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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