANY TO POST A BOND OR ESCROW FOR THE TEMPORARY RATE INCREASE. THE COMPANY HAS MOVED TO DISMISS THE APPEAL. AS A RESULT OF THE ORDERS, WE RECORDED AN ADDITIONAL LOSS OF $7.5 MILLION IN 1999, REPRESENTING THE EFFECT OF THE CONTINUED DISALLOWANCE OF HYDRO-QUEBEC POWER COSTS THROUGH DECEMBER 31, 2000. NOTWITHSTANDING THE INTERIM RATE SETTLEMENT, WE ARE UNABLE TO PREDICT WHETHER THE MOU OR OTHER FUTURE EVENTS, SINGULARLY OR IN COMBINATION, COULD CAUSE OUR LENDING BANKS TO REFUSE TO ALLOW FURTHER BORROWINGS UNDER OUR REVOLVING LOAN AGREEMENT, TO SEEK TO ENTER INTO A NEW CREDIT AGREEMENT WITH US AND/OR TO IMMEDIATELY CALL IN ALL OUTSTANDING LOANS. IF WE ARE UNABLE TO BORROW ON A SHORT-TERM BASIS, WE WILL EVALUATE ALL POTENTIAL ALTERNATIVES AVAILABLE AT THE TIME, INCLUDING, BUT NOT LIMITED TO, ELIMINATING COMMON STOCK DIVIDENDS AND THE FILING OF A PETITION FOR REORGANIZATION UNDER THE UNITED STATES BANKRUPTCY CODE. 6. DEFERRED CHARGES NOT INCLUDED IN RATE BASE. THE COMPANY HAS INCURRED AND DEFERRED APPROXIMATELY $6.8 MILLION IN COSTS FOR TREE TRIMMING, STORM DAMAGE AND REGULATORY COMMISSION WORK OF WHICH $4.5 MILLION WILL BE AMORTIZED OVER SIX YEARS ENDING IN DECEMBER 2005. CURRENTLY, THE COMPANY AMORTIZES SUCH COSTS BASED ON HISTORICAL AVERAGES AND DOES NOT RECEIVE A RETURN ON AMOUNTS DEFERRED. MANAGEMENT EXPECTS TO SEEK AND RECEIVE RATEMAKING TREATMENT FOR THESE COSTS IN FUTURE FILINGS. 58 7. OTHER LEGAL MATTERS. THE COMPANY IS INVOLVED IN LEGAL AND ADMINISTRATIVE PROCEEDINGS IN THE NORMAL COURSE OF BUSINESS AND DOES NOT BELIEVE THAT THE ULTIMATE OUTCOME OF THESE PROCEEDINGS WILL HAVE A MATERIAL EFFECT ON THE FINANCIAL POSITION OR THE RESULTS OF OPERATIONS OF THE COMPANY. J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT AGREEMENTS EXECUTED IN 1985 AMONG THE COMPANY, VELCO AND OTHER NEPOOL MEMBERS AND HYDRO-QUEBEC PROVIDED FOR THE CONSTRUCTION OF THE SECOND PHASE (PHASE II) OF THE INTERCONNECTION BETWEEN THE NEW ENGLAND ELECTRIC SYSTEMS AND THAT OF HYDRO-QUEBEC. PHASE II EXPANDS THE PHASE I FACILITIES FROM 690 MEGAWATTS TO 2,000 MEGAWATTS AND PROVIDES FOR TRANSMISSION OF HYDRO-QUEBEC POWER FROM THE PHASE I TERMINAL IN NORTHERN NEW HAMPSHIRE TO SANDY POND, MASSACHUSETTS. CONSTRUCTION OF PHASE II COMMENCED IN 1988 AND WAS COMPLETED IN LATE 1990. THE COMPANY IS ENTITLED TO 3.2 PERCENT OF THE PHASE II POWER-SUPPLY BENEFITS. TOTAL CONSTRUCTION COSTS FOR PHASE II WERE APPROXIMATELY $487 MILLION. THE NEW ENGLAND PARTICIPANTS, INCLUDING THE COMPANY, HAVE CONTRACTED TO PAY MONTHLY THEIR PROPORTIONATE SHARE OF THE TOTAL COST OF CONSTRUCTING, OWNING AND OPERATING THE PHASE II FACILITIES, INCLUDING CAPITAL COSTS. AS A SUPPORTING PARTICIPANT, THE COMPANY MUST MAKE SUPPORT PAYMENTS UNDER THIRTY-YEAR AGREEMENTS. THESE SUPPORT AGREEMENTS MEET THE CAPITAL LEASE ACCOUNTING REQUIREMENTS UNDER SFAS 13. AT DECEMBER 31, 1999, THE PRESENT VALUE OF THE COMPANY'S OBLIGATION IS APPROXIMATELY $7.0 MILLION. PROJECTED FUTURE MINIMUM PAYMENTS UNDER THE PHASE II SUPPORT AGREEMENTS ARE AS FOLLOWS
Year ending December 31, ------------------------- 2000. . . . . . . . $ 440 2001. . . . . . . . 440 2002. . . . . . . . 440 2003. . . . . . . . 440 2004. . . . . . . . 440 Total for 2005-2020 4,838 ------------------------- Total . . . . . $ 7,038 =========================
THE PHASE II PORTION OF THE PROJECT IS OWNED BY NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY AND NEW ENGLAND HYDRO-TRANSMISSION CORPORATION, SUBSIDIARIES OF NEW ENGLAND ELECTRIC SYSTEM, IN WHICH CERTAIN OF THE PHASE II PARTICIPATING UTILITIES, INCLUDING THE COMPANY, OWN EQUITY INTERESTS. THE COMPANY HOLDS APPROXIMATELY 3.2 PERCENT OF THE EQUITY OF THE CORPORATIONS OWNING THE PHASE II FACILITIES. K. LONG-TERM POWER PURCHASES 1. UNIT PURCHASES. UNDER LONG-TERM CONTRACTS WITH VARIOUS ELECTRIC UTILITIES IN THE REGION, THE COMPANY IS PURCHASING CERTAIN PERCENTAGES OF THE ELECTRICAL OUTPUT OF PRODUCTION PLANTS CONSTRUCTED AND FINANCED BY THOSE UTILITIES. SUCH CONTRACTS OBLIGATE THE COMPANY TO PAY CERTAIN MINIMUM ANNUAL AMOUNTS REPRESENTING THE COMPANY'S PROPORTIONATE SHARE OF FIXED COSTS, INCLUDING DEBT SERVICE REQUIREMENTS (AMOUNTS NECESSARY TO RETIRE THE PRINCIPAL OF AND TO PAY THE INTEREST ON THE PORTION OF THE RELATED LONG-TERM DEBT ASCRIBED TO THE COMPANY) WHETHER OR NOT THE PRODUCTION PLANTS ARE OPERATING. THE COST OF POWER OBTAINED UNDER SUCH LONG-TERM CONTRACTS, INCLUDING PAYMENTS REQUIRED WHEN A PRODUCTION PLANT IS NOT OPERATING, IS REFLECTED AS "POWER SUPPLY EXPENSES" IN THE ACCOMPANYING CONSOLIDATED STATEMENTS OF INCOME. INFORMATION (INCLUDING ESTIMATES FOR THE COMPANY'S PORTION OF CERTAIN MINIMUM COSTS AND ASCRIBED LONG-TERM DEBT) WITH REGARD TO SIGNIFICANT PURCHASED POWER CONTRACTS OF THIS TYPE IN EFFECT DURING 1999 FOLLOWS: 59
STONY VERMONT BROOK YANKEE ----------------------- ---------- (Dollars in thousands) Plant Capacity 352.0 MW 531.0 MW Company's share of output 4.40% 17.90% Contract period (1) (2) Company's annual share of: Interest $ 192 $ 2,044 Other debt service 347 Other capacity 400 31,511 Total annual capacity $ 939 $ 33,555 ======================= ========== Company's share of long-term debt $ 3,609 $ 17,425
(1) LIFE OF PLANT ESTIMATED TO BE 1981 - 2006. (2) LICENSE FOR PLANT OPERATIONS EXPIRES IN 2012. 2. HYDRO-QUEBEC SYSTEM POWER PURCHASE AND SALE COMMITMENTS. UNDER VARIOUS CONTRACTS, THE DETAILS OF WHICH ARE DESCRIBED IN THE TABLE BELOW, THE COMPANY PURCHASES CAPACITY AND ASSOCIATED ENERGY PRODUCED BY THE HYDRO-QUEBEC SYSTEM. SUCH CONTRACTS OBLIGATE THE COMPANY TO PAY CERTAIN FIXED CAPACITY COSTS WHETHER OR NOT ENERGY PURCHASES ABOVE A MINIMUM LEVEL SET FORTH IN THE CONTRACTS ARE MADE. SUCH MINIMUM ENERGY PURCHASES MUST BE MADE WHETHER OR NOT OTHER, LESS EXPENSIVE ENERGY SOURCES MIGHT BE AVAILABLE. THESE CONTRACTS ARE INTENDED TO COMPLEMENT THE OTHER COMPONENTS IN THE COMPANY'S POWER SUPPLY TO ACHIEVE THE MOST ECONOMIC POWER-SUPPLY MIX REASONABLY AVAILABLE. THE COMPANY'S CURRENT PURCHASES PURSUANT TO THE CONTRACT WITH HYDRO-QUEBEC ENTERED INTO DECEMBER 4, 1987 (THE 1987 CONTRACT) ARE AS FOLLOWS: (1) SCHEDULE B -- 68 MEGAWATTS OF FIRM CAPACITY AND ASSOCIATED ENERGY TO BE DELIVERED AT THE HIGHGATE INTERCONNECTION FOR TWENTY YEARS BEGINNING IN SEPTEMBER 1995; AND (2) SCHEDULE C3 -- 46 MEGAWATTS OF FIRM CAPACITY AND ASSOCIATED ENERGY TO BE DELIVERED AT INTERCONNECTIONS TO BE DETERMINED AT ANY TIME FOR 20 YEARS, WHICH BEGAN IN NOVEMBER 1995. DURING 1994, THE COMPANY NEGOTIATED AN ARRANGEMENT WITH HYDRO-QUEBEC THAT REDUCES THE COST IMPACTS ASSOCIATED WITH THE PURCHASE OF SCHEDULES B AND C3 UNDER THE 1987 CONTRACT, OVER THE NOVEMBER 1995 THROUGH OCTOBER 1999 PERIOD (THE JULY 1994 AGREEMENT). UNDER THE JULY 1994 AGREEMENT, THE COMPANY, IN ESSENCE, WILL TAKE DELIVERY OF THE AMOUNTS OF ENERGY AS SPECIFIED IN THE 1987 CONTRACT, BUT THE ASSOCIATED FIXED COSTS WILL BE SIGNIFICANTLY REDUCED FROM THOSE SPECIFIED IN THE 1987 CONTRACT. AS PART OF THE JULY 1994 AGREEMENT, WE WERE OBLIGATED TO PURCHASE $4.0 MILLION (IN 1994 DOLLARS) WORTH OF RESEARCH AND DEVELOPMENT WORK FROM HYDRO-QUEBEC OVER A PERIOD ENDING OCTOBER 1999, AND MADE AN ADDITIONAL $6.5 MILLION (PLUS ACCRUED INTEREST) PAYMENT TO HYDRO-QUEBEC IN 1995. HYDRO-QUEBEC RETAINS THE RIGHT TO CURTAIL ANNUAL ENERGY DELIVERIES BY 10 PERCENT UP TO FIVE TIMES, OVER THE 2000 TO 2015 PERIOD, IF DOCUMENTED DROUGHT CONDITIONS EXIST IN QUEBEC. THE PERIOD FOR COMPLETING THE RESEARCH AND DEVELOPMENT PURCHASE WAS SUBSEQUENTLY EXTENDED TO MARCH 2001. DURING THE FIRST YEAR OF THE JULY 1994 AGREEMENT (THE PERIOD FROM NOVEMBER 1995 THROUGH OCTOBER 1996), THE AVERAGE COST PER KILOWATT-HOUR OF SCHEDULES B AND C3 COMBINED WAS CUT FROM 6.4 TO 4.2 CENTS PER KILOWATT-HOUR, A 34 PERCENT (OR $16 MILLION) COST REDUCTION. OVER THE PERIOD FROM NOVEMBER 1996 THROUGH DECEMBER 2000 AND ACCOUNTING FOR THE PAYMENTS TO HYDRO-QUEBEC, THE COMBINED UNIT COSTS WILL BE LOWERED FROM 6.5 TO 5.9 CENTS PER KILOWATT-HOUR, REDUCING UNIT COSTS BY 10 PERCENT AND SAVING $20.7 MILLION IN NOMINAL TERMS. ALL OF THE COMPANY'S CONTRACTS WITH HYDRO-QUEBEC CALL FOR THE DELIVERY OF SYSTEM POWER AND ARE NOT RELATED TO ANY PARTICULAR FACILITIES IN THE HYDRO-QUEBEC SYSTEM. CONSEQUENTLY, THERE ARE NO IDENTIFIABLE DEBT-SERVICE CHARGES ASSOCIATED WITH ANY PARTICULAR HYDRO-QUEBEC FACILITY THAT CAN BE DISTINGUISHED FROM THE OVERALL CHARGES PAID UNDER THE CONTRACTS. A SUMMARY OF THE HYDRO-QUEBEC CONTRACTS, INCLUDING THE JULY 1994 AGREEMENT, BUT EXCLUDING THE JANUARY AND NOVEMBER 1996 ARRANGEMENTS (DESCRIBED BELOW) INCLUDING HISTORIC AND PROJECTED CHARGES FOR THE YEARS INDICATED, FOLLOWS: 60
THE 1987 CONTRACT SCHEDULE B SCHEDULE C3 -------------------------------------- ------------- (Dollars in thousands except per KWh) Capacity acquired 68 MW 47 MW Contract period 1995-2015 1995-2015 Minimum energy purchase 75% 75% (annual load factor) Annual energy charge 1999 $ 11,373 $ 7,949 estimated 2000-2015 13,506 * 9,320* Annual capacity charge 1999 17,027 7,952 2000-2015 16,686 * 11,523* Average cost per KWh 1999 $ 0.064 $ 0.052 2000-2015 $ 0.070** $ 0.070**
*ESTIMATED AVERAGE **ESTIMATED AVERAGE IN NOMINAL DOLLARS LEVELIZED OVER THE PERIOD INDICATED INCLUDES AMORTIZATION OF PAYMENTS TO HYDRO-QUEBEC FOR THE JULY 1994 AGREEMENT UNDER A 1996 ARRANGEMENT, THE COMPANY IS REQUIRED TO SHIFT UP TO 40 MEGAWATTS OF ITS SCHEDULE C3 TO AN ALTERNATE TRANSMISSION PATH AND USE THE ASSOCIATED PORTION OF THE NEPOOL/HYDRO-QUEBEC INTERCONNECTION FACILITIES TO PURCHASE POWER FOR THE PERIOD FROM SEPTEMBER 1996 THROUGH JUNE 2001 AT PRICES THAT VARY BASED UPON CONDITIONS IN EFFECT WHEN THE PURCHASES WERE MADE. THE 1996 ARRANGEMENT ALSO PROVIDES FOR MINIMUM PAYMENTS BY THE COMPANY TO HYDRO-QUEBEC FOR THE PERIODS IN WHICH POWER IS NOT PURCHASED UNDER THE ARRANGEMENT. ALTHOUGH THE LEVEL OF BENEFITS TO THE COMPANY WILL DEPEND ON VARIOUS FACTORS, THE COMPANY ESTIMATES THAT THE 1996 ARRANGEMENT WILL PROVIDE A BENEFIT OF APPROXIMATELY $3.0 MILLION ON A NET PRESENT VALUE BASIS. UNDER A SEPARATE AGREEMENT EXECUTED ON DECEMBER 5, 1997, HYDRO-QUEBEC PROVIDED A PAYMENT OF $8.0 MILLION TO THE COMPANY IN 1997. IN RETURN FOR THIS PAYMENT, THE COMPANY IS PROVIDING HYDRO-QUEBEC AN OPTION FOR THE PURCHASE OF POWER. COMMENCING APRIL 1, 1998, AND EFFECTIVE THROUGH OCTOBER 2015, HYDRO-QUEBEC CAN EXERCISE AN OPTION TO PURCHASE UP TO 52,500 MWH ON AN ANNUAL BASIS, AT ENERGY PRICES ESTABLISHED IN ACCORDANCE WITH THE 1987 CONTRACT, FOR AN AMOUNT OF ENERGY EQUIVALENT TO THE COMPANY'S FIRM CAPACITY ENTITLEMENTS IN THE 1987 CONTRACT. THE CUMULATIVE AMOUNT OF ENERGY PURCHASED OVER THE REMAINING TERM OF THE 1987 CONTRACT SHALL NOT EXCEED 950,000 MWH. HYDRO-QUEBEC'S OPTION TO CURTAIL ENERGY DELIVERIES PURSUANT TO THE JULY 1994 AGREEMENT CAN BE EXERCISED IN ADDITION TO THIS PURCHASE OPTION. OVER THE SAME PERIOD, HYDRO-QUEBEC CAN EXERCISE AN OPTION ON AN ANNUAL BASIS TO PURCHASE A TOTAL OF 600,000 MWH AT THE 1987 CONTRACT ENERGY PRICE. HYDRO-QUEBEC CAN PURCHASE NO MORE THAN 200,000 MWH IN ANY GIVEN YEAR. IN 1999, HYDRO-QUEBEC CALLED ON THE COMPANY TO DELIVER 158,256 MWH TO A THIRD PARTY AT AN APPROXIMATE NET COST OF $5.4 MILLION, WHICH WAS DUE TO HIGHER ENERGY REPLACEMENT COSTS. THE COMPANY IS UNABLE TO ESTIMATE FUTURE COSTS FOR THIS AGREEMENT, WHICH ARE DEPENDENT UPON THE TIMING OF ANY EXERCISE OF OPTIONS, AND THE MARKET PRICE FOR REPLACEMENT POWER. HOWEVER, THESE COSTS COULD HAVE A MATERIAL ADVERSE EFFECT ON THE COMPANY'S EARNINGS AND CASH FLOWS. 3. MORGAN STANLEY AGREEMENT - ON FEBRUARY 11, 1999, WE ENTERED INTO A CONTRACT WITH MORGAN STANLEY CAPITAL GROUP, INC. (MS) AS A RESULT OF OUR POWER REQUIREMENTS SOLICITATION IN 1998. A MASTER POWER PURCHASE AND SALES AGREEMENT (PPSA) DATED FEBRUARY 11, 1999 DEFINES THE GENERAL CONTRACT TERMS UNDER WHICH THE PARTIES MAY TRANSACT. THE SALES UNDER THE PPSA COMMENCED ON FEBRUARY 12, 1999 AND WILL TERMINATE AFTER ALL OBLIGATIONS UNDER EACH TRANSACTION ENTERED INTO BY MS AND THE COMPANY HAS BEEN FULFILLED, CURRENTLY ANTICIPATED TO BE JANUARY 31, 2002. THE PPSA HAS BEEN NOTICED TO THE VPSB AND FILED WITH THE FERC. THE PARTIES HAVE ALSO AGREED TO ENTER INTO TWO TRANSACTIONS SUBJECT TO THE PPSA, WHICH PROVIDES UA A MEANS OF MANAGING PRICE RISKS ASSOCIATED WITH CHANGING FOSSIL FUEL PRICES. SALE BY THE COMPANY TO MS.-ON A DAILY BASIS, AND AT MS'S DISCRETION, WE WILL SELL POWER TO MS FROM EITHER (I) ALL OR PART OF OUR PORTFOLIO OF POWER RESOURCES AT PREDEFINED OPERATING AND PRICING PARAMETERS OR (II) ANY POWER RESOURCES AVAILABLE TO US, PROVIDED THAT SALES OF POWER FROM SOURCES OTHER THAN COMPANY-OWNED GENERATION COMPLY WITH THE PREDEFINED OPERATING AND PRICING PARAMETERS. 61 SALE BY MS TO THE COMPANY.- MS THEN SELLS TO US, AT A PREDEFINED PRICE, POWER SUFFICIENT TO SERVE PRE-ESTABLISHED LOAD REQUIREMENTS. MS IS ALSO RESPONSIBLE FOR BALANCING SUPPLY RESOURCES WHEN ACTUAL LOADS VARY FROM THE PRE-ESTABLISHED LOAD REQUIREMENTS. WE REMAIN RESPONSIBLE FOR RESOURCE PERFORMANCE AND AVAILABILITY, HOWEVER MS PROVIDES COVERAGE AGAINST MAJOR UNSCHEDULED OUTAGES, CONTINGENT UPON BOTH PRICE AND AVAILABILITY OF POWER RESOURCES. L. DISCONTINUED OPERATIONS. THE COMPANY HAS DECIDED TO SELL OR OTHERWISE DISPOSE OF THE OPERATIONS AND ASSETS OF MEI, WHICH OWNS AND INVESTS IN ENERGY GENERATION, ENERGY EFFICIENCY, AND WASTEWATER TREATMENT PROJECTS. MEI HAS BEEN REPORTED AS A SEPARATE SEGMENT IN PRIOR YEARS, AND APPEARS AS A SEPARATE "EQUITY INVESTMENT IN ENERGY RELATED BUSINESS" CAPTION IN THE NONUTILITY SECTION OF THE CONSOLIDATED BALANCE SHEET. RESULTS OF OPERATIONS WERE PREVIOUSLY INCLUDED IN THE SECTION OTHER INCOME IN THE CONSOLIDATING STATEMENTS OF INCOME. IN 1999, ASSETS AND LIABILITIES ARE PRESENTED NET IN THE NONUTILITY SECTION AS "BUSINESS SEGMENT HELD FOR DISPOSAL". THE PROVISIONS FOR LOSS FROM DISCONTINUED OPERATIONS REFLECT MANAGEMENT'S CURRENT ESTIMATE. THE ULTIMATE LOSS REMAINS SUBJECT TO THE CONSUMMATION OF A SALE OR OTHER DISPOSITION, AND COULD EXCEED THE AMOUNTS RECORDED. THE FOLLOWING ILLUSTRATES THE RESULTS AND FINANCIAL STATEMENT IMPACT OF MEI DURING AND AT THE PERIODS SHOWN:
1999 1998 1997 -------------------------------- -------- ------- (In thousands except per share) Revenues $ 2,296 $ 2,092 $ 4,500 Net income (loss) operations (603) (2,086) 142 Provisions for loss on disposal and future operating losses (6,676) - - Net income (loss) (7,279) (2,086) 142 Net income (loss) per share (1.36) (0.40) 0.03 Assets $ 19,395 $26,810 $25,046
AT DECEMBER 31, 1999, MEI HAD UNSECURED LONG-TERM DEBT OF $1.2 MILLION, ALL BECOMING DUE IN THE YEAR 2000. INCOME TAXES FOR MEI FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 ARE SUMMARIZED AS:
YEARS ENDED DECEMBER 31, 1999 1998 1997 -------------------------- -------- ------ (In thousands) State income taxes . . . . . $ (281) $ (222) $ 98 Federal income taxes . . . . (1,371) (1,130) 51 Investment tax credits . . . - (111) (45) -------------------------- -------- ------ Income tax expense (benefit) $ (1,652) $(1,463) $ 104 ========================== ======== ======
M. SUBSEQUENT EVENTS. ON JANUARY 31, 2000, THE COMPANY AMENDED ITS CONTRACT WITH MS. SALES UNDER THE AMENDED AGREEMENT BEGIN FEBRUARY 15, 2000, AND WILL TERMINATE ON JANUARY 31, 2002. THE AMENDED AGREEMENT CONTAINS THE FEATURES, AS DISCUSSED IN NOTE K, OF THE ORIGINAL AGREEMENT AND ADDS SEVERAL SERVICES. THE AMENDMENT ASSIGNS MS THE RESPONSIBILITIES OF SCHEDULING THE COMPANY'S RESOURCES AND SEEKING ECONOMICAL ENERGY TO MEET LOADS NOT COVERED BY THE BASE CONTRACT. IT ALSO ADDS A PROVISION THAT GUARANTEES A PAYMENT TO THE COMPANY IN CASE OF UNSCHEDULED UNIT OUTAGES UP TO 114 MW DURING PERIODS OF HIGH REPLACEMENT COST ENERGY. THE AMENDMENT ALSO REMOVES ENERGY FROM THE COMPANY'S INTERNAL COMBUSTION UNITS FROM THE CONTROL OF MS, ALLOWING THE COMPANY TO RESERVE THAT FOR ITS OWN NEEDS. THE COMPANY REMAINS RESPONSIBLE FOR PLANT PERFORMANCE NOT COVERED UNDER THIS PROVISION. 62 N. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) THE FOLLOWING QUARTERLY FINANCIAL INFORMATION, IN THE OPINION OF MANAGEMENT, INCLUDES ALL ADJUSTMENTS NECESSARY TO A FAIR STATEMENT OF RESULTS OF OPERATIONS FOR SUCH PERIODS. VARIATIONS BETWEEN QUARTERS REFLECT THE SEASONAL NATURE OF THE COMPANY'S BUSINESS AND THE TIMING OF RATE CHANGES.
1999 Quarter ended MARCH JUNE SEPTEMBER DECEMBER TOTAL -------------------- -------- ----------- ---------- --------- (Amounts in thousands except per share data) Operating Revenues. . . . . . . . . . . . . . $ 59,018 $59,535 $ 68,478 $ 64,017 $251,048 Operating Income. . . . . . . . . . . . . . . 3,906 977 1,412 1,651 7,946 Net Income (loss) from continuing operations. 3,170 (412) (115) 418 3,061 Net Income (loss) from discontinued operations. . . . . . . . . . . (522) (81) (4,592) (2,084) (7,279) Net Income (loss) applicable to common stock. 2,648 (493) (4,707) (1,666) (4,218) Earnings (loss) per average share from: Continuing operations . . . . . . . . . 0.60 (0.08) (0.02) 0.07 0.57 Discontinued operations . . . . . . . . . . . (0.10) (0.02) (0.85) (0.39) (1.36) Basic and diluted . . . . . . . . . . . . . . $ 0.50 $ (0.10) $ (0.88) $ (0.31) $ (0.79) Weighted average common shares outstanding. . 5,318 5,344 5,374 5,291 5,361
1998 Quarter ended MARCH JUNE SEPTEMBER DECEMBER TOTAL -------------------- -------- ----------- ---------- --------- (Amounts in thousands except per share data) Operating Revenues. . . . . . . . . . . . . . $ 46,932 $43,733 $ 47,984 $ 45,655 $184,304 Operating Income. . . . . . . . . . . . . . . 316 2,811 3,147 (802) 5,472 Net Income (loss) from continuing operations. (2,648) 1,286 1,811 (2,536) (2,087) Net Income (loss) from discontinued operations . . . . . . . . . . . (757) (355) (178) (796) (2,086) Net Income (loss) applicable to common stock. (3,405) 931 1,633 (3,332) (4,173) Earnings (loss) per average share from: Continuing operations . . . . . . . . . (0.51) 0.25 0.34 (0.48) (0.40) Discontinued operations . . . . . . . . . . . (0.15) (0.06) (0.03) (0.16) (0.40) Basic and diluted . . . . . . . . . . . . . . $ (0.66) $ 0.18 $ 0.31 $ (0.63) $ (0.80) Weighted average common shares outstanding. . 5,196 5,222 5,261 5,291 5,243
1997 Quarter ended MARCH JUNE SEPTEMBER DECEMBER TOTAL -------------------- ------- ---------- ---------- -------- (Amounts in thousands except per share data) Operating Revenues. . . . . . . . . . . . . . $ 47,204 $42,682 $ 43,574 $ 45,863 $179,323 Operating Income. . . . . . . . . . . . . . . 4,251 2,991 4,542 3,731 15,515 Net Income (loss) from continuing operations. 3,003 298 2,468 2,094 7,863 Net Income (loss) from discontinued operations . . . . . . . . . . . (62) 558 554 (908) 142 Net Income (loss) applicable to common stock. 2,941 856 3,022 1,186 8,005 Earnings (loss) per average share from: Continuing operations . . . . . . . . . 0.60 0.06 0.48 0.41 1.54 Discontinued operations . . . . . . . . . . . (0.01) 0.11 0.11 (0.18) 0.03 Basic and diluted . . . . . . . . . . . . . . $ 0.58 $ 0.17 $ 0.59 $ 0.23 $ 1.57 Weighted average common shares outstanding. . 5,044 5,096 5,138 5,168 5,112
63 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE BOARD OF DIRECTORS OF GREEN MOUNTAIN POWER CORPORATION: WE HAVE AUDITED THE ACCOMPANYING CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED CAPITALIZATION DATA OF GREEN MOUNTAIN POWER CORPORATION (A VERMONT CORPORATION) AND ITS SUBSIDIARIES AS OF DECEMBER 31, 1999 AND 1998, AND THE RELATED CONSOLIDATED STATEMENTS OF INCOME, RETAINED EARNINGS, AND CASH FLOWS FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 1999. THESE FINANCIAL STATEMENTS ARE THE RESPONSIBILITY OF THE COMPANY'S MANAGEMENT. OUR RESPONSIBILITY IS TO EXPRESS AN OPINION ON THESE FINANCIAL STATEMENTS BASED ON OUR AUDIT. WE CONDUCTED OUR AUDITS IN ACCORDANCE WITH GENERALLY ACCEPTED AUDITING STANDARDS. THOSE STANDARDS REQUIRE THAT WE PLAN AND PERFORM THE AUDIT TO OBTAIN REASONABLE ASSURANCE ABOUT WHETHER THE FINANCIAL STATEMENTS ARE FREE OF MATERIAL MISSTATEMENT. AN AUDIT INCLUDES EXAMINING, ON A TEST BASIS, EVIDENCE SUPPORTING THE AMOUNTS AND DISCLOSURES IN THE FINANCIAL STATEMENTS. AN AUDIT ALSO INCLUDES ASSESSING THE ACCOUNTING PRINCIPLES USED AND SIGNIFICANT ESTIMATES MADE BY MANAGEMENT, AS WELL AS EVALUATING THE OVERALL FINANCIAL STATEMENT PRESENTATION. WE BELIEVE THAT OUR AUDITS PROVIDE A REASONABLE BASIS FOR OUR OPINION. AS DISCUSSED IN NOTE I.5, THE COMPANY APPEALED THE VERMONT PUBLIC SERVICE BOARD'S FEBRUARY 27, 1998 RATE ORDER TO THE VERMONT SUPREME COURT. IN ADDITION, THE COMPANY IS INVOLVED IN A RATE PROCEEDING THAT WAS INITIATED IN 1998 AND IS ANTICIPATED TO REACH FINAL DECISION BY DECEMBER 31, 2000. THE OUTCOME OF THE APPEAL PROCESS AND THE RATE PROCEEDING COULD HAVE A SIGNIFICANT ADVERSE IMPACT ON THE COMPANY'S REPORTED FINANCIAL CONDITION AND 2000 RESULTS OF OPERATIONS AND COULD IMPACT THE COMPANY'S FINANCIAL VIABILITY. IN OUR OPINION, THE CONSOLIDATED FINANCIAL STATEMENTS REFERRED TO ABOVE PRESENT FAIRLY, IN ALL MATERIAL ASPECTS, THE FINANCIAL POSITION OF GREEN MOUNTAIN POWER CORPORATION AND ITS SUBSIDIARIES AS OF DECEMBER 31, 1999 AND 1998, AND THE CONSOLIDATED RESULTS OF ITS OPERATIONS AND CASH FLOWS FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 1999, IN CONFORMITY WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES. /S/ ARTHUR ANDERSEN LLP BOSTON, MASSACHUSETTS FEBRUARY 4, 2000 64
Schedule II GREEN MOUNTAIN POWER CORPORATION VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 1999, 1998 and 1997 Balance at Additions Additions Balance at Beginning of Charged to Charged to End of Period Cost & Expenses Other Accounts Deductions Period ------------- ---------------- ---------------- ----------- ----------- Injuries and Damages (1) 1999 . . . . . . . . . . $ 7,898,785 $ 100,000 $ 3,814,874 $ 1,684,529 $10,129,130 1998 . . . . . . . . . . $ 663,785 $ 2,735,000 $ 5,000,000 $ 500,000 $ 7,898,785 1997 $ 237,892 $ 427,546 ---- $ 1,653 $ 663,785 Bad Debt Reserve 1999 . . . . . . . . . . $ 400,000 $ 261,697 $ 12,762 $ 283,964 $ 390,495 1998(2). . . . . . . . . $ 493,405 $ 393,949 $ 83,299 $ 570,653 $ 400,000 1997(2). . . . . . . . . $ 498,024 $ 637,010 $ 173,899 (3) $ 815,528 $ 493,405
(1) Includes Pine Street Barge Canal reserves (2) Includes non-utility bad debt reserve. (3) Represents collection of accounts previously written off. 65 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE NONE PART III ITEMS 10, 11, 12 & 13 CERTAIN INFORMATION REGARDING EXECUTIVE OFFICERS CALLED FOR BY ITEM 10, "DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT," IS FURNISHED UNDER THE CAPTION, "EXECUTIVE OFFICERS" IN ITEM 1 OF PART I OF THIS REPORT. THE OTHER INFORMATION CALLED FOR BY ITEM 10, AS WELL AS THAT CALLED FOR BY ITEMS 11, 12, AND 13, "EXECUTIVE COMPENSATION," "SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" AND "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS," WILL BE SET FORTH UNDER THE CAPTIONS "ELECTION OF DIRECTORS," BOARD COMPENSATION, OTHER RELATIONSHIP, MEETINGS AND COMMITTEES, "SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE," "EXECUTIVE COMPENSATION," COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION, PERFORMANCE GRAPHS, "PENSION PLAN INFORMATION" AND "SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" IN THE COMPANY'S DEFINITIVE PROXY STATEMENT RELATING TO ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD ON MAY 18, 2000. SUCH INFORMATION IS INCORPORATED HEREIN BY REFERENCE. SUCH PROXY STATEMENT PERTAINS TO THE ELECTION OF DIRECTORS AND OTHER MATTERS. DEFINITIVE PROXY MATERIALS WILL BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO REGULATION 14A IN APRIL 2000. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K ITEM 14(A)1. FINANCIAL STATEMENTS AND SCHEDULES. THE FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES OF THE COMPANY ARE LISTED ON THE INDEX TO FINANCIAL STATEMENTS SET FORTH IN ITEM 8 HEREOF. ITEM 14(B) A REPORT ON FORM 8-K WAS FILED ON DECEMBER 8, 1999 ANNOUNCING AGREEMENT WITH THE VERMONT DEPARTMENT OF PUBLIC SERVICE AND INTERNATIONAL BUSINESS MACHINES ON A TEMPORARY 3 PERCENT RATE INCREASE, SUBJECT TO THE VERMONT PUBLIC SERVICE BOARD APPROVAL. IN ADDITION, IT WAS ANNOUNCED THAT THE COMPANY'S LENDING ARRANGEMENTS, SPECIFICALLY THE TOTAL AMOUNT AVAILABLE OF $15 MILLION, WERE CONTINUED AFTER EXTENSIVE DISCUSSIONS WITH THE BANKS INVOLVED. A REPORT ON FORM 8-K WAS FILED ON DECEMBER 17, 1999 ANNOUNCING THE VERMONT PUBLIC SERVICE BOARD APPROVAL OF A 3 PERCENT TEMPORARY RATE INCREASE, EFFECTIVE FOR SERVICE RENDERED AFTER DECEMBER 31, 1999. 66 EXHIBIT 23-A-1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS AS INDEPENDENT PUBLIC ACCOUNTANTS, WE HEREBY CONSENT TO THE INCORPORATION OF OUR REPORTS DATED FEBRUARY 4, 2000 INCLUDED IN THIS FORM 10-K INTO THE COMPANY'S PREVIOUSLY FILED REGISTRATION STATEMENTS ON FORM S-3, FILE NOS. 33-58411 AND 33-59383, AND INTO THE COMPANY'S PREVIOUSLY FILED REGISTRATION STATEMENTS ON FORM S-8, FILE NOS. 33-58413 AND 33-60511. BOSTON, MASSACHUSETTS MARCH 21, 2000 /S/ ARTHUR ANDERSEN LLP REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS WE HAVE AUDITED, IN ACCORDANCE WITH GENERALLY ACCEPTED AUDITING STANDARDS, THE CONSOLIDATED FINANCIAL STATEMENTS OF GREEN MOUNTAIN POWER CORPORATION INCLUDED IN THIS FORM 10-K AND HAVE ISSUED OUR REPORT THEREON DATED FEBRUARY 4, 2000. OUR AUDIT WAS MADE FOR THE PURPOSE OF FORMING AN OPINION ON THE BASIC FINANCIAL STATEMENTS TAKEN AS A WHOLE. THE SCHEDULE LISTED IN THE ACCOMPANYING INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES IS PRESENTED FOR PURPOSES OF COMPLYING WITH THE SECURITIES AND EXCHANGE COMMISSION'S RULES AND IS NOT PART OF THE BASIC CONSOLIDATED FINANCIAL STATEMENTS. THIS SCHEDULE HAS BEEN SUBJECTED TO THE AUDITING PROCEDURES APPLIED IN THE AUDIT OF THE BASIC CONSOLIDATED 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 CONSOLIDATED FINANCIAL STATEMENTS TAKEN AS A WHOLE. BOSTON, MASSACHUSETTS FEBRUARY 4, 2000 /S/ ARTHUR ANDERSEN LLP 67
Item 14(a)3 and Item 14(c). Exhibits SEC Docket Form incorporated by Exhibit reference or Number Description Exhibit Page filed herewith - ---------- ---------------------------------------------------------- ---------- --------------------- 3-a Restated Articles of Association, as certified . . . . . . 3-a Form 10-K 1993 June 6, 1991. (1-8291) 3-a-1 Amendment to 3-a above, dated as of May 20, 1993.. . . . . 3-a-1 Form 10-K 1993 (1-8291) 3-a-2 Amendment to 3-a above, dated as of October 11, 1996.. . . 3-a-2 Form 10-Q Sept. 1996 (1-8291) 3-b By-laws of the Company, as amended . . . . . . . . . . . . 3-b Form 10-K 1996 February 10, 1997. (1-8291) 4-b-1 Indenture of First Mortgage and Deed of Trust. . . . . . . 4-b 2-27300 dated as of February 1, 1955. 4-b-2 First Supplemental Indenture dated as of . . . . . . . . . 4-b-2 2-75293 April 1, 1961. 4-b-3 Second Supplemental Indenture dated as of. . . . . . . . . 4-b-3 2-75293 January 1, 1966. 4-b-4 Third Supplemental Indenture dated as of . . . . . . . . . 4-b-4 2-75293 July 1, 1968. 4-b-5 Fourth Supplemental Indenture dated as of. . . . . . . . . 4-b-5 2-75293 October 1, 1969. 4-b-6 Fifth Supplemental Indenture dated as of . . . . . . . . . 4-b-6 2-75293 December 1, 1973. 4-b-7 Seventh Supplemental Indenture dated as. . . . . . . . . . 4-a-7 2-99643 August 1, 1976. 4-b-8 Eighth Supplemental Indenture dated as of. . . . . . . . . 4-a-8 2-99643 December 1, 1979. 4-b-9 Ninth Supplemental Indenture dated as of . . . . . . . . . 4-b-9 2-99643 July 15, 1985. 4-b-10 Tenth Supplemental Indenture dated as of . . . . . . . . . 4-b-10 Form 10-K 1989 June 15, 1989. (1-8291) 4-b-11 Eleventh Supplemental Indenture dated as of. . . . . . . . 4-b-11 Form 10-Q September September 1, 1990. 1990 (1-8291) 4-b-12 Twelfth Supplemental Indentrue dated as of . . . . . . . . 4-b-12 Form 10-K 1991 March 1, 1992. (1-8291) 4-b-13 Thirteenth Supplemental Indenture dated as of. . . . . . . 4-b-13 Form 10-K 1991 March 1, 1992. (1-8291) 4-b-14 Fourteenth Supplemental Indenture dated as of. . . . . . . 4-b-14 Form 10-K 1993 November 1, 1993. (1-8291) 4-b-15 Fifteenth Supplemental Indenture dated as of . . . . . . . 4-b-15 Form 10-K 1993 November 1, 1993. (1-8291) 4-b-16 Sixteenth Supplemental Indenture dated as of . . . . . . . 4-b-16 Form 10-K 1995 December 1, 1995. (1-8291) 4-b-17 Revised form of Indenture as filed as an Exhibit . . . . . 4-b-17 Form 10-Q Sept. 1995 to Registration Statement No. 33-59383. (1-8291) 4-b-18 Credit Agreement by and among Green Mountain Power . . . . 4-b-18 Form 10-K 1997 The Bank of Nova Scotia, State Street Bank and (1-8291) Trust Company, Fleet National Bank, and Fleet National Bank, as Agent 4-b-18(a) Amendment to Exhibit 4-b-18. . . . . . . . . . . . . . . . 4-b-18(a) Form 10-Q Sept. 1998 (1-8291) 10-a Form of Insurance Policy issued by Pacific . . . . . . . . 10-a 33-8146 Insurance Company, with respect to indemnification of Directors and Officers. 68 10-b-1 Firm Power Contract dated September 16, 1958,. . . . . . . 13-b 2-27300 between the Company and the State of Vermont and supplements thereto dated September 19, 1958; November 15, 1958; October 1, 1960 and February 1, 1964. 10-b-2 Power Contract, dated February 1, 1968, between. . . . . . 13-d 2-34346 the Company and Vermont Yankee Nuclear Power Corporation. 10-b-3 Amendment, dated June 1, 1972, to Power Contract . . . . . 13-f-1 2-49697 between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-3(a) Amendment, dated April 15, 1983, to Power. . . . . . . . . 10-b-3(a) 33-8164 Contract between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-3(b) Additional Power Contract, dated . . . . . . . . . . . . . 10-b-3(b) 33-8164 February 1, 1984,between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-4 Capital Funds Agreement, dated February 1, . . . . . . . . 13-e 2-34346 1968, between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-5 Amendment, dated March 12, 1968, to Capital. . . . . . . . 13-f 2-34346 Funds Agreement between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-6 Guarantee Agreement, dated November 5, 1981, . . . . . . . 10-b-6 2-75293 of the Company for its proportionate share of the obligations of Vermont Yankee Nuclear Power Corporation under a $40 million loan arrangement. 10-b-7 Three-Party Power Agreement among the Company, . . . . . . 13-i 2-49697 VELCO and Central Vermont Public Service Corporation dated November 21, 1969. 10-b-8 Amendment to Exhibit 10-b-7, dated June 1, 1981. . . . . . 10-b-8 2-75293 10-b-9 Three-Party Transmission Agreement among the . . . . . . . 13-j 2-49697 Company, VELCO and Central Vermont Public Service Corporation, dated November 21, 1969. 10-b-10 Amendment to Exhibit 10-b-9, dated June 1, 1981. . . . . . 10-b-10 2-75293 10-b-12 Unit Purchase Contract dated February 10, 1968,. . . . . . 13-h 2-34346 between the Company and Vermont Electric Power Company, Inc., for purchase of "Merrimack" power from Public Service Company of New Hampshire. 10-b-14 Agreement with Central Maine Power Company et. . . . . . . 5.16 2-52900 al, to enter into joint ownership of Wyman plant, dated November 1, 1974. 10-b-15 New England Power Pool Agreement as amended to . . . . . . 4.8 2-55385 November 1, 1975. 10-b-16 Bulk Power Transmission Contract between the . . . . . . . 13-v 2-49697 Company and VELCO dated June 1, 1968. 10-b-17 Amendment to Exhibit 10-b-16, dated June 1, 1970.. . . . . 13-v-i 2-49697 10-b-20 Power Sales Agreement, dated August 2, 1976, as. . . . . . 10-b-20 33-8164 amended October 1, 1977, and related Transmission Agreement, with the Massachusetts Municipal Wholesale Electric Company. 10-b-21 Agreement dated October 1, 1977, for Joint . . . . . . . . 10-b-21 33-8164 Ownership, Construction and Operation of the MMWEC Phase I Intermediate Units, dated October 1, 1977. 10-b-28 Contract dated February 1, 1980, providing for . . . . . . 10-b-28 33-8164 the sale of firm power and energy by the Power Authority of the State of New York to the Vermont Public Service Board. 69 10-b-30 Bulk Power Purchase Contract dated April 7,. . . . . . . . 10-b-32 2-75293 1976, between VELCO and the Company. 10-b-33 Agreement amending New England Power Pool. . . . . . . . . 10-b-33 33-8164 Agreement dated as of December 1, 1981, providing for use of transmission inter- connection between New England and Hydro-Qubec. 10-b-34 Phase I Transmission Line Support Agreement. . . . . . . . 10-b-34 33-8164 dated as of December 1, 1981, and Amendment No. 1 dated as of June 1, 1982, between VETCO and participating New England utilities for construction, use and support of Vermont facilities of transmission interconnection between New England and Hydro-Qubec. 10-b-35 Phase I Terminal Facility Support Agreement. . . . . . . . 10-b-35 33-8164 dated as of December 1, 1981, and Amendment No. 1 dated as of June 1, 1982, between New England Electric Transmission Corporation and participating New England utilities for construction, use and support of New Hampshire facilities of transmission interconnection between New England and Hydro-Qubec. 10-b-36 Agreement with respect to use of Quebec. . . . . . . . . . 10-b-36 33-8164 Interconnection dated as of December 1, 1981, among participating New England utilities for use of transmission interconnection between New England and Hydro-Qubec. 10-b-39 Vermont Participation Agreement for Quebec . . . . . . . . 10-b-39 33-8164 Interconnection dated as of July 15, 1982, between VELCO and participating Vermont utilities for allocation of VELCO's rights and obligations as a participating New England utility in the transmission inter- connection between New England and Hydro-Qubec. 10-b-40 Vermont Electric Transmission Company, Inc.. . . . . . . . 10-b-40 33-8164 Capital Funds Agreement dated as of July 15, 1982, between VETCO and VELCO for VELCO to provide capital to VETCO for construction of the Vermont facilities of the transmission inter-connection between New England and Hydro-Qubec. 10-b-41 VETCO Capital Funds Support Agreement dated as . . . . . . 10-b-41 33-8164 of July 15, 1982, between VELCO and participating Vermont utilities for allocation of VELCO's obligation to VETCO under the Capital Funds Agreement. 10-b-42 Energy Banking Agreement dated March 21, 1983, . . . . . . 10-b-42 33-8164 among Hydro-Qubec, VELCO, NEET and parti- cipating New England utilities acting by and through the NEPOOL Management Committee for terms of energy banking between participating New England utilities and Hydro-Qubec. 10-b-43 Interconnection Agreement dated March 21, 1983,. . . . . . 10-b-43 33-8164 between Hydro-Qubec and participating New England utilities acting by and through the NEPOOL Management Committee for terms and conditions of energy transmission between New England and Hydro-Qubec. 70 10-b-44 Energy Contract dated March 21, 1983, between. . . . . . . 10-b-44 33-8164 Hydro-Qubec and participating New England utilities acting by and through the NEPOOL Management Committee for purchase of surplus energy from Hydro-Qubec. 10-b-45 Firm-Power Agreement dated as of October 5, 1982,. . . . . 10-b-45 33-8164 between Ontario Hydro and Vermont Department of Public Service. 10-b-46 Sales Agreement, dated January 20, 1983, between . . . . . 10-b-46 33-8164 Central Maine Power Company and the Company for excess power. 10-b-48 Sales Agreement, dated February 1, 1983, . . . . . . . . . 10-b-48 33-8164 between Niagara Mohawk and Vermont Electric Power Company for purchase of energy. 10-b-50 Agreement for Joint Ownership, Construction and. . . . . . 10-b-50 33-8164 Operation of the Highgate Transmission Interconnection, dated August 1, 1984, between certain electric distribution companies, including the Company. 10-b-51 Highgate Operating and Management Agreement, . . . . . . . 10-b-51 33-8164 dated as of August 1, 1984, among VELCO and Vermont electric-utility companies, including the Company. 10-b-52 Allocation Contract for Hydro-Qubec Firm Power . . . . . . 10-b-52 33-8164 dated July 25, 1984, between the State of Vermont and various Vermont electric utilities, including the Company. 10-b-53 Highgate Transmission Agreement dated as of. . . . . . . . 10-b-53 33-8164 August 1, 1984, between the Owners of the Project and various Vermont electric distribution companies. 10-b-54 Lease and Sublease Agreement dated June 1, 1984, . . . . . 10-b-54 33-8164 between Burlington Associates and the Company. 10-b-55 Ground Lease Agreement dated June 1, 1984, . . . . . . . . 10-b-55 33-8164 between GMP Real Estate Corporation and Burlington Associates. 10-b-56 Assignment of Lease and Agreement, dated June 1, . . . . . 10-b-56 33-8164 1984, from Burlington Associates to Teachers Insurance and Annuity Association of America. 10-b-57 Mortgage dated June 1, 1984, from GMP Real Estate. . . . . 10-b-57 33-8164 Corporation, Mortgagor, to Teachers Insurance and Annuity Association of America, Mortgagee. 10-b-58 Lease and Operating Agreement dated June 28,1985,. . . . . 10-b-58 33-8164 between the State of Vermont and the Company. 10-b-59 Service Contract dated June 28, 1985, between the. . . . . 10-b-59 33-8164 State of Vermont and the Company. 10-b-61 Agreements entered in connection with Phase II . . . . . . 10-b-61 33-8164 of the NEPOOL/Hydro-Qubec + 450 KV HVDC Transmission Interconnection. 10-b-62 Agreement between UNITIL Power Corp. and the . . . . . . . 10-b-62 33-8164 Company to sell 23 MW capacity and energy from Stony Brook Intermediate Combined Cycle Unit. 10-b-63 Sales Agreement dated as of June 20, 1986, . . . . . . . . 10-b-63 33-8164 between the Company and UNITIL Power Corp. for sale of system power. 10-b-64 Sales Agreement dated as of June 20, 1986, . . . . . . . . 10-b-64 33-8164 between the Company and Fitchburg Gas and Electric Light Company for sale of 10 MW capacity and energy from the Vermont Yankee plant. 71 10-b-65 Sales Agreement dated September 18, 1985,. . . . . . . . . 10-b-65 Form 10-K 1991 between the Company and Fitchburg Gas and (1-8291) Electric Light Company for the sale of system power. 10-b-66 Sales Agreement dated January 1, 1987, between . . . . . . 10-b-66 Form 10-K 1991 the Company and Bozrah Light and Power (1-8291) Company for sale of power. 10-b-67 Sales Agreement dated August 31, 1987, amending. . . . . . 10-b-67 Form 10-K 1992 the agreement dated June 20, 1986, between (1-8291) the Company and UNITIL Power Corp. for sale of system power. 10-b-68 Firm Power and Energy Contract dated December 4, . . . . . 10-b-68 Form 10-K 1992 1987, between Hydro-Qubec and participating (1-8291) Vermont utilities, including the Company, for the purchase of firm power for up to thirty years. 10-b-69 Firm Power Agreement dated as of October 26, 1987, . . . . 10-b-69 Form 10-K 1992 between Ontario Hydro and Vermont Department of (1-8291) Public Service. 10-b-70 Firm Power and Energy Contract dated as of . . . . . . . . 10-b-70 Form 10-K 1992 February 23, 1987, between the Vermont Joint (1-8291) Owners of the Highgate facilities and Hydro- Quebec for up to 50 MW of capacity. 10-b-70(a) Amendment to 10-b-70.. . . . . . . . . . . . . . . . . . . 10-b-70(a) Form 10-K 1992 (1-8291) 10-b-71 Interconnection Agreement dated as of. . . . . . . . . . . 10-b-71 Form 10-K 1992 February 23, 1987, between the Vermont Joint (1-8291) Owners of the Highgate facilities and Hydro-Qubec. 10-b-72 Participation Agreement dated as of April 1, 1988, . . . . 10-b-72 Form 10-Q between Hydro-Qubec and participating Vermont June 1988 utilities, including the Company, implementing (1-8291) the purchase of firm power for up to 30 years under the Firm Power and Energy Contract dated December 4, 1987 (previously filed with the Company's Annual Report on Form 10-K for 1987, Exhibit Number 10-b-68). 10-b-72(a) Restatement of the Participation Agreement filed . . . . . 10-b-72(a) Form 10-K 1988 as Exhibit 10-b-72 on Form 10-Q for June 1988. (1-8291) 10-b-73 Agreement dated as of May 1, 1988, between . . . . . . . . 10-b-73 Form 10-Q Rochester Gas and Electric Corporation and the September. 1988 Company, implementing the Company's purchase of up (1-8291) to 50 MW of electric capacity and associated energy. 10-b-74 Agreement dated as of November 1, 1988, between. . . . . . 10-b-74 Form 10-Q for the Company and Fitchburg Gas and Electric Light September. 1988 Company, for sale of electric capacity and (1-8291) associated energy. 10-b-74(a) Amendment to Exhibit 10-b-74.. . . . . . . . . . . . . . . 10-b-74(a) Form 10-Q September 1989 (1-8291) 10-b-75 Allocation Agreement dated as of March 25, 1988, . . . . . 10-b-75 Form 10-Q between Ontario Hydro and the State of Vermont, September. 1988 for firm power and associated energy from (1-8291) Ontario Hydro. 10-b-77 Firm Power and Energy Contract dated December 29,. . . . . 10-b-77 Form 10-K 1988 1988, between Hydro-Qubec and participating (1-8291) Vermont utilities, including the Company, for the purchase of up to 54 MW of firm power and energy. 72 10-b-78 Transmission Agreement dated December 23, 1988,. . . . . . 10-b-78 Form 10-K 1988 between the Company and Niagara Mohawk Power (1-8291) Corporation (Niagara Mohawk), for Niagara Mohawk to provide electric transmission to the Company from Rochester Gas and Electric and Central Hudson Gas and Electric. 10-b-79 Lease Agreement dated November 1, 1988, between. . . . . . 10-b-79 Form 10-K 1988 the Company and International Business Machines (1-8291) Corporation (IBM) for the lease to IBM of the gas turbines and associated facilities located on land adjacent to IBM's Essex Junction, Vermont, plant. 10-b-80 Sales Agreement dated January 1, 1989, between . . . . . . 10-b-80 Form 10-K 1988 the Company and Public Service of New Hampshire (1-8291) (PSNH)for PSNH to purchase electric capacity from the Company. 10-b-81 Sales Agreement dated May 24, 1989, between. . . . . . . . 10-b-81 Form 10-Q the Town of Hardwick, Hardwick Electric Department June 1989 and the Company for the Company to purchase (1-8291) all of the output of Hardwick's generation and transmission sources and to provide Hardwick with all-requirements energy and capacity except for that provided by the Vermont Department of Public Service or Federal Preference Power. 10-b-82 Sales Agreement dated July 14, 1989, between . . . . . . . 10-b-82 Form 10-Q Northfield Electric Department and the Company June 1989 for the Company to purchase all of the output (1-8291) of Northfield's generation and transmission sources and to provide Northfield with all- requirements energy and capacity except for that provided by the Vermont Department of Public Service or Federal Preference Power. 10-b-83 Power Purchase and Operating Agreement dated as. . . . . . 10-b-83 Form 10-Q of April 20, 1990, between CoGen Lime Rock, June 1990 Inc., and the Company for the production of (1-8291) energy to meet customer needs. 10-b-84 Capacity, Transmission and Energy Service. . . . . . . . . 10-b-84 Form 10-K 1992 Agreement dated December 23, 1992, between (1-8291) the Company and Connecticut Light and Power Company (CL&P) for CL&P to supply power to Bozrah Light and Power Company. 10-b-85 Power Purchase and Sale Agreement between. . . . . . . . . 10-b-85 Form 10-K 1998 Morgan Stanley Capital Group Inc. and the (1-8291) Company MANAGEMENT CONTRACTS OR COMPENSATORY PLANS OR ARRANGEMENTS REQUIRED TO BE FILED AS EXHIBITS TO THIS FORM 10-K PURSUANT TO ITEM 14(C)., ALL UNDER SEC DOCKET 1-8291 10-d-1b Green Mountain Power Corporation Second Amended. . . . . . 10-d-1b Form 10-K 1993 and Restated Deferred Compensation Plan for Directors. 10-d-1c Green Mountain Power Corporation Second Amended. . . . . . 10-d-1c Form 10-K 1993 and Restated Deferred Compensation Plan for Officers. 10-d-1d Amendment No. 93-1 to the Amended and Restated . . . . . . 10-d-1d Form 10-K 1993 Deferred Compensation Plan for Officers. 10-d-1e Amendment No. 94-1 to the Amended and Restated . . . . . . 10-d-1e Form 10-Q Deferred Compensation Plan for Officers. June 1994 73 10-d-2 Green Mountain Power Corporation Medical Expense . . . . . 10-d-2 Form 10-K 1991 Reimbursement Plan. 10-d-4 Green Mountain Power Corporation Officer . . . . . . . . . 10-d-4 Form 10-K 1991 Insurance Plan. 10-d-4a Green Mountain Power Corporation Officers' . . . . . . . . 10-d-4a Form 10-K 1990 Insurance Plan as amended. 10-d-8 Green Mountain Power Corporation Officers' . . . . . . . . 10-d-8 Form 10-K 1990 Supplemental Retirement Plan. 10-d-15b Green Mountain Power Corporation Compensation Program. . . 10-d-15b Form 10-K 1997 for Officers and Key Management Personnel as amended August 4, 1997 10-d-21 Severance Agreement with N. R. Brock . . . . . . . . . . . 10-d-21 Form 10-K 1998 10-d-22 Severance Agreement with C. L. Dutton. . . . . . . . . . . 10-d-22 Form 10-K 1998 10-d-23 Severance Agreement with R. J. Griffin . . . . . . . . . . 10-d-23 Form 10-K 1998 10-d-24 Severance Agreement with J. J. Lampron . . . . . . . . . . 10-d-24 Form 10-K 1998 10-d-25 Severance Agreement with M. H. Lipson. . . . . . . . . . . 10-d-25 Form 10-K 1998 10-d-26 Severance Agreement with C. T. Myotte. . . . . . . . . . . 10-d-26 Form 10-K 1998 10-d-27 Severance Agreement with W. S. Oakes . . . . . . . . . . . 10-d-27 Form 10-K 1998 10-d-28 Severance Agreement with M. G. Powell. . . . . . . . . . . 10-d-28 Form 10-K 1998 10-d-29 Severance Agreement with S. C. Terry . . . . . . . . . . . 10-d-29 Form 10-K 1998 10-d-30 Severance Agreement with J. H. Winer . . . . . . . . . . . 10-d-30 Form 10-K 1998 21 Subsidiaries of the Registrant . . . . . . . . . . . . . . 21 Form 10-K 1996 *23-a-1 Consent of Arthur Andersen LLP *27 Financial Data Schedule
74 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. GREEN MOUNTAIN POWER CORPORATION By: ____/s/ Christopher L. Dutton________ -------------------------- Christopher L. Dutton, President and Chief Executive Officer Date: March 28, 2000 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. SIGNATURE TITLE DATE __/s/ Christopher L. Dutton President and Director March 28, 2000 ------------------------- Christopher L. Dutton (Principal Executive Officer) _/s/Nancy R. Brock_______ Vice President, Treasurer and March 28, 2000 --------------------- Nancy R. Brock Chief Financial Officer (Principal Financial Officer) /s/Robert J. Griffin_ Controller March 28, 2000 ----------------------- Robert J. Griffin (Principal Accounting Officer) *Thomas P. Salmon Chairman of the Board *Nordahl L. Brue ) *William H. Bruett ) *Lorraine E. Chickering ) *John V. Cleary ) Directors *Euclid A. Irving ) *Martin L. Johnson ) *Ruth W. Page ) *By: _/s/ Christopher L. Dutton March 28, 2000 --------------------------- Christopher L. Dutton (Attorney - in - Fact) 75 EX-27 2 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT EXHIBIT 27 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1999 AND THE RELATED CONSOLIDATED STATEMENTS OF INCOME AND CASH FLOWS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. GREEN MOUNTAIN POWER CORPORATION FINANCIAL DATA SCHEDULE FORM 10-K DECEMBER 31, 1999 (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) 1000 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 per-book 192826 20665 33238 41853 11099 299751 18085 72594 10344 100645 1880 12555 88500 7900 0 0 6700 1650 7038 0 89133 299751 251048 1242 241860 243102 7946 3453 11399 7183 (3063) 1155 (4218) 2946 6716 15105 (.79) (.79)
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