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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 taxa