SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
---------------------------
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report February 29, 2000
NORTHEAST UTILITIES
-------------------
(Exact name of registrant as specified in its charter)
MASSACHUSETTS 1-5324 04-2147929
------------ ------ ----------
State or other Commission I.R.S. Employer
jurisdiction of File No.) Identification No.)
incorporation
or organization)
174 BRUSH HILL AVENUE
WEST SPRINGFIELD, MASSACHUSETTS 01090-0010
-------------------------------------------
(Address of principal executive offices)
Registrant's telephone number, including area code
(413) 785-5871
INFORMATION TO BE INCLUDED IN THE REPORT
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
(c) Exhibits
23 Consent of Arthur Andersen LLP
27 Financial Data Schedule (To the extent provided in Rule 402 of
Regulation S-T, this exhibit shall not be deemed "filed", or otherwise
subject to liabilities, or be deemed part of a registration statement.)
99.1 Consolidated balance sheet and statement of capitalization at
December 31, 1999 and 1998, and related consolidated statements of
income, of retained earnings, and of cash flows for each of the three
years in the period ended December 31, 1999, and the notes thereto, of
Northeast Utilities and its subsidiaries ("1999 Financial Statements").
99.2 Report of Arthur Andersen LLP, dated January 25, 2000, relating to the
1999 Financial Statements.
99.3 Management's Discussion and Analysis of Financial Condition and Results
of Operations, dated January 25, 2000, relating to the 1999 Financial
Statements.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
(c) Exhibits
SIGNATURE
Pursuant to the requirements of the Securities and Exchange Act of 1934,
Registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
NORTHEAST UTILITIES
By: /s/ John H. Forsgren
-------------------------------
John H. Forsgren
Executive Vice President
and Chief Financial Officer
Date: February 23, 2000
Exhibit 23 to Form 8-K Report
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report included in this Form 8-K, into the Company's previously filed
Registration Statements No. 33-55279 of The Connecticut Light and Power
Company, No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814,
No. 33-63023, No. 33-40156, No. 333-52413, No. 333-52415, and No. 333-85613
of Northeast Utilities. It should be noted that we have not audited any
financial statements of the Company subsequent to December 31, 1999 or
performed any audit procedures subsequent to the date of our report.
/s/ ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 25, 2000
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000072741
<NAME> NORTHEAST UTILITIES AND SUBSIDIARIES
<MULTIPLIER>1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,947,434
<OTHER-PROPERTY-AND-INVEST> 888,181
<TOTAL-CURRENT-ASSETS> 1,071,280
<TOTAL-DEFERRED-CHARGES> 3,781,157
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 9,688,052
<COMMON> 686,969
<CAPITAL-SURPLUS-PAID-IN> 940,726
<RETAINED-EARNINGS> 581,817
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,083,311
121,289
136,200
<LONG-TERM-DEBT-NET> 2,372,341
<SHORT-TERM-NOTES> 278,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 457,065
46,250
<CAPITAL-LEASE-OBLIGATIONS> 62,824
<LEASES-CURRENT> 118,469
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,012,303
<TOT-CAPITALIZATION-AND-LIAB> 9,688,052
<GROSS-OPERATING-REVENUE> 4,471,251
<INCOME-TAX-EXPENSE> 98,611
<OTHER-OPERATING-EXPENSES> 3,945,831
<TOTAL-OPERATING-EXPENSES> 4,126,714
<OPERATING-INCOME-LOSS> 344,537
<OTHER-INCOME-NET> (106,187)
<INCOME-BEFORE-INTEREST-EXPEN> 320,622
<TOTAL-INTEREST-EXPENSE> 263,651
<NET-INCOME> 56,971
22,755
<EARNINGS-AVAILABLE-FOR-COMM> 34,216
<COMMON-STOCK-DIVIDENDS> 13,168
<TOTAL-INTEREST-ON-BONDS> 258,093
<CASH-FLOW-OPERATIONS> 614,218
<EPS-BASIC> 0.26
<EPS-DILUTED> 0.26
</TABLE>
Exhibit 99.1 to Form 8-K Report
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Income
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information) 1999 1998 1997
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues................................. $ 4,471,251 $ 3,767,714 $ 3,834,806
------------- ------------- -------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power...... 1,898,314 1,470,200 1,478,566
Other.......................................... 855,917 803,419 919,431
Maintenance........................................ 340,419 399,165 501,693
Depreciation....................................... 302,305 332,807 354,329
Amortization of regulatory assets, net............. 596,437 203,132 123,718
Federal and state income taxes..................... 180,883 82,332 12,650
Taxes other than income taxes...................... 261,353 251,932 253,637
Gain on sale of utility plant...................... (308,914) - -
------------- ------------- -------------
Total operating expenses..................... 4,126,714 3,542,987 3,644,024
------------- ------------- -------------
Operating Income................................... 344,537 224,727 190,782
------------- ------------- -------------
Other Income/(Loss):
Equity in earnings of regional nuclear generating
and transmission companies.................... 5,034 12,420 11,306
Nuclear unrecoverable costs ....................... (71,066) (143,239) -
Other, net......................................... (30,855) (12,225) (31,185)
Minority interest in loss of subsidiary............ (9,300) (9,300) (9,300)
Income taxes....................................... 82,272 76,393 10,702
------------- ------------- -------------
Other loss, net.............................. (23,915) (75,951) (18,477)
------------- ------------- -------------
Income before interest charges............... 320,622 148,776 172,305
------------- ------------- -------------
Interest Charges:
Interest on long-term debt......................... 258,093 273,824 282,095
Other interest..................................... 13,959 7,808 3,561
Deferred interest - nuclear plants................. (8,401) (12,543) (13,675)
------------- ------------- -------------
Interest charges, net........................ 263,651 269,089 271,981
------------- ------------- -------------
Income/(loss) after interest charges......... 56,971 (120,313) (99,676)
Preferred Dividends of Subsidiaries................ 22,755 26,440 30,286
------------- ------------- -------------
Net Income/(Loss).................................. $ 34,216 $ (146,753) $ (129,962)
============= ============= =============
Earnings/(Loss) Per Common Share -
Basic and Diluted $ 0.26 $ (1.12) $ (1.01)
============= ============= =============
Common Shares Outstanding (average)................ 131,415,126 130,549,760 129,567,708
============= ============= =============
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income
Net Income/(Loss).................................. $ 34,216 $ (146,753) $ (129,962)
------------- ------------- -------------
Other comprehensive income, net of tax:
Foreign currency translation adjustments........... 1 - (499)
Unrealized gains on securities..................... 118 2,019 -
Minimum pension liability adjustments.............. - (613) -
------------- ------------- -------------
Other comprehensive income/(loss), net of tax.. 119 1,406 (499)
------------- ------------- -------------
Comprehensive Income/(Loss)........................ $ 34,335 $ (145,347) $ (130,461)
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility Plant, at cost:
Electric................................................ $ 9,185,272 $ 9,570,547
Other................................................... 226,002 195,325
------------- -------------
9,411,274 9,765,872
Less: Accumulated provision for depreciation............ 6,088,310 4,224,416
------------- -------------
3,322,964 5,541,456
Unamortized PSNH acquisition costs........................ 324,437 352,855
Construction work in progress............................. 177,504 143,159
Nuclear fuel, net......................................... 122,529 133,411
------------- -------------
Total net utility plant.............................. 3,947,434 6,170,881
------------- -------------
Other Property and Investments:
Nuclear decommissioning trusts, at market................. 711,910 619,143
Investments in regional nuclear generating
companies, at equity.................................... 81,503 85,791
Other, at cost............................................ 94,768 151,857
------------- -------------
888,181 856,791
------------- -------------
Current Assets:
Cash and cash equivalents................................. 255,154 136,155
Investments in securitizable assets....................... 107,620 182,118
Receivables, less accumulated provision for uncollectible
accounts of $4,895 in 1999 and $2,416 in 1998........... 310,190 237,207
Unbilled revenues......................................... 75,728 42,145
Fuel, materials and supplies, at average cost............. 172,973 202,661
Recoverable energy costs, net of current portion.......... 73,721 67,181
Prepayments and other..................................... 75,894 68,087
------------- -------------
1,071,280 935,554
------------- -------------
Deferred Charges:
Regulatory assets......................................... 3,642,439 2,328,949
Unamortized debt expense.................................. 39,192 40,416
Other .................................................... 99,526 54,790
------------- -------------
3,781,157 2,424,155
------------- -------------
Total Assets.............................................. $ 9,688,052 $ 10,387,381
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization and Liabilities
Capitalization:
Common shares, $5 par value - authorized 225,000,000
shares; 137,393,829 shares issued and 131,870,284
shares outstanding in 1999 and 137,031,264 shares
issued and 130,954,740 shares outstanding in 1998....... $ 686,969 $ 685,156
Capital surplus, paid in.................................. 940,726 940,661
Deferred contribution plan - employee stock
ownership plan.......................................... (127,725) (140,619)
Retained earnings......................................... 581,817 560,769
Accumulated other comprehensive income.................... 1,524 1,405
------------- -------------
Total common shareholders' equity.................... 2,083,311 2,047,372
Preferred stock not subject to mandatory redemption....... 136,200 136,200
Preferred stock subject to mandatory redemption........... 121,289 167,539
Long-term debt............................................ 2,372,341 3,282,138
------------- -------------
Total capitalization................................. 4,713,141 5,633,249
------------- -------------
Minority Interest in Consolidated Subsidiaries............ 100,000 100,000
------------- -------------
Obligations Under Capital Leases.......................... 62,824 88,423
------------- -------------
Current Liabilities:
Notes payable to banks.................................... 278,000 30,000
Long-term debt and preferred stock - current portion...... 503,315 397,153
Obligations under capital leases - current portion........ 118,469 120,856
Accounts payable.......................................... 347,321 338,612
Accrued taxes............................................. 158,684 50,755
Accrued interest.......................................... 37,904 51,044
Other..................................................... 126,768 139,367
------------- -------------
1,570,461 1,127,787
------------- -------------
Deferred Credits and Other Long-term Liabilities:
Accumulated deferred income taxes......................... 1,688,114 1,848,694
Accumulated deferred investment tax credits............... 140,407 143,369
Decommissioning obligation - Millstone 1.................. 702,351 692,000
Deferred contractual obligations.......................... 358,387 418,760
Other..................................................... 352,367 335,099
------------- -------------
3,241,626 3,437,922
------------- -------------
Total Capitalization and Liabilities...................... $ 9,688,052 $ 10,387,381
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Shareholders' Equity
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
Accum-
Deferred ulated
Contribu- Other
Capital tion Retained Compre-
Common Surplus, Plan- Earnings hensive
(Thousands of Dollars) Shares Paid In ESOP (a) Income Total
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance as of
January 1, 1997................$680,260 $939,589 $(176,091)$ 869,618 $ 498 $2,313,874
--------------------------------------------------------
Net loss for 1997............. (129,962) (129,962)
Cash dividends on common
shares-$0.25 per share...... (32,134) (32,134)
Issuance of 790,232 common
shares, $5 par value........ 3,951 2,551 6,502
Allocation of benefits - ESOP. (12,238) 21,950 9,712
Capital stock expenses, net... 2,592 2,592
Other comprehensive
income/(loss)............... (499) (499)
--------------------------------------------------------
Balance as of
December 31, 1997............. 684,211 932,494 (154,141) 707,522 (1) 2,170,085
--------------------------------------------------------
Net loss for 1998............. (146,753) (146,753)
Issuance of 189,094 common
shares, $5 par value........ 945 1,714 2,659
Allocation of benefits - ESOP. (4,769) 13,522 8,753
Unearned stock compensation... (537) (537)
Capital stock expenses, net... 3,560 3,560
Gain on equity investment..... 8,140 8,140
Gain on repurchase of
preferred stock............. 59 59
Other comprehensive income.... 1,406 1,406
--------------------------------------------------------
Balance as of
December 31, 1998............. 685,156 940,661 (140,619) 560,769 1,405 2,047,372
--------------------------------------------------------
Net income for 1999........... 34,216 34,216
Cash dividends on common
shares-$0.10 per share...... (13,168) (13,168)
Issuance of 362,565 common
shares, $5 par value........ 1,813 3,505 5,318
Allocation of benefits - ESOP. (3,053) 12,894 9,841
Unearned stock compensation... (1,194) (1,194)
Capital stock expenses, net... 807 807
Other comprehensive income.... 119 119
--------------------------------------------------------
Balance as of
December 31, 1999.............$686,969 $940,726 $(127,725)$ 581,817 $1,524 $2,083,311
========================================================
(a) Certain consolidated subsidiaries have dividend restrictions imposed by their
long-term debt agreements. These restrictions also limit the amount of retained
earnings available for NU common dividends. At December 31, 1999, retained earnings
available for payment of dividends totaled $158.5 million.
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998 1997
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities:
Income/(loss) after interest charges......................... $ 56,971 $(120,313) $ (99,676)
Adjustments to reconcile to net cash
provided by operating activities:
Depreciation............................................... 302,305 332,807 354,329
Deferred income taxes and investment tax credits, net...... (183,356) 23,502 26,435
Amortization of regulatory assets, net..................... 596,437 203,132 123,718
Amortization of demand-side-management costs, net.......... 10,014 42,085 38,029
Amortization/(deferral) of recoverable energy costs........ 44,526 38,356 (54,102)
Nuclear unrecoverable costs................................ 71,066 143,239 -
Gain on sale of utility plant.............................. (308,914) - -
Net other sources and (uses) of cash....................... (55,543) 55,399 (66,518)
Changes in working capital:
Receivables and unbilled revenues, net..................... (106,566) (27,553) 352,384
Fuel, materials and supplies............................... 29,688 10,060 (1,307)
Accounts payable........................................... 8,709 (64,258) (104,269)
Accrued taxes.............................................. 107,929 4,739 38,966
Investments in securitizable assets........................ 74,498 48,787 (230,905)
Other working capital (excludes cash)...................... (33,546) (26,714) (36,464)
---------- ---------- ----------
Net cash flows provided by operating activities................ 614,218 663,268 340,620
---------- ---------- ----------
Financing Activities:
Issuance of common shares.................................... 5,318 2,659 6,502
Issuance of long-term debt................................... 200 275 260,000
Net increase/(decrease) in short-term debt................... 248,000 (20,000) 11,250
Reacquisitions and retirements of long-term debt............. (817,759) (269,555) (288,793)
Reacquisitions and retirements of preferred stock............ (46,250) (62,211) (25,000)
Cash dividends on preferred stock............................ (22,755) (26,440) (30,286)
Cash dividends on common shares.............................. (13,168) - (32,134)
---------- ---------- ----------
Net cash flows used in financing activities.................... (646,414) (375,272) (98,461)
---------- ---------- ----------
Investing Activities:
Investment in plant:
Electric and other utility plant........................... (287,081) (217,009) (233,399)
Nuclear fuel............................................... (42,471) (17,026) (6,852)
---------- ---------- ----------
Net cash flows used for investments in plant................. (329,552) (234,035) (240,251)
Investment in nuclear decommissioning trusts................. (74,231) (75,551) (61,046)
Investment in nonregulated assets............................ (23,542) - -
Net proceeds from the sale of utility plant.................. 565,436 - -
Other investment activities, net............................. 13,084 14,342 8,344
---------- ---------- ----------
Net cash flows provided by/(used in) investing activities...... 151,195 (295,244) (292,953)
---------- ---------- ----------
Net increase/(decrease) in cash for the period................. 118,999 (7,248) (50,794)
Cash and cash equivalents - beginning of period................ 136,155 143,403 194,197
---------- ---------- ----------
Cash and cash equivalents - end of period...................... $ 255,154 $ 136,155 $ 143,403
========== ========== ==========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized......................... $ 266,823 $ 238,990 $ 291,335
========== ========== ==========
Income taxes................................................. $ 86,183 $ 19,454 $ (26,387)
========== ========== ==========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases.............. $ 5,865 $ 12,583 $ 3,475
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Capitalization
<TABLE>
At December 31,
(Thousands of Dollars) 1999 1998
<S> <C> <C>
Common Shareholders' Equity........................................................ $ 2,083,311 $ 2,047,372
------------ ------------
Cumulative Preferred Stock of Subsidiaries:
$25 par value - authorized 36,600,000 shares at December 31, 1999 and 1998;
2,720,000 shares outstanding in 1999 and 3,780,000 shares outstanding in 1998
$50 par value - authorized 9,000,000 shares at December 31, 1999 and 1998;
4,314,774 shares outstanding in 1999 and 4,709,774 shares outstanding in 1998
$100 par value - authorized 1,000,000 shares at December 31, 1999 and 1998;
200,000 shares outstanding in 1999 and 1998
Current
Current Shares
Dividend Rates Redemption Price (a) Outstanding
Not Subject to Mandatory
Redemption:
$50 par value - $1.90 to $3.28 $50.50 to $54.00 2,324,000......... 116,200 116,200
$100 par value - $7.72 $103.51 200,000......... 20,000 20,000
------------ ------------
Total Preferred Stock Not Subject
to Mandatory Redemption.......................................................... 136,200 136,200
------------ ------------
Subject to Mandatory Redemption: (b)
$25 par value - $1.90 to $2.65 $25.00 to $25.38 2,720,000......... 68,000 94,500
$50 par value - $2.65 to $3.615 $50.67 to $51.93 1,990,774......... 99,539 119,289
------------ ------------
Total Preferred Stock Subject to
Mandatory Redemption............................................................. 167,539 213,789
Less: Preferred Stock to be
redeemed within one year......................................................... 46,250 46,250
------------ ------------
Preferred Stock Subject to
Mandatory Redemption, net........................................................ 121,289 167,539
------------ ------------
Long-Term Debt: (c)
First Mortgage Bonds -
Maturity Interest Rates
1999 5.50% to 7.25%......................................................... - 254,000
2000 5.75% to 6.875%........................................................ 159,000 260,000
2001 7.375% to 7.875%....................................................... 220,000 220,000
2002 7.75% to 9.05%......................................................... 489,150 560,000
2004 6.125%................................................................. - 140,000
2019-2023 7.375% to 7.50%........................................................ 20,000 120,000
2024-2025 7.375% to 8.50%........................................................ 305,000 430,000
------------ ------------
Total First Mortgage Bonds....................................................... 1,193,150 1,984,000
------------ ------------
Other Long-Term Debt -
Pollution Control Notes and
Other Notes - (d)
2000 Adjustable Rate (e)
and 7.67%.............................................................. 206,011 212,022
2005-2006 8.38% to 8.58%......................................................... 158,000 177,000
2013-2018 Adjustable Rate
and 5.90%.............................................................. 33,400 33,400
2020 Adjustable Rate........................................................ 15,300 15,300
2021-2022 5.85% to 7.65% and
Adjustable Rate........................................................ 552,485 552,485
2028 5.85% to 5.95%......................................................... 369,300 369,300
2031 Adjustable Rate........................................................ 62,000 62,000
------------ ------------
Total Pollution Control Notes
and Other Notes................................................................ 1,396,496 1,421,507
Fees and interest due for spent
nuclear fuel disposal costs...................................................... 226,463 216,377
Other.............................................................................. 15,346 17,043
------------ ------------
Total Other Long-Term Debt......................................................... 1,638,305 1,654,927
------------ ------------
Unamortized premium and
discount, net.................................................................... (2,049) (5,886)
------------ ------------
Total Long-Term Debt............................................................... 2,829,406 3,633,041
Less: Amounts due within one year................................................. 457,065 350,903
------------ ------------
Long-Term Debt, net................................................................ 2,372,341 3,282,138
------------ ------------
Total Capitalization............................................................... $ 4,713,141 $ 5,633,249
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements
NORTHEAST UTILITIES AND SUBSIDIARIES
Notes to Consolidated Statements of Capitalization
(a) Each of these series is subject to certain refunding limitations for
the first five years after issuance. Redemption prices reduce in
future years.
(b) Changes in Preferred Stock Subject to Mandatory Redemption:
(Millions of Dollars)
Balance at December 31, 1997................. $276.0
Reacquisitions and Retirements............. (62.2)
Balance at December 31, 1998................. 213.8
Reacquisitions and Retirements............. (46.3)
Balance at December 31, 1999................. $167.5
The minimum sinking fund requirements of the series subject each year to
mandatory redemption aggregate $46.3 million each year in 2000 and 2001,
$21.3 million in 2002, $7.7 million in 2003 and $5.3 million in 2004. In
case of default on sinking fund payments, no payments may be made on any
junior stock by way of dividends or otherwise (other than in shares of
junior stock) so long as the default continues. If a subsidiary is in
arrears in the payment of dividends on any outstanding shares of preferred
stock, the subsidiary is prohibited from redeeming or purchasing less than
all of the outstanding preferred stock.
(c) Long-term debt maturities and cash sinking fund requirements, excluding
fees and interest due for spent nuclear fuel disposal costs, on debt
outstanding at December 31, 1999, for the years 2000 through 2004 are
$457.1 million, $314 million, $374.6 million, $25.6 million, and $25.5
million, respectively.
Essentially all utility plant of CL&P, PSNH, WMECO, and NAEC, is subject
to the liens of each company's respective first mortgage bond indenture.
NAEC's first mortgage bonds are also secured by payments made to NAEC by
PSNH under the terms of two life-of-unit, full cost recovery contracts.
CL&P and WMECO have secured $369.3 million of pollution control notes with
second mortgage liens on Millstone 1, junior to the liens of their
respective first mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs)
with bond insurance secured by the first mortgage bonds and a liquidity
facility.
Concurrent with the issuance of PSNH's Series A and B first mortgage bonds,
PSNH entered into financing arrangements with the Business Finance
Authority (BFA) of the state of New Hampshire. Pursuant to these
arrangements, the BFA issued seven series of PCRBs and loaned the proceeds
to PSNH. At December 31, 1999 and 1998, $516.5 million of the PCRBs were
outstanding. PSNH's obligation to repay each series of PCRBs is secured by
the first mortgage bonds. Each such series of first mortgage bonds
contains similar terms and provisions as the applicable series of PCRBs.
For financial reporting purposes, these bonds would not be considered
outstanding unless PSNH failed to meet its obligations under the PCRBs.
(d) The average effective interest rates on the variable-rate pollution control
notes ranged from 2.2 percent to 6.1 percent for 1999 and 3.1 percent to
5.6 percent for 1998.
During 1998, $535 million of adjustable-rate debt was converted to fixed-
rate debt at rates ranging from 5.85 percent to 6.0 percent.
(e) Interest rate swaps effectively fix the interest rate of NAEC's $200
million variable-rate bank note at interest rates ranging from 5.81 percent
to 6.07 percent.
Consolidated Statements of Income Taxes
For the Years Ended December 31,
(Thousands of Dollars) 1999 1998 1997
The components of the federal and state
income tax provisions charged to
operations are:
Current income taxes:
Federal.................................. $ 248,012 $ (13,660) $ (22,760)
State.................................... 33,955 (3,903) (1,727)
---------- ---------- ----------
Total current.............................. 281,967 (17,563) (24,487)
---------- ---------- ----------
Deferred income taxes, net:
Federal.................................. (134,773) 51,913 46,871
State.................................... (28,789) (12,948) (10,841)
---------- ---------- ----------
Total deferred............................. (163,562) 38,965 36,030
---------- ---------- ----------
Investment tax credits, net................ (19,794) (15,463) (9,595)
---------- ---------- ----------
Total income tax expense................... $ 98,611 $ 5,939 $ 1,948
========== ========== ==========
The components of total income tax
expense are classified as follows:
Income taxes charged to operating
expenses............................... $ 180,883 $ 82,332 $ 12,650
Other income taxes....................... (82,272) (76,393) (10,702)
---------- ---------- ----------
Total income tax expense................... $ 98,611 $ 5,939 $ 1,948
========== ========== ==========
Deferred income taxes are comprised of
the tax effects of temporary
differences as follows:
Deferred tax asset associated with
net operating losses................... $ 14,801 $ 69,212 $ -
Depreciation, leased nuclear fuel,
settlement credits and disposal costs.. (4,580) 16,217 32,932
Regulatory deferral...................... (23,463) (26,786) 19,237
State net operating loss carryforward.... 7,777 1,150 (7,670)
Regulatory disallowance.................. (30,719) (18,080) -
Sale of fossil and hydroelectric
generation assets...................... (125,807) - -
Other.................................... (1,571) (2,748) (8,469)
---------- ---------- ----------
Deferred income taxes, net................. $(163,562) $ 38,965 $ 36,030
========== ========== ==========
A reconciliation between income tax
expense and the expected tax
expense at 35 percent of pretax
income:
Expected federal income tax................ $ 54,454 $ (40,031) $ (34,205)
Tax effect of differences:
Depreciation............................. 35,672 25,793 21,776
Amortization of regulatory assets........ 34,736 30,740 5,498
Amortization of PSNH acquisition costs... 9,946 17,301 31,298
Investment tax credit amortization....... (19,794) (15,463) (9,595)
State income taxes, net of federal
benefit................................ 3,358 (10,953) (8,169)
Nondeductible penalties.................. 17 3,589 648
Adjustment for prior years' taxes........ (2,796) (7,338) (2,592)
Employee stock ownership plan............ 1,166 (1,670) (4,648)
Dividends received deduction............. (1,314) (3,218) (1,563)
Adjustment to tax asset valuation
allowance.............................. (23,129) 7,000 8,750
Merger related expenditures.............. 4,597 - -
Other, net............................... 1,698 189 (5,250)
--------- ---------- ----------
Total income tax expense $ 98,611 $ 5,939 $ 1,948
========= ========== ==========
The accompanying notes are in integral part of these financial statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. About Northeast Utilities
Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system (NU system). Through its regulated utilities and unregulated
energy service companies, the NU system serves in excess of 30 percent of
New England's electric needs and is one of the 20 largest electric utility
systems in the country as measured by revenues. The NU system's regulated
utilities furnish franchised retail electric service in Connecticut, New
Hampshire and western Massachusetts through three wholly owned subsidiaries:
The Connecticut Light and Power Company (CL&P), Public Service Company of
New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO).
Another wholly owned subsidiary, North Atlantic Energy Corporation (NAEC),
sells all of its entitlement to the capacity and output of the Seabrook
Station (Seabrook) nuclear unit to PSNH under the terms of two life-of-unit,
full cost recovery contracts (Seabrook Power Contracts). A fifth wholly owned
subsidiary, Holyoke Water Power Company (HWP), also is engaged in the
production and distribution of electric power.
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935 (1935
Act), and the NU system is subject to the provisions of the 1935 Act.
Arrangements among the NU system companies, outside agencies and other
utilities covering interconnections, interchange of electric power and sales
of utility property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. The operating subsidiaries are subject to
further regulation for rates, accounting and other matters by the FERC and/or
applicable state regulatory commissions.
NU Enterprises, Inc. (NUEI) is a wholly owned subsidiary of NU and acts as the
holding company for NU's unregulated energy service companies. Northeast
Generation Company (NGC) was formed to acquire generating facilities.
Northeast Generation Services Company (NGS) was formed to provide services to
the electric generation market as well as to large commercial and industrial
customers in the Northeast. Select Energy, Inc. (Select Energy), HEC Inc.
(HEC) and Mode 1 Communications, Inc. (Mode 1) engage in a variety of
energy-related and telecommunications activities, as applicable, primarily in
the unregulated energy retail and wholesale commodity, marketing and services
fields. During 1999 and 1998, NUEI accounted for 13.6 percent and 1.4 percent
of consolidated revenues, respectively.
Several wholly owned subsidiaries of NU provide support services for the NU
system companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing, and other services to the NU system
companies. Northeast Nuclear Energy Company acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
units. North Atlantic Energy Service Corporation has operational
responsibility for Seabrook. Three other subsidiaries construct, acquire or
lease some of the property and facilities used by the NU system companies.
On October 13, 1999, NU and Consolidated Edison, Inc. (Con Edison) announced
that they have agreed to a merger to combine the two companies. For further
information, see Note 15, " Merger Agreement with Con Edison."
On October 12, 1999, Yankee Energy System, Inc. shareholders approved the
proposed merger with NU. On December 20, 1999, the Connecticut Department of
Public Utility Control (DPUC) issued its final decision approving the merger.
In January 2000, the SEC granted final approval of the merger. The
transaction is expected to close in early March 2000.
B. Presentation
The consolidated financial statements of the NU system include the accounts
of all subsidiaries. Intercompany transactions have been eliminated in
consolidation.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with
the current year's presentation.
C. New Accounting Standards
The Financial Accounting Standards Board (FASB) has issued Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 establishes accounting
and reporting standards for derivative instruments and hedging activities.
This statement will require derivative instruments utilized by the NU system
companies to be recognized on the balance sheets as assets or liabilities
at fair value.
In June 1999, the FASB delayed the adoption date of SFAS No. 133 until
January 1, 2001.
Based on the derivative instruments which currently are being utilized by
the NU system companies to hedge some of their interest rate risk and certain
power contracts, there may be an impact on earnings upon adoption of SFAS
No. 133 which management has not estimated at this time.
D. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock
in four regional nuclear companies (Yankee Companies). The NU system's
ownership interests in the Yankee Companies at December 31, 1999 and 1998,
which are accounted for on the equity basis due to the NU system companies'
ability to exercise significant influence over their operating and financial
policies are 49 percent of the Connecticut Yankee Atomic Power Company
(CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent
of the Maine Yankee Atomic Power Company (MYAPC), and 16 percent of the
Vermont Yankee Nuclear Power Corporation (VYNPC). The NU system's total
equity investment in the Yankee Companies at December 31, 1999 and 1998,
is $81.5 million and $85.8 million, respectively. Each Yankee Company owns
a single nuclear generating unit. However, VYNPC is the only unit still in
operation at December 31, 1999.
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a
660 megawatt (MW) nuclear unit and Millstone 2, an 870 MW nuclear
generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint
ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. The
company expects to auction all three units as a single package in 2000, with
a closing in 2001. Appropriate regulatory approvals will be required
to complete the auction.
Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook, a 1,148 MW nuclear generating unit. NAEC sells all of
its share of the power generated by Seabrook to PSNH under the Seabrook Power
Contracts. CL&P and NAEC expect to auction their investment in Seabrook
upon the resolution of the restructuring issues in the state of New Hampshire.
Plant-in-service and the accumulated provision for depreciation for the
NU system's share of Millstone 2 and 3 and Seabrook are as follows:
At December 31,
(Millions of Dollars) 1999 1998
Plant-in-service
Millstone 2............................ $ 952.1 $ 936.8
Millstone 3............................ 2,414.9 2,407.4
Seabrook............................... 901.9 895.5
Accumulated provision for depreciation
Millstone 2............................ $ 910.0 $ 379.6
Millstone 3............................ 2,220.5 765.9
Seabrook............................... 318.8 170.0
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
$16.5 million, in two companies that transmit electricity imported from
the Hydro-Quebec system in Canada.
E. Depreciation
The provision for depreciation is calculated using the straight-line method
based on the estimated remaining useful lives of depreciable utility plant-
in-service, adjusted for salvage value and removal costs, as approved by the
appropriate regulatory agency where applicable. Except for major facilities,
depreciation rates are applied to the average plant-in-service during the
period. Major facilities are depreciated from the time they are placed in
service. When plant is retired from service, the original cost of the plant,
including costs of removal less salvage, is charged to the accumulated
provision for depreciation. The costs of closure and removal of nonnuclear
facilities are accrued over the life of the plant as a component of
depreciation. The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.3 percent in
1999 and 1998 and 3.8 percent in 1997.
At December 31, 1999 and 1998, the accumulated provision for depreciation
included $91.5 million and $88.4 million, respectively, accrued for the cost
of removal, net of salvage, for nonnuclear generation property.
As a result of discontinuing the application of SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation
businesses, including CL&P's ownership interest in Seabrook, the company
recorded a charge to accumulated depreciation for the nuclear plant in excess
of fair market value in the amount of $2 billion, and a corresponding
regulatory asset was created.
F. Revenues
Regulated utility revenues are based on authorized rates applied to each
customer's use of electricity. In general, rates can be changed only through a
formal proceeding before the appropriate regulatory commission. Regulatory
commissions also have authority over the terms and conditions of nontraditional
rate-making arrangements. At the end of each accounting period, CL&P, PSNH and
WMECO accrue a revenue estimate for the amount of energy delivered but
unbilled.
Revenues for NU's unregulated subsidiaries, primarily Select Energy, are
recognized when the energy is delivered.
G. PSNH Acquisition Costs
PSNH acquisition costs represent the aggregate value placed by the 1989 rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in
excess of the net book value of PSNH's non-Seabrook assets, plus the $700
million value assigned to Seabrook by the Rate Agreement as part of the
bankruptcy resolution on June 5, 1992. The Rate Agreement provides for the
recovery through rates, with a return, of the PSNH acquisition costs. The
unrecovered balance was $324.4 million and $352.9 million at December 31, 1999
and 1998, respectively, and is being recovered ratably over a 20-year period
ending May 1, 2011, in accordance with the Rate Agreement. Through
December 31, 1999 and 1998, $668 million and $640 million, respectively, has
been collected.
H. Regulatory Accounting and Assets
The accounting policies of the NU system operating companies and the
accompanying consolidated financial statements conform to generally accepted
accounting principles applicable to rate-regulated enterprises and historically
reflect the effects of the rate-making process in accordance with SFAS No. 71.
As a result of final restructuring orders issued in 1999, CL&P and WMECO
discontinued the application of SFAS No. 71 for the generation portion of
their businesses.
Based on a current evaluation of the various factors and conditions that are
expected to impact future cost recovery, management continues to believe it
is probable that the NU system operating companies will recover their
investments in long-lived assets, including regulatory assets. In addition,
all material regulatory assets are earning a return. The components
of the NU system companies' regulatory assets are as follows:
At December 31,
(Millions of Dollars) 1999 1998
Recoverable nuclear costs............. $2,210.8 $ 576.3
Income taxes, net..................... 636.6 762.5
Unrecovered contractual obligations... 349.2 408.0
Recoverable energy costs, net......... 228.2 279.2
Deferred costs - nuclear plants....... 111.6 187.1
Other................................. 106.0 115.8
-------- --------
$3,642.4 $2,328.9
======== ========
The restructuring orders in Connecticut and Massachusetts provide for the
transmission and distribution business to continue to be cost-of-service
based and also provide for a transition charge which recovers stranded
costs, including the nuclear regulatory assets established below.
As a result of discontinuing the application of SFAS No. 71 for CL&P's and
WMECO's generation businesses, the company reclassified nuclear plant in
excess of its estimated fair market value from plant to regulatory assets.
As of December 31, 1999, both the CL&P unamortized balance ($1.38 billion)
and the WMECO unamortized balance ($316.1 million) are classified as
recoverable nuclear costs. Also included in that regulatory asset component
for 1999 is $514.7 million, which includes Millstone 1 recoverable
nuclear costs relating to the recoverable portion of the undepreciated
plant and related assets ($145.7 million) and the decommissioning
and closure obligation ($369 million).
At this time, management continues to believe that the application of
SFAS No. 71 for PSNH and NAEC remains appropriate. If the "Agreement to
Settle PSNH Restructuring" (Settlement Agreement), as filed, is approved
by the New Hampshire Public Utilities Commission (NHPUC) and implemented,
then PSNH will discontinue the application of SFAS No. 71 for the generation
portion of its business and record an after-tax write-off of $225 million.
PSNH's transmission and distribution business will continue to be rate-
regulated on a cost-of-service basis as the Settlement Agreement allows for
the recovery of the remaining regulatory assets through that portion of the
business.
I. Income Taxes
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods
in which they affect the determination of taxable income) is accounted for in
accordance with the rate-making treatment of the applicable regulatory
commissions.
The tax effect of temporary differences, including timing differences accrued
under previously approved accounting standards, that give rise to the
accumulated deferred tax obligation is as follows:
At December 31,
(Millions of Dollars) 1999 1998
Accelerated depreciation and
other plant-related differences.......... $1,388.0 $1,537.9
Net operating loss carryforwards........... - (33.4)
Regulatory assets - income tax gross-up.... 241.2 370.0
Other...................................... 58.9 (25.8)
-------- ---------
$1,688.1 $1,848.7
======== =========
As of December 31, 1999 and 1998, PSNH had an Investment Tax Credit
carryforward of $23 million, which if unused, expires in 2004.
J. Recoverable Energy Costs
Energy Policy Act of 1992: Under the Energy Policy Act of 1992 (Energy Act),
CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of the
costs of decontaminating and decommissioning uranium enrichment plants owned
by the United States Department of Energy (DOE) (D&D Assessment). The Energy
Act requires that regulators treat D&D Assessments as a reasonable and
necessary current cost of fuel, to be fully recovered in rates like any other
fuel cost. CL&P, PSNH, WMECO, and NAEC are currently recovering these costs
through rates. As of December 31, 1999 and 1998, the NU system's total D&D
Assessment deferrals were $38.4 million and $57.5 million, respectively.
CL&P: Through December 31, 1999, CL&P had an energy adjustment clause under
which fuel prices above or below base-rate levels were charged to or credited
to customers. At December 31, 1999 and 1998, recoverable energy costs included
$62.6 million and $78.1 million, respectively, of costs previously deferred.
Coincident with the start of restructuring, the fuel clause was terminated.
The balance at December 31, 1999, has been recorded as a generation-related
stranded cost and will be recovered through a transition charge mechanism.
PSNH: The Rate Agreement includes a fuel and purchased-power adjustment clause
(FPPAC) permitting PSNH to pass through to retail customers, for a 10-year
period that began in May 1991, the retail portion of differences between the
fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual
costs, which include the costs related to the Seabrook Power Contracts and
the Clean Air Act Amendment. The cost components of the FPPAC are subject to
a prudence review by the NHPUC. At December 31, 1999 and 1998, PSNH had
$120.7 million and $156.3 million, respectively, of noncurrent recoverable
energy costs deferred under the FPPAC. If the Settlement Agreement is
approved, the FPPAC will be recovered through a transition charge.
K. Deferred Costs - Nuclear Plants
Under the Rate Agreement, the plant costs of Seabrook were phased into rates
over a 7-year period beginning May 15, 1991. Total costs deferred under the
phase-in plan were $288 million. This plan is accounted for in compliance with
SFAS No. 92, "Regulated Enterprises - Accounting for Phase-In Plans." The
costs will be fully recovered from PSNH's customers by May 2001.
L. Unrecovered Contractual Obligations
Under the terms of contracts with the Yankee Companies, the shareholder-
sponsored companies are responsible for their proportionate share of the
remaining costs of the units, including decommissioning. As management
expects that the NU system companies will be allowed to recover these costs
from their customers, the NU system companies have recorded regulatory
assets, with corresponding obligations, on their respective balance
sheets.
M. Interest Rate Risk Management Instruments
The NU system utilizes market risk management instruments to hedge well-defined
risks associated with variable interest rates. To qualify for hedge treatment,
the underlying hedged item must expose the company to risks associated with
market fluctuations and the market risk management instrument used must be
designated as a hedge and must reduce the NU system's exposure to market
fluctuations throughout the period. Amounts receivable or payable under
interest rate risk management instruments are accrued and offset against
interest expense.
N. Cash and Cash Equivalents
Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.
2. Nuclear Decommissioning and Plant Closure Costs
Millstone and Seabrook: The NU system operating nuclear power plants,
Millstone 2 and 3 and Seabrook, have service lives that are expected to end
during the years 2015 through 2026, and upon retirement, must be
decommissioned. Millstone 1's expected service life was to end in 2010,
however, in July 1998, restart activities were discontinued and preparations
for decommissioning the unit began. Current decommissioning studies conclude
that complete and immediate dismantlement as soon as practical after retirement
continues to be the most viable and economic method of decommissioning a unit.
These studies are reviewed and updated periodically to reflect changes in
decommissioning requirements, costs, technology, and inflation. Changes in
requirements or technology, the timing of funding or dismantling or adoption
of a decommissioning method other than immediate dismantlement would change
decommissioning cost estimates and the amounts required to be recovered.
CL&P, PSNH and WMECO attempt to recover sufficient amounts through their
allowed rates to cover their expected decommissioning costs.
The estimated cost of decommissioning Millstone 2, in year end 1999 dollars
is $413.4 million. The NU system's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook in year end 1999 dollars, is $421.3
million and $226.2 million, respectively. Nuclear decommissioning costs are
accrued over the expected service lives of the units and are included in
depreciation expense. Nuclear decommissioning expenses for these units
amounted to $30.6 million in 1999, $27.9 million in 1998 and $28.6 million
in 1997. Nuclear decommissioning, as a cost of removal, is included in the
accumulated provision for depreciation. Through December 31, 1999 and 1998,
total decommissioning expenses of $260.6 million and $229.7 million,
respectively, have been collected from customers and are reflected in the
accumulated provision for depreciation.
A Post-Shutdown Decommissioning Activities Report for Millstone 1 was filed
with the Nuclear Regulatory Commission (NRC) in June 1999 which outlines
decommissioning activities, and costs, and supports the obligation recorded
by the company. Nuclear decommissioning expenses for Millstone 1 were $25.7
million in 1999, $19.8 million in 1998 and $20.2 million in 1997.
External decommissioning trusts have been established for the costs of
decommissioning the Millstone units. Payments for the NU system's ownership
share of the cost of decommissioning Seabrook are paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assumes levelized collections
for the Millstone units and escalated collections for Seabrook and after-tax
earnings on the Millstone and Seabrook decommissioning funds of 5.5 percent
and 6.5 percent, respectively.
As of December 31, 1999 and 1998, CL&P, PSNH and WMECO collected a total of
$260.6 million and $229.7 million, respectively, through rates toward the
future decommissioning costs of their shares of Millstone 2 and 3 and
Seabrook, of which $239.7 million in 1999 and $209.9 million in 1998 have
been transferred to external decommissioning trusts. Earnings on the
decommissioning trusts increase the decommissioning trust balances and
the accumulated reserves for depreciation. Unrealized gains and losses
associated with the decommissioning trusts and financing funds also impact
the balance of the trusts and the accumulated reserve for depreciation.
The fair values of the amounts in the external decommissioning trusts were
$415.9 million and $349.9 million at December 31, 1999 and 1998, respectively.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. The NU system's ownership share
of estimated costs, in year end 1999 dollars, of decommissioning this unit is
$68.6 million. On October 15, 1999, VYNPC agreed to sell the unit for $22
million to an unaffiliated company. Among other commitments, the acquiring
company agreed to assume the decommissioning cost of the unit after it is
taken out of service, and the VYNPC owners have agreed to fund the uncollected
decommissioning cost to a negotiated amount at the time of the closing of the
sale.
As of December 31, 1999 and 1998, NU's remaining estimated obligation,
including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which
have been shut down was $358.4 million and $418.8 million, respectively.
3. Short-Term Debt
Limits: The amount of short-term borrowings that may be incurred by NU and the
NU system operating companies is subject to periodic approval by either the SEC
under the 1935 Act or by the respective state regulators. SEC authorization
allowed NU, CL&P, WMECO, and NAEC, as of January 1, 1999, to incur total
short-term borrowings up to a maximum of $400 million, $375 million, $250
million, and $60 million, respectively. In addition, the charters of CL&P and
WMECO contain preferred stock provisions restricting the amount of unsecured
debt those companies may incur. As of December 31, 1999, CL&P's and WMECO's
charters permit CL&P and WMECO to incur $322 million and $132 million,
respectively, of unsecured debt. PSNH is authorized under a NHPUC order to
incur short-term borrowings up to a maximum of $68.3 million.
Credit Agreements: On November 19, 1999, CL&P and WMECO entered into a new
364-day revolving credit facility for $500 million, replacing the previous
$313.75 million facility which was to expire on November 21, 1999. The
revolving credit facility will be used to bridge gaps in working capital and
provide short-term liquidity. CL&P and WMECO may draw up to $300 million and
$200 million, respectively, under the facility which is secured by second
mortgages on Millstone 2 and 3. Unless extended, the new credit facility will
expire on November 17, 2000. At December 31, 1999 and 1998, there were
$213 million and $30 million, respectively, in borrowings under these
facilities.
To support the working capital needs of NU and its unregulated subsidiaries,
NU replaced its $25 million 364-day revolving credit facility which was to
expire on November 21, 1999, with a new 364-day unsecured revolving credit
facility (NU Credit Agreement) on November 19, 1999. This new facility provides
a total commitment of $350 million which is available subject to two
overlapping sub-limits. First, subject to the notional amount of any letters
of credit outstanding, amounts up to $200 million are available for advances.
Second, subject to the advances outstanding, letters of credit may be issued in
notional amounts up to $250 million. Unless extended, this credit facility
will expire on November 17, 2000. As of December 31, 1999 and 1998, there
were $65 million and no borrowings under the NU Credit Agreement and the
previous credit facility, respectively. In regard to credit support, NU had
$29 million in letters of credit issued under this agreement as of
December 31, 1999.
In addition, NU provides credit assurance in the form of guarantees, letters
of credit, performance guarantees and other assurances for the financial
performance obligations of certain of its unregulated subsidiaries. NU
currently has authorization from the SEC to provide up to $500 million of
guarantees, but is limited under certain loan agreements to $350 million of
such arrangements without creditor approval. As of December 31, 1999, NU had
provided approximately $190 million of such credit assurances.
Under the credit agreements discussed above, the respective borrowers may
borrow at fixed or variable rates plus an applicable margin based upon the
companies' most senior secured debt as rated by the lower of Standard and
Poor's or Moody's Investors Service (Moody's). The weighted average interest
rate on the NU system companies' notes payable to banks outstanding on
December 31, 1999 and 1998, was 7.928 percent and 6.53 percent, respectively.
Maturities of short-term debt obligations were for periods of three months
or less.
These credit agreements provide that the parties to these agreements must
comply with certain financial and nonfinancial covenants as are customarily
included in such agreements, including, but not limited to, common equity
ratios, interest coverage ratios and dividend payment restrictions.
4. Leases
CL&P and WMECO finance their nuclear fuel for Millstone 2 and their respective
shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust
(NBFT) capital lease agreement. This capital lease agreement has an expiration
date of June 1, 2040. At December 31, 1999 and 1998, the present value of the
capital lease obligation to the NBFT was $157 million and $178.7 million,
respectively. In connection with the planned nuclear divestiture, CL&P and
WMECO anticipate that the NBFT capital lease agreement will be terminated and
the NBFT's obligation under the $180 million Series G Intermediate Term Note
agreement will be assigned to CL&P and WMECO.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates which
reflect estimated kilowatt-hours of energy provided plus financing costs
associated with the fuel in the reactors. Upon permanent discharge from the
reactors, ownership of the nuclear fuel transfers to CL&P and WMECO.
The NU system companies also have entered into lease agreements, some of
which are capital leases, for the use of data processing and office equipment,
vehicles, nuclear control room simulators, and office space. The provisions
of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $20.8 million
in 1999, $31 million in 1998 and $19 million in 1997. Interest included in
capital lease rental payments was $13.7 million in 1999, $18.3 million in 1998
and $13.6 million in 1997. Operating lease rental payments charged to expense
were $7.5 million in 1999, $15.7 million in 1998 and $17.3 million in 1997.
Future minimum rental payments, excluding annual nuclear fuel lease payments
and executory costs, such as property taxes, state use taxes, insurance and
maintenance, under long-term noncancelable leases, as of December 31, 1999
are:
(Millions of Dollars)
Year Capital Leases Operating Leases
2000............................... $ 7.4 $ 24.4
2001............................... 4.9 22.6
2002............................... 3.1 19.0
2003............................... 3.1 15.5
2004............................... 3.0 13.6
After 2004......................... 30.6 26.9
------ -------
Future minimum lease payments...... 52.1 $ 122.0
=======
Less amount representing interest.. 27.8
------
Present value of future minimum
lease payments for other than
nuclear fuel..................... 24.3
Present value of future nuclear
fuel lease payments.............. 157.0
------
Present value of future
minimum lease payments........... $181.3
======
5. Employee Benefits
A. Pension Benefits and Postretirement Benefits Other Than Pensions
The NU system companies participate in a uniform noncontributory defined
benefit retirement plan covering substantially all regular NU system
employees. Benefits are based on years of service and the employees' highest
eligible compensation during 60 consecutive months of employment. The total
pension credit, part of which was credited to utility plant, was $54.4 million
in 1999, $44.1 million in 1998 and $22.5 million in 1997.
Currently, the NU system companies annually fund an amount at least equal to
that which will satisfy the requirements of the Employee Retirement Income
Security Act and Internal Revenue Code (the Code).
The NU system companies also provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees. These benefits are available for employees retiring from
the NU system who have met specified service requirements. For current
employees and certain retirees, the total benefit is limited to two times
the 1993 per retiree health care cost. These costs are charged to expense
over the future estimated work life of the employee. The NU system companies
annually fund postretirement costs through external trusts with amounts that
have been rate-recovered and which also are tax deductible under the Code.
Pension and trust assets are invested primarily in domestic and international
equity securities and bonds.
The following table represents information on the plans' benefit obligation,
fair value of plan assets, and the respective plans' funded status:
At December 31,
Pension Benefits Postretirement Benefits
(Millions of Dollars) 1999 1998 1999 1998
Change in benefit obligation
Benefit obligation at
beginning of year............$(1,479.2) $(1,392.8) $(305.2) $(286.0)
Service cost................... (43.7) (37.4) (7.6) (6.6)
Interest cost.................. (106.3) (96.8) (21.8) (20.9)
Plan amendment................. (79.6) - - -
Transfers...................... - 8.5 - -
Actuarial gain/(loss).......... 133.8 (37.7) (1.3) (16.1)
Benefits paid.................. 78.3 77.0 28.9 24.4
Settlements.................... (19.9) - 0.2 -
---------- ---------- -------- --------
Benefit obligation at
end of year..................$(1,516.6) $(1,479.2) $(306.8) $(305.2)
========== ========== ======== ========
Change in plan assets
Fair value of plan assets at
beginning of year............$ 2,098.0 $ 1,919.4 $ 151.2 $ 129.4
Actual return on plan assets... 310.5 264.7 18.7 17.4
Employer contribution.......... - - 29.7 28.8
Benefits paid.................. (78.3) (77.0) (28.9) (24.4)
Transfers...................... - (9.1) - -
---------- ---------- -------- --------
Fair value of plan assets at
end of year..................$ 2,330.2 $ 2,098.0 $ 170.7 $ 151.2
========== ========== ======== ========
Funded status at December 31...$ 813.6 $ 618.8 $(136.1) $(154.0)
Unrecognized transition
(asset)/obligation........... (7.4) (9.0) 196.6 211.9
Unrecognized prior service
cost......................... 99.2 27.6 - -
Unrecognized net gain.......... (904.7) (670.4) (60.4) (57.9)
---------- ---------- -------- --------
Prepaid/(accrued) benefit cost.$ 0.7 $ (33.0) $ 0.1 $ -
========== ========== ======== ========
The following actuarial assumptions were used in calculating the plans' year
end funded status:
At December 31,
Pension Benefits Postretirement Benefits
1999 1998 1999 1998
Discount rate................... 7.75% 7.00% 7.75% 7.00%
Compensation/progression rate... 4.75 4.25 4.75 4.25
Health care cost trend rate (a). N/A N/A 5.57 5.22
(a) The annual per capita cost of covered health care benefits was assumed to
decrease to 4.9 percent by 2001.
The components of net periodic benefit cost are:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
(Millions of Dollars) 1999 1998 1997 1999 1998 1997
Service cost............ $ 43.7 $ 37.4 $ 34.9 $ 7.6 $ 6.6 $ 5.7
Interest cost........... 106.3 96.8 98.6 21.8 20.9 20.6
Expected return on
plan assets........... (175.5) (153.2) (135.1) (11.7) (9.9) (8.1)
Amortization of
unrecognized net
transition (asset)/
obligation............ (1.5) (1.5) (1.5) 15.1 15.1 15.1
Amortization of prior
service cost.......... 7.9 2.1 2.1 - - -
Amortization of
actuarial gain........ (33.5) (25.7) (18.9) - - -
Other amortization, net. - - - (3.1) (3.8) (5.0)
Settlements............. (1.8) - (2.6) - - -
------- -------- -------- ------- ------ -------
Net periodic benefit
(credit)/cost........ $(54.4) $ (44.1) $ (22.5) $ 29.7 $28.9 $ 28.3
======= ======== ======== ======= ====== =======
For calculating pension and postretirement benefit costs, the following
assumptions were used:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
1999 1998 1997 1999 1998 1997
Discount rate........... 7.00% 7.25% 7.75% 7.00% 7.25% 7.75%
Expected long-term
rate of return........ 9.50 9.50 9.25 N/A N/A N/A
Compensation/
progression rate...... 4.25 4.25 4.75 4.25 4.25 4.75
Long-term rate
of return -
Health assets,
net of tax........ N/A N/A N/A 7.50 7.75 7.50
Life assets......... N/A N/A N/A 9.50 9.50 9.25
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. The effect of changing the assumed health
care cost trend rate by one percentage point in each year would have the
following effects:
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
Effect on total service and
interest cost components......... $ 1.4 $ (1.4)
Effect on postretirement
benefit obligation............... $16.4 $(16.1)
The trust holding the health plan assets is subject to federal income taxes.
B. 401(k) Savings Plan
NU maintains a 401(k) Savings Plan for substantially all NU system employees.
This savings plan provides for employee contributions up to specified limits.
NU matches employee contributions up to a maximum of 3 percent of eligible
compensation with cash and NU stock. The matching contributions made by NU
were $13.8 million for 1999, $13.2 million for 1998 and $12 million for 1997.
C. ESOP
NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating
shares to employees participating in the NU system's 401(k) Savings Plan.
Under this arrangement, NU issued unsecured notes during 1991 and 1992
totaling $250 million, the proceeds of which were lent to the ESOP trust for
the purchase of 10.8 million newly issued NU common shares (ESOP Shares). The
ESOP trust is obligated to make principal and interest payments on the ESOP
notes at the same rate that ESOP Shares are allocated to employees. NU makes
annual contributions to the ESOP equal to the ESOP's debt service, less
dividends received by the ESOP. All dividends received by the ESOP on
unallocated shares are used to pay debt service and are not considered
dividends for financial reporting purposes. During the fourth quarter of
1999, NU paid a 10 cent per share dividend. During 1998, there were no
dividends paid on NU stock.
In 1999 and 1998, the ESOP trust issued 556,978 and 584,107 of NU common
shares, respectively, to satisfy 401(k) Savings Plan obligations to employees.
As of December 31, 1999 and 1998, the total allocated ESOP shares were
5,281,836 and 4,724,858, respectively, and total unallocated ESOP shares were
5,518,349 and 6,075,327, respectively. The fair market value of unallocated
ESOP shares as of December 31, 1999 and 1998, was $113.5 million and $97.2
million, respectively.
D. Stock-Based Compensation
Employee Stock Purchase Plan (ESPP): Since July 1998, the NU system has
maintained an ESPP for all eligible employees. Under the ESPP, shares of NU
common stock may be purchased at 6-month intervals at 85 percent of the lower
of the price on the first or last day of each 6-month period. Employees may
purchase shares having a value not exceeding 25 percent of their compensation
at the beginning of the purchase period. During 1999 and 1998, employees
purchased 253,853 and 129,471 shares, respectively, at discounted prices
ranging from $13.76 to $14.93 per share in 1999 and $13.60 per share in 1998.
At December 31, 1999 and 1998, 1,616,676 and 1,870,529 shares remained reserved
for future issuance under the ESPP, respectively.
Incentive Plans: The NU system has long-term incentive plans authorizing
various types of share-based awards, including stock options, to be made to
eligible employees and board members. The exercise price of stock options,
as set at the time of grant, is equal to the fair market value per share at
the date of grant. Under the Northeast Utilities Incentive Plan (Incentive
Plan), the number of shares which may be utilized for awards granted during
a given calendar year may not exceed one percent of the total number of
shares of NU common stock outstanding as of the first day of that calendar
year.
Stock option transactions for 1997, 1998 and 1999 are as follows:
Exercise Price Per Share
Weighted
Options Range Average
Outstanding December 31, 1996... - $ - $ -
Granted......................... 500,000 $9.625 $ 9.625
----------
Outstanding December 31, 1997... 500,000 $9.625 $ 9.625
Granted......................... 741,273 $14.875 - $16.8125 $16.178
Forfeited....................... (7,595) $16.3125 $16.3125
----------
Outstanding December 31, 1998... 1,233,678 $ 9.625 - $16.8125 $13.5213
Granted......................... 644,123 $14.9375 - $21.125 $15.2514
Exercised....................... (19,368) $16.3125 - $16.8125 $16.3986
Forfeited....................... (32,177) $14.9375 - $16.3125 $15.8714
----------
Outstanding December 31, 1999... 1,826,256 $ 9.625 - $21.125 $14.0585
==========
Exercisable December 31, 1997... - $ - $ -
Exercisable December 31, 1998... 232,936 $14.875 - $16.8125 $16.2972
Exercisable December 31, 1999... 711,787 $ 9.625 - $21.125 $14.0102
The vesting schedule for the options granted in 1997 is 50 percent after
two years, 75 percent after three years and the total award after four years.
The vesting schedule for the options granted in 1998 is one-third upon grant,
two-thirds after one year and the total award after two years. The options
that were granted in 1999 vest ratably over three years from the date of grant.
Also under the Incentive Plan, the NU system awarded 91,120 and 49,973 of
restricted shares in 1999 and 1998, respectively. These shares have the same
vesting schedule as the options granted under the Incentive Plan. During 1997,
certain key officers were awarded restricted stock totaling 25,700 shares which
vest ratably over three years from the date of grant. The NU system has also
made several small grants of restricted stock and other incentive-based stock
compensation. During 1999, 1998 and 1997, $2.2 million, $0.8 million and
$0.3 million, respectively, was expensed for stock-based compensation.
Had compensation cost been determined for the ESPP and the incentive plan stock
options under the fair value method as opposed to the intrinsic value method
followed by the NU system, net income/(loss) and net income/(loss) per share
would have been as follows:
(Millions of Dollars,
except per share amounts) 1999 1998 1997
Net income/(loss)....................... $29.6 $(149.1) $(130.0)
Basic income/(loss) per share........... $0.23 $ (1.14) $ (1.01)
Diluted income/(loss) per share......... $0.22 $ (1.14) $ (1.01)
The fair value of each stock option grant has been estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions:
1999 1998 1997
Risk-free interest rate................. 5.69% 5.82% 6.41%
Expected life........................... 10 years 10 years 10 years
Expected volatility..................... 36.21% 35.05% 31.89%
Expected dividend yield................. 1.89% 5.46% 7.42%
The weighted average grant date fair values of options granted during 1999,
1998 and 1997 were $6.79, $3.98 and $1.68, respectively. As of December 31,
1999, the weighted average remaining contractual life for those options
outstanding is 8.47 years.
6. Sale of Customer Receivables
As of December 31, 1999 and 1998, CL&P had sold accounts receivable of $170
million and $105 million, respectively, to a third-party purchaser with limited
recourse through the CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. In addition, at December 31, 1999 and 1998, $22.5 million
and $11.6 million, respectively, of assets was designated as collateral under
the agreement with CRC.
On June 30, 1999, WMECO terminated its $40 million accounts receivable program
with its respective sponsor. At December 31, 1998, WMECO had sold accounts
receivable of $20 million to a third-party purchaser.
Concentrations of credit risk to the purchaser under the company's agreement
with respect to the receivables are limited due to CL&P's diverse customer base
within its service territory.
7. Commitments and Contingencies
A. Restructuring
Connecticut: During 1999, restructuring orders were issued by the DPUC which
required CL&P to discontinue the application of SFAS No. 71 to the generation
portion of its business and allowed for the recovery of the majority of its
stranded costs. Stranded costs including regulatory assets will be collected
through a transition charge through 2026. The restructuring orders also
allowed for securitization of CL&P's nonnuclear regulatory assets and the
costs to buyout or buydown the various purchased-power contracts.
Securitization is the process of monetizing stranded costs through the sale
of nonrecourse debt securities by a special purpose entity, collateralized by
CL&P's interests in its stranded cost recoveries.
On December 15, 1999, the DPUC issued a supplemental decision approving the
components of CL&P's rates for standard offer service commencing on January 1,
2000. The DPUC also approved an interim nuclear capital recovery mechanism for
the period from January 1, 2000, until the nuclear units are sold at auction.
In approving the rates, the DPUC denied recovery of most of the capital
additions made to Millstone 2 and 3 subsequent to June 30, 1997, which the
company has or will expend to maintain those plants in a safe and efficient
condition or to maintain their auction value. If implemented as approved, the
company would not recover a significant portion of the capital additions which
have been or are expected to be incurred subsequent to July 1, 1997, until the
plants are sold in 2001. On December 29, 1999, CL&P filed with the DPUC a
petition for reconsideration of this portion of the order. The DPUC has agreed
to reopen the docket to consider CL&P's petition. Management believes the
restructuring legislation provides for the recovery of these prudently incurred
expenditures. If CL&P is unsuccessful in favorably resolving this contingency,
an impairment loss of $50 million would be recorded.
Massachusetts: In 1999, restructuring orders required WMECO to discontinue the
application of SFAS No. 71 for the generation portion of its business. In
these restructuring orders, WMECO was allowed to recover the majority of its
stranded costs through a transition charge over the 12-year transition period
beginning March 1, 1998. The decision instructed WMECO to work with the
Massachusetts attorney general regarding the recovery of nuclear capital
additions made after July 1, 1991. The decision also concluded that the
company's deferred fuel balance should be included as part of the company's
outstanding generating unit performance proceedings and not as part of the
transition charge. Management believes that these costs are recoverable and
that there will not be an impact on the results of operations.
Nuclear Generation Assets Auction: In September 1999, NU announced that the
Millstone nuclear generation assets of CL&P and WMECO will be put up for
auction as soon as practical. On November 8, 1999, CL&P filed its divestiture
plan for the Millstone units with the DPUC. The auction is expected to begin
in early 2000, provided all regulatory approvals have been met, with a
successful bidder chosen by mid 2000 and a closing in 2001. No NU system
company will participate as a bidder in the auction process. Management
expects to recover all of its nuclear stranded costs through the net proceeds
of generation asset sales and through billing a transition charge to retail
customers.
New Hampshire: In August 1999, NU, PSNH and the state of New Hampshire signed
a Settlement Agreement intended to settle a number of pending regulatory and
court proceedings related to PSNH. Parties to the agreement included the
governor of New Hampshire, the Governor's Office of Energy and Community
Service, the New Hampshire attorney general, certain members of the staff of
the NHPUC, PSNH and NU. The Settlement Agreement was submitted to the NHPUC
on August 2, 1999, and is awaiting approval. If approved by the NHPUC, the
Settlement Agreement would resolve 11 NHPUC dockets and PSNH's federal lawsuit
which had enjoined the state of New Hampshire from implementing its
restructuring legislation, would require PSNH to write off $225 million after-
tax of its stranded costs and would allow for the recovery of the remaining
amount. Also, implementation of the Settlement Agreement is contingent upon
the issuance of $725 million in rate reduction bonds (securitization).
Issuance of the rate reduction bonds requires the initial approval of the NHPUC
and final approval from the New Hampshire Legislature via enactment of
appropriate legislation. Other approvals are also required from various
federal and state regulatory agencies and financial lenders. Under the terms
of the Settlement Agreement, on the effective date, PSNH's rates will be
reduced from current levels by an average of 18.3 percent. Due to the number
of approvals required and still pending to implement the Settlement Agreement,
management continues to believe the application of SFAS No. 71 is appropriate
for PSNH at this time.
The Settlement Agreement also requires PSNH to sell its generation assets and
certain power contracts, including PSNH's current purchased-power contract with
NAEC for the output from Seabrook. The net proceeds from all sales will be
used to recover a portion of PSNH's stranded costs. The sales would be
accomplished through an auction process subject to approval by the NHPUC.
Following the divestiture, the transmission and distribution portion of the
business will continue to be cost-of-service based.
Phase I of the proceeding regarding the Settlement Agreement allowed proponents
to provide sufficient record for the NHPUC to compare the Settlement Agreement
to a range of reasonable outcomes in the other associated dockets. The NHPUC
also determined within the testimony of Phase I that the Con Edison merger is
relevant to the Settlement Agreement and intervening parties should have
discovery in Phase II to evaluate the impact of the merger on the Settlement
Agreement. Phase II allowed opponents to file testimony concerning the
Settlement Agreement and then allowed proponents to conduct discovery and file
rebuttal testimony. A decision on the Settlement Agreement is expected in the
first quarter of 2000.
B. Nuclear Litigation
The non-NU joint owners of Millstone 3 have filed demands for arbitration with
CL&P, WMECO and PSNH as well as lawsuits in Massachusetts Superior Court
against NU and its current and former trustees related to the companies'
operation of Millstone 3. During 1999, NU and these subsidiaries agreed in
principle to settle with certain of the joint owners, who own 58 percent of the
non-NU ownership of Millstone 3. The settlements provide for the payment
to the claimants of $36.4 million and certain contingent payments.
Arbitration and litigation claims remain outstanding for the remaining joint
owners who have not agreed to settle. Management cannot estimate the potential
outcome of the arbitration and litigation for the nonsettled joint owners,
therefore, no liability has been established as of December 31, 1999.
C. Environmental Matters
The NU system is subject to environmental laws and regulations intended to
mitigate or remove the effect of past operations and improve or maintain the
quality of our environment. As such, the NU system has an active environmental
auditing and training program and believes it is in compliance with the current
laws and regulations.
However, the normal course of operations may necessarily involve activities and
substances that expose the NU system to potential liabilities of which
management cannot determine the outcome. Additionally, management cannot
determine the outcome for liabilities that may be imposed for past acts, even
though such past acts may have been lawful at the time they occurred.
Management does not believe, however, that this will have a material impact
on the NU system's financial statements.
Based upon currently available information for the estimated remediation costs
as of December 31, 1999 and 1998, the liability recorded by the NU system for
its estimated environmental remediation costs amounted to $24.8 million and
$21.5 million, respectively.
D. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must
pay the DOE for the disposal of spent nuclear fuel and high-level radioactive
waste. The DOE is responsible for the selection and development of
repositories for, and the disposal of, spent nuclear fuel and high-level
radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983,
are billed currently to customers and paid to the DOE on a quarterly basis.
For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior
Period Fuel), an accrual has been recorded for the full liability and payment
must be made prior to the first delivery of spent fuel to the DOE. Until such
payment is made, the outstanding balance will continue to accrue interest at
the 3-month treasury bill yield rate. As of December 31, 1999 and 1998,
fees due to the DOE for the disposal of Prior Period Fuel were $226.5 million
and $216.4 million, respectively, including interest costs of $144.3 million
and $134 million, respectively.
E. Nuclear Insurance Contingencies
Insurance policies covering the NU system's nuclear facilities have been
purchased for the primary cost of repair, replacement or decontamination of
utility property, certain extra costs incurred in obtaining replacement power
during prolonged accidental outages and the excess cost of repair, replacement
or decontamination or premature decommissioning of utility property.
The NU system is subject to retroactive assessments if losses under those
policies exceed the accumulated funds available to the insurer. The maximum
potential assessments with respect to losses arising during the current
policy year for the primary property insurance program, the replacement power
policies and the excess property damage policies are $11 million, $6.2 million
and $15 million, respectively. In addition, insurance has been purchased in
the aggregate amount of $200 million on an industry basis for coverage of
worker claims.
Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities covered by the federal government's third-party liability
indemnification program, the NU system could be assessed liabilities in
proportion to its ownership interest in each of its nuclear units up to $83.9
million. The NU system's payment of this assessment would be limited to, in
proportion to its ownership interest in each of its nuclear units, $10 million
in any one year per nuclear unit. In addition, if the sum of all claims and
costs from any one nuclear incident exceeds the maximum amount of financial
protection, the NU system would be subject to an additional 5 percent or $4.2
million liability, in proportion to its ownership interests in each of its
nuclear units. Based upon its ownership interests in the Millstone units and
in Seabrook, the NU system's maximum liability, including any additional
assessments, would be $271 million per incident, of which payments would be
limited to $30.8 million per year. In addition, through purchased-power
contracts with VYNPC, the NU system would be responsible for up to an
additional assessment of $14.1 million per incident, of which payments would
be limited to $1.6 million per year.
F. Construction Program
The NU system companies currently forecast construction expenditures of $1.8
billion for the years 2000-2004, including $309.7 million for 2000. The NU
system companies estimate that nuclear fuel requirements, including nuclear
fuel financed through the NBFT, will be $217.8 million for the years 2000-2003,
including $74.2 million for 2000.
G. Long-Term Contractual Arrangements
Yankee Companies: The NU system companies relied on VYNPC for 1.5 percent of
their capacity under long-term contracts. Under the terms of their agreements,
the NU system companies paid their ownership (or entitlement) shares of costs,
which included depreciation, operation and maintenance (O&M) expenses, taxes,
the estimated cost of decommissioning, and a return on invested capital.
These costs were recorded as purchased-power expenses and recovered through
the companies' rates. The total cost of purchases under contracts with VYNPC
amounted to $29.2 million in 1999, $27.3 million in 1998 and $24.2 million in
1997. VYNPC has agreed to sell its nuclear unit. Upon completion of the
sale, this long-term contract will be terminated.
Nonutility Generators (NUGs): CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from NUGs. For the years
ended December 31, 1999 and 1998, 13 percent and for the year ended
December 31, 1997, 14 percent, of NU system electricity requirements were met
by NUGs. The total cost of purchases under these arrangements amounted to
$461.8 million in 1999, $459.7 million in 1998 and $447.6 million in 1997.
The company is in the process of renegotiating the terms of these contracts
through either a contract buydown or buyout. The company expects any payments
to the NUGs as a result of these renegotiations to be recovered from the
company's customers.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and
HWP have entered into agreements to support transmission and terminal
facilities to import electricity from the Hydro-Quebec system in Canada.
CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending
in 2020, their proportionate shares of the annual O&M expenses and capital
costs of those facilities.
New Hampshire Electric Cooperative (NHEC): Previously, PSNH entered into a
buy-back agreement to purchase the capacity and energy of the NHEC share of
Seabrook and to pay all of NHEC's Seabrook costs for a 10-year period, which
began on July 1, 1990. The total cost of purchases under this agreement was
$33 million in 1999, $29.7 million in 1998 and $23.4 million in 1997. These
costs are recoverable through the FPPAC. Effective January 1, 2000, the
buy-back agreement was terminated.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements, absent the effects of any
contract terminations or buydowns are as follows:
(Millions of Dollars) 2000 2001 2002 2003 2004
VYNPC....................... $ 24.1 $ 21.8 $ 21.9 $ 21.5 $ 21.0
NUGs........................ 472.6 480.2 489.2 500.1 487.3
Hydro-Quebec................ 31.3 30.3 29.6 28.7 27.8
Select Energy: Select Energy maintains long-term agreements to purchase both
wholesale and retail energy in the normal course of business. The notional
amount of these purchase contracts is $3.1 billion at December 31, 1999.
These contracts extend through 2004 as follows:
(Millions of Dollars)
Year
2000...................... $1,271
2001...................... 638
2002...................... 573
2003...................... 499
2004...................... 101
------
Total $3,082
======
H. New England Power Pool (NEPOOL) Generation Pricing
Disputes with respect to interpretation and implementation of the NEPOOL market
rules have arisen with respect to various competitive product markets. In
certain cases, Select Energy and the NU operating companies stand to gain as
a result of resolution of such disputes. In other cases, Select Energy and
the NU operating companies could incur additional costs as the result of
resolution of the disputes. The various disputes are in various stages of
resolution through alternative dispute resolution and regulatory review.
It is too early to tell the level of potential gain or loss that may result
upon resolution of these issues.
8. Market Risk and Risk Management Instruments
Interest Rate Risk Management: NAEC uses swap instruments with financial
institutions to hedge against interest rate risk associated with its $200
million variable-rate bank note. Under the agreements, NAEC exchanges
quarterly payments based on a differential between a fixed contractual interest
rate and the 3-month LIBOR rate at a given time. As of December 31, 1999 and
1998, NAEC had outstanding agreements with a total notional value of $200
million and mark-to-market positions of positive $0.5 million and negative
$2.3 million, respectively.
Energy Price Risk Management: Beginning in 1997 through 1999, CL&P used swap
instruments with financial institutions to hedge the energy price risk created
by long-term negotiated energy contracts. These agreements were intended to
minimize exposure associated with rising fuel prices by managing a portion of
CL&P's cost of producing power for these negotiated energy contracts.
In 1999, CL&P divested substantially all of its fossil and hydroelectric
generation assets and agreed to transfer the rights and obligations related
to the long-term negotiated energy contracts to an unregulated affiliate.
Accordingly, the fuel swap positions were marked-to-market and CL&P recognized
a loss of $5.2 million. In January 2000, the fuel swap positions were
liquidated.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating group.
NAEC is exposed to credit risk on its respective market risk management
instruments if the counterparties fail to perform their obligations.
Management anticipates that the counterparties will fully satisfy their
obligations under the agreements.
Unregulated Energy Services Market Risk: NU's unregulated companies, as major
providers of electricity and natural gas, have certain market risks inherent in
their business activities. Market risk represents the risk of loss that may
impact the companies' financial position, results of operations or cash flows
due to adverse changes in commodity market prices. In 1999, the companies
increased their volume of electricity and gas marketing activities,
increasing their risks. Policies and procedures have been established to
manage these exposures including the use of risk management instruments.
9. Minority Interest in Consolidated Subsidiary
CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A. CL&P has the sole ownership interest in CL&P LP, as a general
partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS
issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's
$3.1 million capital contribution, back to CL&P in the form of an unsecured
debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon
consolidation, the unsecured debenture is eliminated, and the MIPS securities
are accounted for as a minority interest.
10. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash and cash equivalents: The carrying amounts approximate fair value due
to the short-term nature of cash and cash equivalents.
Supplemental Executive Retirement Plan (SERP) Investments: Investments held
for the benefit of the SERP are recorded at fair market value. The investments
having a cost basis of $5.8 million and $5.4 million held for benefit of the
SERP were recorded at their fair market values at December 31, 1999 and 1998
of $9.2 million and $8.7 million, respectively.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were marked-to-market by $129 million
as of December 31, 1999, and $110.4 million as of December 31, 1998, with
corresponding offsets to the accumulated provision for depreciation. The
amounts adjusted in 1999 and 1998 represent cumulative net unrealized gains.
The cumulative gross unrealized holding losses were immaterial for both
1999 and 1998.
Preferred stock and long-term debt: The fair value of the NU system's fixed-
rate securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair value
equal to their carrying value. The carrying amounts of the NU system's
financial instruments and the estimated fair values are as follows:
At December 31, 1999
Carrying Fair
(Millions of Dollars) Amount Value
Preferred stock not subject
to mandatory redemption................... $ 136.2 $ 164.0
Preferred stock subject to
mandatory redemption...................... 167.5 166.8
Long-term debt -
First mortgage bonds...................... 1,193.2 1,209.5
Other long-term debt...................... 1,638.3 1,430.1
MIPS........................................ 100.0 97.3
At December 31, 1998
Carrying Fair
(Millions of Dollars) Amount Value
Preferred stock not subject
to mandatory redemption................... $ 136.2 $ 97.0
Preferred stock subject to
mandatory redemption...................... 213.8 205.9
Long-term debt -
First mortgage bonds...................... 1,984.0 2,003.6
Other long-term debt...................... 1,654.9 1,682.7
MIPS........................................ 100.0 102.0
11. Other Comprehensive Income
The accumulated balance for each other comprehensive income item is as follows:
Current
December 31, Period December 31,
1998 Change 1999
(Thousands of Dollars)
Foreign currency
translation adjustments........ $ (1) $ 1 $ -
Unrealized gains on securities... 2,019 118 2,137
Minimum pension liability
adjustment..................... (613) - (613)
------- ---- -------
Accumulated other
comprehensive income........... $1,405 $119 $1,524
======= ==== =======
Current
December 31, Period December 31,
1997 Change 1998
(Thousands of Dollars)
Foreign currency
translation adjustments........ $ (1) $ - $ (1)
Unrealized gains on securities... - 2,019 2,019
Minimum pension liability
adjustment..................... - (613) (613)
------- ------- -------
Accumulated other
comprehensive income........... $ (1) $1,406 $1,405
======= ======= =======
The changes in the components of other comprehensive income are reported net
of the following income tax effects:
1999 1998 1997
(Thousands of Dollars)
Foreign currency translation
adjustments........................... $ - $ - $359
Unrealized gains on securities.......... (71) (1,222) -
Minimum pension liability
adjustment............................ - 398 -
----- -------- ----
Other comprehensive income.............. $(71) $ (824) $359
===== ======== ====
12. Earnings Per Share
Earnings per share (EPS) is computed based upon the weighted average number
of common shares outstanding during each year. Diluted earnings per share is
computed on the basis of the weighted average number of common shares
outstanding plus the potential dilutive effect if certain securities are
converted into common stock.
The following table sets forth the components of basic and diluted EPS:
(Millions of Dollars,
except share information) 1999 1998 1997
Income/(loss) after
interest charges................ $57.0 $(120.4) $ (99.7)
Preferred dividends
of subsidiaries................. 22.8 26.4 30.3
----------- ------------ ------------
Net income/(loss)................. $34.2 $(146.8) $(130.0)
=========== ============ ============
Basic EPS common
shares outstanding (average)..... 131,415,126 130,549,760 129,567,708
Dilutive effect of
employee stock options.......... 616,447 - (a) - (a)
----------- ------------ ------------
Diluted EPS common shares
outstanding (average)........... 132,031,573 130,549,760 129,567,708
=========== ============ ============
Basic earnings/(loss) per share... $0.26 $(1.12) $(1.01)
Diluted earnings/(loss) per share. $0.26 $(1.12) $(1.01)
(a) The addition of dilutive potential common shares would be anti-dilutive
for 1998 and 1997 and was not included.
13. Mode 1
In August 1998, NorthEast Optic Network, Inc. (NEON) issued 4,000,000 new
common shares on the open market in an initial public offering (IPO). The IPO
had the effect of decreasing Mode 1's ownership interest in NEON from 40.78
percent to 30.74 percent. The shares were issued at an amount greater than
Mode 1's investment, resulting in a $13.7 million pretax increase to Mode 1's
equity. NU's accounting policy is to recognize the gain or loss from this type
of change in ownership interest in net income. However, as a result of the
startup nature of NEON's operations, this change in ownership interest was
recognized in additional paid in capital.
In conjunction with the IPO, Mode 1 sold 217,997 NEON shares, resulting in a
pretax gain of $1.7 million and further reducing its ownership interest to
29.4 percent of the outstanding common shares of NEON.
On November 23, 1999, NEON entered into two agreements with unaffiliated
companies. Under the agreements, NEON will provide network transport and
carrier services among the service areas of NEON and the two unaffiliated
companies and each company will provide connectivity from the backbone system
to their respective local loops. Additionally, each company will manage their
local distribution into their respective end-users' locations. NEON will
also develop, operate and market the combined telecommunications infrastructure
created under the two agreements.
As the agreements are implemented, the two unaffiliated companies will
ultimately obtain 10.75 percent and 9.25 percent ownership interests,
respectively, in NEON and will each nominate one member to the NEON Board of
Directors. The agreements are subject to regulatory approvals, which are
expected by the spring of 2000.
14. Segment Information
Effective January 1, 1999, the NU system companies adopted SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information."
The NU system is organized between regulated utilities and unregulated energy
services.
The regulated utilities segment represents 87 percent of the NU system's total
revenue and is comprised of several business units including generation,
transmission and distribution.
The unregulated energy services segment in the following table includes NGC,
NGS, Select Energy and HEC.
Other in the following table includes the results for Mode 1. Mode 1 had a net
loss of $4.3 million for the year ended December 31, 1999. Interest expense
included in Other primarily relates to the debt of NU parent. Inter-segment
eliminations of revenues and expenses are also included in Other.
Regulated utilities revenues primarily are derived from residential, commercial
and industrial customers and are not dependent on any single customer. The
unregulated energy services segment has a major customer whose purchases
represented 46 percent of its total revenues for the year ended December 31,
1999.
For the Year Ended December 31, 1999
Unregulated
Regulated Energy
(Millions of Dollars) Utilities Services Other Total
Operating revenues $3,888.7 $606.3 $(23.7) $4,471.3
Operating expenses (3,495.9) (646.7) 15.9 (4,126.7)
--------- ------- ------- ---------
Operating income/(loss) 392.8 (40.4) (7.8) 344.6
Other (loss)/income (36.4) (1.2) 13.7 (23.9)
Interest expense (247.8) (1.0) (14.9) (263.7)
Preferred dividends (22.8) - - (22.8)
--------- ------- ------- ---------
Net income/(loss) $ 85.8 $(42.6) $ (9.0) $ 34.2
========= ======= ======= =========
Total assets $9,388.3 $222.5 $ 77.3 $9,688.1
========= ======= ======= =========
Prior to 1999, the NU system evaluated management performance using a cost-
based budget, therefore business segment reporting on a comparative basis will
not be available until the year 2000.
15. Merger Agreement with Con Edison
On October 13, 1999, NU and Con Edison announced that they have agreed to a
merger to combine the two companies. The shareholders of NU will receive $25
per share in a combination of cash and Con Edison common stock.
NU shareholders also have the right to receive an additional $1 per share if a
definitive agreement to sell its interests (other than that now held by PSNH)
in Millstone 2 and 3 is entered into and recommended by the Utility Operations
and Management Unit of the DPUC on or prior to the later of December 31, 2000,
or the closing of the merger. Further, the value of the amount of cash or
common stock to be received by NU shareholders is subject to increase by an
amount of $0.0034 per share per day for each day that the transaction
does not close after August 5, 2000.
Upon completion of the merger, NU will become a wholly owned subsidiary of Con
Edison. The purchase is subject to the approval of the shareholders of both
companies and several regulatory agencies. The companies anticipate that
these regulatory procedures will be completed by July 2000.
Exhibit 99.2 to Form 8-K Report
Report of Independent Public Accountants
To the Board of Trustees and Shareholders
of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust)
and subsidiaries as of December 31, 1999 and 1998, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash flows
and income taxes for each of the three years in the period ended December 31,
1999. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with generally accepted accounting
principles.
/s/ ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 25, 2000
Exhibit 99.3 to Form 8-K Report
Financial Condition
Overview
The financial improvement that began in 1998 continued throughout 1999 at
Northeast Utilities (NU or the company), despite rate reductions in
Connecticut and Massachusetts, and larger operating losses at NU's unregulated
subsidiaries. NU's results benefited from the successful restart of the
Millstone 2 nuclear unit, the strong operating performance delivered by the
Millstone 3 and Seabrook Station (Seabrook) nuclear units, retail sales growth,
and continued control over operation and maintenance (O&M) expenses. The
financial improvement allowed NU to resume the payment of a quarterly dividend
for the first time since early 1997. NU shareholders received a common
dividend of 10 cents per share in the fourth quarter of 1999.
During 1999, NU resolved key industry restructuring issues by establishing
initial stranded cost recovery levels and standard offer service tariffs and
agreements in Connecticut and by receiving final approval of a restructuring
plan in Massachusetts. The auction of substantially all of the fossil and
hydroelectric generation assets owned by The Connecticut Light and Power
Company (CL&P) and Western Massachusetts Electric Company (WMECO) and the
auction of their respective interests in the output of the Millstone units,
moved both companies along in their transition into purely electric
transmission and distribution companies, as contemplated by restructuring
legislation in both Connecticut and Massachusetts. Also in 1999, the company
made significant progress toward resolving restructuring issues in the state
of New Hampshire by negotiating a global restructuring settlement that is
still subject to regulatory approval.
NU earned $34.2 million, or $0.26 per share in 1999, compared with a loss of
$146.8 million, or $1.12 per share in 1998 and a loss of $130 million, or
$1.01 per share in 1997. Absent significant one-time items, the NU system
earned $0.89 per share in 1999, compared with a loss of $0.30 per share in 1998
and a loss of $0.76 per share in 1997. NU's improved 1999 operating results
are attributed to better operating performance of its nuclear units, a strong
economy and continued strong expense control throughout the year. The 1999
results included $83 million, or $0.63 per share, in after-tax write-offs.
These write-offs were associated with the settlement of nuclear related issues
($0.39 per share), industry restructuring ($0.15 per share) and fees related
to the pending merger with Consolidated Edison, Inc. (Con Edison) ($0.09 per
share). During 1998, NU recorded $133 million, or $0.82 per share, in
after-tax write-offs associated with a rate decision in Connecticut, the
retirement of Millstone 1 and nonrecurring charges at Charter Oak Energy, an
unregulated generation subsidiary of NU. The "Agreement to Settle PSNH
Restructuring" (Settlement Agreement), involving the Public Service Company of
New Hampshire (PSNH) calls for an after-tax write-off of $225 million.
However, that write-off was not recorded in 1999, as key aspects of the
Settlement Agreement still required regulatory and legislative approval and it
was not possible to determine the ultimate resolution of this matter at year
end.
In 1999, NU's revenues exceeded $4 billion for the first time, totaling $4.47
billion, up 18.7 percent from revenues of $3.77 billion in 1998. The growth
was primarily due to increased electric sales by Select Energy, Inc. (Select
Energy), NU's unregulated power marketing subsidiary, and higher retail sales
from NU's regulated subsidiaries. Select Energy's revenues totaled $554.9
million in 1999, compared with $29.3 million in 1998. Revenues from the
company's regulated subsidiaries also benefited from a 3.8 percent increase in
retail sales, the largest increase in retail sales in recent history.
Approximately 40 percent of that growth was due to weather related factors that
included a hotter than normal summer. The balance of that increase was due to
economic expansion in NU's service territories.
Aside from increased revenues, the primary reason for better operating
performance in 1999 was the return to service from extended outages of
Millstone 3 in July 1998 and Millstone 2 in May 1999. The return to service
of those units reduced replacement power costs by $215 million in 1999,
compared to 1998.
Retail rate reductions involving CL&P and WMECO offset some of the growth in
revenues. CL&P's rates were reduced 5 percent in early 1999. CL&P's rates
were further reduced in January 2000 by 5 percent. The additional 5 percent
rate reduction will offset some of the growth in future revenues. WMECO's
rates were reduced a total of 15 percent from its August 1997 rates,
11.8 percent adjusted for inflation, between March 1998 and September 1999.
Sharply higher purchased-power costs at Select Energy also offset many of the
benefits from higher sales. Select Energy recorded a net loss of $38.8 million
in 1999, compared with a net loss of $13.4 million in 1998. Also in 1999,
Select Energy's earnings were reduced by $4.1 million related to retail
contracts which extend through 2003.
NU's ability to continue improving financial performance in 2000 will depend
largely on continued regulated sales growth and on successful control of O&M
expenses. Additionally, NU plans to meet the challenges of assimilating Yankee
Energy System, Inc. (Yankee) into its business and achieving, by July 2000, the
shareholder and regulatory approvals needed to complete the merger with Con
Edison. NU also hopes to complete in 2000 the majority of restructuring work
remaining, primarily the implementation of the Settlement Agreement in New
Hampshire, the issuance of rate reduction bonds (securitization) to lower
stranded costs at CL&P, WMECO and PSNH, and the auction of NU's ownership
interests in the Millstone units. Additionally, during 2000, NU intends to
continue focusing on the growth of its competitive businesses. NU's ability
to reverse losses in its unregulated businesses will depend largely on the
energy marketing subsidiary's ability to better balance its supply options,
including soon to be acquired hydroelectric generation assets, with sales
commitments.
Mergers
In 1998 and 1999, NU management concluded that the pace of deregulation was
accelerating throughout the northeastern United States and that shareholders
would benefit from NU, not only remaining a major provider of electric
transmission and distribution service, but also becoming an unregulated marketer
of both electricity and natural gas. NU management also concluded that as a
result of the changes occurring in the highly competitive electric utility
industry, increased size would be crucial to achieve its objective of being
a leading provider of energy products and services in the Northeast.
NU management discussed potential business combinations with several electric
utilities in the northeastern United States. On October 13, 1999, NU announced
an agreement to merge with Con Edison, a financially stronger utility based
in New York. Con Edison will pay approximately $3.8 billion for all of the
outstanding common stock of NU and will assume NU's debt, capitalized leases
and preferred securities which totaled $3.7 billion at December 31, 1999.
Under the merger agreement, NU shareholders will receive $25 per share, in a
combination of cash and Con Edison common stock. NU shareholders will have the
right to elect cash or stock subject to proration if the total elections exceed
50 percent in either cash or stock. NU shareholders who elect to receive stock
will receive the number of shares of Con Edison stock based on the average
trading prices, determined pursuant to a formula, during a fixed period prior
to the closing. So long as such average trading prices are between $36 and
$46 per share, the total value of the Con Edison common stock received by NU
shareholders will be $25 per share. NU shareholders also have the right to
receive an additional $1 per share in value as long as definitive agreements
to sell its interests (other than that now held by PSNH) in Millstone 2 and 3
are entered into and recommended by the Utility Operations and Management Unit
of the Connecticut Department of Public Utility Control (DPUC) on or prior to
the later of December 31, 2000, or the closing of the merger. In addition,
another $0.0034 per share per day for every day beyond August 5, 2000, that
the merger is not consummated is added to the purchase price. If Con Edison's
stock price is below $36 per share, then the value received for the stock
portion will be less than $25 per share. The merger will create the nation's
largest electric distribution system with more than 5 million customers and
one of the 15 largest natural gas distribution systems with 1.4 million
customers.
NU and Con Edison filed with various state and federal regulatory bodies in
January 2000 to secure approval of the merger. The two companies expect these
regulatory proceedings can be completed by the end of July 2000.
Also in 1999, NU management concluded that the Northeast Utilities system (NU
system) would be stronger and customers could be better served if NU reentered
the natural gas distribution business that it had exited in 1989 and examined
several potential businesses in New England. By adding gas to NU's energy mix,
NU will be able to broaden its services to its existing customers and will have
additional opportunities for long-term growth. In June 1999, NU announced an
agreement to merge with Yankee.
Yankee is the natural gas division that CL&P divested in 1989. Yankee
shareholders will receive $45 per share, or approximately $479.6 million in
cash and NU common stock. In addition, NU will assume Yankee's outstanding
debt of approximately $240.8 million. Yankee shareholders will receive 45
percent of the $479.6 million in NU common stock and 55 percent in cash. NU
will finance the cash portion of the transaction and will meet the stock
component of the transaction by issuing new shares. NU expects to redeem a
similar amount of shares later this year by closing out forward share purchase
transactions with proceeds from restructuring. The forward share purchase
transactions were arranged in late 1999 with two financial institutions. NU is
prohibited from purchasing additional shares under its merger agreement with
Con Edison. The merger will return to NU Connecticut's largest natural gas
distribution system, as well as several unregulated businesses involved in
energy services, collections and other areas. The Yankee merger received
final DPUC approval in December 1999 and Securities and Exchange Commission
(SEC) approval in January 2000. The merger is expected to close in early
March 2000.
Liquidity
During 1999, strong sales growth, improved nuclear performance and continued
control of O&M expenses resulted in net cash flows provided by operations of
$614.2 million in 1999, compared to $663.3 million in 1998 and $340.6 million
in 1997.
On December 15, 1999, CL&P closed on the sale of 2,235 megawatts (MW) of fossil
generation assets with an unaffiliated company. Proceeds from the sale totaled
$516.9 million, including payments for fuel and inventory. CL&P used the
proceeds primarily to par call $406 million of first mortgage bonds in December
1999. CL&P also used $57.5 million to buy out its lease of four 40 MW
turbines.
On July 26, 1999, WMECO closed on the sale of 290 MW of fossil and
hydroelectric generation assets with an affiliate of Con Edison. Proceeds from
the sale were $48.5 million.
Proceeds from these generation asset sales are included in net cash flows
provided by investing activities. Including construction expenditures and
investments in nuclear decommissioning trusts, net cash flows provided by
investing activities were $151.2 million in 1999, compared with net cash
flows used in investing activities of $295.2 million in 1998 and $293 million
in 1997.
The strong operating cash flows provided by NU's regulated businesses and the
proceeds from generation asset sales enabled the NU system to substantially
reduce its outstanding debt. As of December 31, 1999, the NU system's total
debt level, including capital lease obligations, was $3.3 billion, compared
with $3.9 billion as of December 31, 1998, and $4.1 billion as of December 31,
1997.
The net cash flows used in financing activities were $646.4 million in 1999,
compared to $375.3 million in 1998 and $98.5 million in 1997. This included
$864 million paid in 1999 to retire long-term debt and preferred stock,
compared to $331.8 million in 1998 and $313.8 million in 1997. Cash dividends
on common shares paid in 1999 were $13.2 million, compared to no cash dividends
in 1998 and $32.1 million in 1997. Payments made for preferred stock dividends
were $22.8 million, $26.4 million and $30.3 million for 1999, 1998 and 1997,
respectively.
The NU system's access to capital also benefited from the strong operating
performance at Millstone 2 and 3, continued progress toward the resolution of
all restructuring issues in New Hampshire and the announced merger with Con
Edison. During 1999, NU system securities received several upgrades from three
credit rating agencies. CL&P's and WMECO's senior secured bonds achieved
investment grade ratings for the first time since early 1997 and PSNH's bonds
were upgraded to investment grade by Standard & Poor's (S&P) for the first
time since early 1994. At year end, all securities were under review for
possible upgrades, or on "credit watch" with positive implications by S&P,
Moody's Investors Service and Fitch IBCA.
The rating agency upgrades benefited NU's efforts to broaden its credit lines.
On November 19, 1999, NU parent entered into a $350 million, 364-day unsecured
revolving credit facility which allows NU parent access to $350 million in a
combination of cash and letters of credit. NU parent provides credit assurance
in the form of guarantees of letters of credit, performance guarantees and other
assurances for the financial performance obligations of certain of its
unregulated subsidiaries, particularly Select Energy. Over the course of 1999,
NU parent sought and received approval from the SEC to increase the limit of
such credit assurance arrangements from $75 million to $500 million. However,
NU is limited under certain loan agreements to $350 million of such
arrangements without creditor approval. As of December 31, 1999, NU had
provided approximately $190 million of such credit assurances.
Also on November 19, 1999, CL&P and WMECO entered into a new 364-day revolving
credit facility for $500 million, replacing the previous $313.75 million
facility which was to expire on November 21, 1999. The revolving credit
facility, which is secured by second mortgaes on Millstone 2 and 3, will be
used to bridge gaps in working capital and provide short-term liquidity.
CL&P may draw up to $300 million and WMECO may draw up to $200 million under
the facility. Once CL&P and WMECO receive the proceeds from securitization,
the $500 million facility will be reduced to $300 million, with a $200 million
limit for CL&P and a $100 million limit for WMECO. As of December 31, 1999,
CL&P had $90 million and WMECO had $123 million outstanding under this
facility.
For further information regarding the NU parent revolving credit facility and
the CL&P and WMECO revolving credit facility, see Note 3, "Short-Term Debt,"
to the consolidated financial statements.
PSNH's $75 million revolving credit agreement was terminated on April 14, 1999.
PSNH currently funds its operations through cash on hand and operating cash
flows. As of December 31, 1999, PSNH had $182.6 million of cash and cash
equivalents. On April 14, 1999, PSNH renewed bank letters of credit that
support nearly $110 million of taxable variable-rate pollution control bonds.
CL&P also has arranged financing through the sale of its accounts receivable.
CL&P can finance up to $200 million through this facility. As of December 31,
1999, CL&P had $170 million outstanding under this facility. WMECO terminated
its $40 million accounts receivable credit facility on June 30, 1999.
In late 1999, NU arranged forward purchase transactions for approximately 10
million NU common shares with two financial institutions (counterparties).
To effect these transactions, the counterparties purchased, on the open market
between November 1999 and January 2000, NU common shares, at an average price
per share of $21.26, in a total aggregate amount of $215 million. The
counterparties maintain ownership of the shares until the transactions are
settled. Additionally, NU will continue to accrue fees on the total aggregate
amount at LIBOR plus 2.5 percent per annum, until the transactions are settled.
These transactions can be settled in cash or NU common shares at the company's
discretion. As required under the terms of the contracts, NU must settled the
transactions no later than December 31, 2000 for an aggregate purchase price
equal to $215 million. However, NU expects to settle these purchase
transactions with the proceeds from restructuring in the second half of 2000.
If prior to the settlement date, NU's share price falls below $15.80 per share,
NU may be required to provide the counterparties with additional collateral.
During 2000, the NU system companies hope to receive regulatory approval to
begin the process of securitizing approximately $2.5 billion of approved
stranded costs. Securitization involves issuing rate reduction bonds with
interest rates lower than the company's weighted average cost of capital.
Proceeds from securitization will be used to significantly reduce the
capitalization of NU's regulated subsidiaries and buyout or buydown certain
purchased-power contracts with a number of nonutility generators.
Restructuring
During 1999, Connecticut and Massachusetts made significant progress in
resolving industry restructuring issues. Restructuring orders issued in
Connecticut and Massachusetts allowed NU to determine the impacts of
discontinuing Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," for the generation
portion of CL&P's and WMECO's businesses. In both states, the transmission and
distribution portion of those businesses will continue to be cost-of-service
regulated. In addition, the restructuring orders provided for a transition
charge which allows for the recovery of CL&P's and WMECO's generation-related
regulatory assets and prudently incurred stranded costs.
The process of restructuring the electric utility industry in New Hampshire
has not yet been concluded, however, significant progress has been made over
the past year. In August 1999, PSNH and state officials reached a Settlement
Agreement, addressing all rate and restructuring issues involving PSNH,
which is awaiting New Hampshire Public Utilities Commission (NHPUC) approval.
Connecticut
During April 1999, CL&P filed its standard offer service plan with the DPUC
and received a decision on October 1, 1999, as amended on December 15, 1999.
In that decision, the DPUC approved the recovery of CL&P's regulatory assets
and certain stranded costs associated with CL&P's nuclear generation assets
and established the methodology for setting CL&P's standard offer rates,
including the transition charge and transmission and distribution rates.
The DPUC ruled on CL&P's stranded cost filing in July 1999 approving $3.5
billion of stranded cost recovery, which is utilized, in part, in the
determination of the transition charge.
As provided for in the electric utility restructuring legislation enacted in
April 1998, 35 percent of CL&P's customers were able to choose their electric
generation supplier on January 1, 2000, with the remaining 65 percent having
choice on July 1, 2000. The major components of rates are a transmission and
distribution charge, a generation charge and a transition charge. For those
customers who do not or are unable to choose another competitive electric
generation supplier, CL&P will supply standard offer or generation service at
an average rate of $0.04813 per kilowatt-hour (kWh) through December 31, 2003.
The revenues attributable to standard offer (generation) service are expected
to exceed the actual cost of providing generation and the difference will be
applied against stranded costs. In accordance with a plan approved by the
DPUC, one-half of the CL&P standard offer load was procured through a
competitive bidding process, with the remaining one-half of the power being
supplied by an affiliated company. The contracts are in place through the
end of 2003. For further information regarding commitments and contingencies
related to the Connecticut restructuring order, see Note 7A, "Commitments and
Contingencies - Restructuring - Connecticut," to the consolidated financial
statements.
Massachusetts
Massachusetts enacted electric utility restructuring legislation in November
1997. Based on an interim order approving WMECO's restructuring plan filed in
December 1997, WMECO's customers were able to choose an alternative retail
electricity supplier beginning on March 1, 1998. In 1999, the Massachusetts
Department of Telecommunications and Energy (DTE) issued its final decision
on WMECO's restructuring plan. In that decision, the DTE permitted WMECO to
recover its generation-related regulatory asset balances and its nuclear
decommissioning costs. However, the DTE disallowed any return on Millstone 2
and 3 starting March 1, 1998, until they returned to service and on Millstone 1
for its remaining life. The pretax impact of these disallowances was $41
million. The DTE also approved one-year contracts with the winning bidders
of the standard offer and default service supply auction. For further
information regarding commitments and contingencies related to the
Massachusetts restructuring order, see Note 7A, "Commitments and Contingencies
- - Restructuring - Massachusetts," to the consolidated financial statements.
Generation Asset Divestitures - Connecticut and Massachusetts
The Connecticut and Massachusetts restructuring laws required CL&P and WMECO
to divest of their nonnuclear generation assets and utilize substantially all
of the net gains from any sales to offset stranded costs. During 1999, WMECO
and CL&P sold their nonnuclear generation assets resulting in net gains of
$22.4 million and $286.5 million, respectively. A corresponding amount of
regulatory assets was amortized. In September 1999, NU announced that the
Millstone nuclear generation assets of its subsidiaries, CL&P and WMECO, will
be put up for auction as soon as practical. For further information regarding
commitments and contingencies related to the Connecticut and Massachusetts
generation asset divestitures, see Note 7A, "Commitments and Contingencies -
Restructuring - Nuclear Generation Assets Auction," to the consolidated
financial statements.
New Hampshire
In August 1999, NU, PSNH and the state of New Hampshire signed the Settlement
Agreement which will resolve a number of pending regulatory and court
proceedings related to PSNH. The Settlement Agreement is awaiting approval
of the NHPUC and is subject to legislative approval of securitization. The
key components of the agreement include an after-tax write-off of $225 million
of stranded costs; the recovery of the remaining stranded costs; the
securitization of $725 million of approved stranded costs; the sale
of generation assets and wholesale power entitlements, with transition service
being available to customers for three years; a reduction in rates of an
average of 18.3 percent, and the opening of the New Hampshire electricity
market to competition. For further information regarding commitments and
contingencies related to the New Hampshire Settlement Agreement, see Note 7A,
"Commitments and Contingencies - Restructuring - New Hampshire," to the
consolidated financial statements.
Unregulated Energy Services
The energy marketing and brokering business is intensely competitive, with
many companies with larger financial resources than NU's bidding for business
in the deregulating New England market. The sharply fluctuating cost of power
supply caused by, among other things, weather extremes, plant outages and fuel
costs, and a lack of load-following generating facilities, have made it
difficult for Select Energy to economically match its wholesale power purchases
with its power supply obligations. In 1999, Select Energy recorded a net loss
of $38.8 million on revenues of $554.9 million, compared to a net loss of
$13.4 million on revenues of $29.3 million in 1998. Select Energy's ability
to economically compete has also been affected by NU's weakened financial
position caused by the extended Millstone outages which ended in mid 1999.
In 2000, Select Energy's expected contract with an affiliated company, Northeast
Generation Company, to purchase 1,329 MW of capacity and energy should
significantly reduce the load-following risk and allow Select Energy to better
manage its portfolio profitability.
Select Energy's goal is to be the regional and national leader in providing
standard offer service to those Northeast markets opened to retail competition.
Currently, Select Energy provides more than 5,000 MW of standard offer load,
making it the largest provider of standard offer service in the Northeast. On
December 22, 1999, Select Energy and an unaffiliated company signed a 6-month
power supply agreement, effective January 1, 2000, to meet the utility's
standard offer service requirements, which are expected to exceed 3,000 MW.
This contract does not include renewal or termination provisions, and payment
is due within ten days of the receipt of the bill. Select Energy has been
serving this standard offer load since December 1998. During 1999, revenues
billed to this customer totaled $276.1 million, or approximately 46 percent
of Select Energy's revenues. On January 1, 2000, Select Energy began serving
CL&P with one-half of its approximately 2,000 MW standard offer requirement
for a 4-year period. The CL&P standard offer contract does not include renewal
provisions. Select Energy can terminate the contract if the Federal Energy
Regulatory Commission (FERC) or DPUC require changes to the contract which
create material adverse economic impact to Select Energy which cannot be cured.
These power supply contracts are expected to provide Select Energy with over
50 percent of its revenues in the year 2000. In addition, beginning in
January 2000, Select Energy assumed responsibility for serving approximately
30 market-based wholesale contracts, totaling approximately 500 MW, throughout
New England with electric energy supply that was previously provided by CL&P
and WMECO. For the most part, the prices are fixed by contract and applicable
to actual volumes.
Nuclear Generation
Millstone Nuclear Units
Millstone 3 received the appropriate Nuclear Regulatory Commission (NRC)
approvals and resumed operation in July 1998. Millstone 2 received similar
NRC approvals, resumed operation and was returned to CL&P's rate base in May
1999. Millstone 3 and 2 achieved annual capacity factors of 81.7 percent
and 57.9 percent in 1999, respectively. After a 60-day refueling and
maintenance outage, Millstone 3 returned to service on June 29, 1999, and
has achieved a 98.1 percent capacity factor through December 31, 1999. Since
returning to service in May 1999, Millstone 2 has achieved a 90.3 percent
capacity factor through December 31, 1999. NU's total share of O&M expenses
associated with Millstone 3 and 2 totaled $261.8 million in 1999, as compared
to $323.2 million in 1998 and $406 million in 1997. Millstone 1 is currently
in decommissioning status.
An auction of the NU system's ownership interests in the Millstone units is
expected in 2000 with a closing in 2001. Based on regulatory decisions
received in 1999, management expects to recover all of its remaining nuclear
stranded costs from retail customers.
Seabrook
Seabrook achieved an annual capacity factor of 86.4 percent in 1999. However,
since returning to service on May 13, 1999, after a 48-day refueling and
maintenance outage, Seabrook has achieved a 99 percent capacity factor through
December 31, 1999.
CL&P anticipates auctioning its 4.06 percent share of Seabrook, with the
35.98 percent share owned by its affiliate North Atlantic Energy Corporation
(NAEC) after approval of the Settlement Agreement. The Settlement Agreement
with the state of New Hampshire requires divestiture prior to December 31,
2003.
Yankee Companies
On June 1, 1999, the FERC accepted the offer of settlement which was filed on
January 15, 1999, by the Maine Yankee Atomic Power Company (MYAPC). The
significant aspects of the settlement allowed MYAPC to collect $33.6 million
annually to pay for decommissioning and spent fuel, approved its return on
equity of 6.5 percent, permitted full recovery of MYAPC's unamortized
investment, including fuel, and set an incentive budget for decommissioning
at $436.3 million.
On October 15, 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC)
agreed to sell its unit for $22 million to an unaffiliated company. Among
other commitments, the acquiring company agreed to assume the decommissioning
cost of the unit after it is taken out of service, and the VYNPC owners have
agreed to fund the uncollected decommissioning cost to a negotiated amount at
the time of the closing of the sale. VYNPC's owners have also agreed either
to enter into a new purchased-power agreement with the acquiring company or
to buy out such future power payment obligations by making a fixed payment
to them. CL&P, WMECO and PSNH have elected the buyout option. The VYNPC
owners' obligations to close and pay such amounts are conditioned upon their
receipt of satisfactory regulatory approval of the transaction, including
provision for adequate recovery of these payments.
Nuclear Decommissioning
The staff of the SEC has questioned certain of the current accounting practices
of the electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear units in their financial
statements.
Currently, the Financial Accounting Standards Board plans to review the
accounting for obligations associated with the retirement of long-lived assets,
including the decommissioning of nuclear units. If current accounting
practices for nuclear decommissioning change, the annual provision for
decommissioning could increase relative to 1999, and the estimated cost for
decommissioning could be recorded as a liability with recognition of an
increase in the cost of the related nuclear unit. However, management
does not believe that such a change will have a material impact on the NU
system's financial statements due to its current and future ability to recover
decommissioning costs through rates.
Spent Nuclear Fuel Disposal Costs
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent fuel in 1998. However, delays in confirming the
suitability of a permanent storage site continually have postponed plans for
the DOE's long-term storage and disposal site. Extended delays or a default
by the DOE could lead to consideration of costly alternatives. NU has the
primary responsibility for the interim storage of its spent nuclear fuel.
Adequate storage capacity exists to accommodate all spent nuclear fuel at
Millstone 1. The facilities for Millstone 2 are expected to provide adequate
storage to accommodate a full-core discharge from the reactor until 2005 with
the implementation of currently planned modifications. Fuel consolidation,
which has been licensed for Millstone 2, could provide adequate storage
capacity for its projected life. The facilities for Millstone 3 are expected
to provide adequate storage for its projected life with the addition of new
storage racks. Seabrook is expected to have spent fuel storage capacity until
at least 2010. Meeting spent fuel storage requirements beyond these periods
could require new and separate storage facilities. For further information
regarding spent nuclear fuel disposal costs, see Note 7D, "Commitments and
Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated
financial statements.
Market Risk and Risk Management Instruments
The NU system uses swaps and collars to manage the market risk exposures
associated with changes in variable interest rates and energy prices. The
NU system uses these instruments to reduce risk by essentially creating
offsetting market exposures. Based on the derivative instruments which are
currently being utilized by the NU system companies to hedge some of their
interest rate and energy price risks, there may be an impact on earnings upon
adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," which management has not estimated at this time.
Interest Rate Risk Management Instruments
Several NU subsidiaries hold variable-rate, long-term debt, exposing the NU
system to interest rate risk. In order to hedge some of this risk, interest
rate risk management instruments have been entered into on NAEC's $200 million
variable-rate note. A 10 percent increase in market interest rates above the
1999 weighted average variable rate during 2000 would result in an immaterial
impact on interest expense.
Energy Price Risk Management Instruments
In the generation of electricity, the most significant segment of the variable
cost component is the cost of fuel. Typically, most of CL&P's fuel purchases
were protected by a regulatory fuel price adjustment clause. However, for a
specific, well-defined volume of fuel that was excluded from the energy price
adjustment clause, CL&P employed energy price risk management instruments to
protect itself against the risk of rising fuel prices, thereby limiting fuel
costs and protecting its profit margins. These risks were created by the sale
of long-term fixed-price electricity sales contracts to wholesale customers.
In 1999, CL&P divested substantially all of its fossil and hydroelectric
generation assets and also transferred the rights and obligations of its
long-term fixed-price contracts to an unregulated affiliate. As a result,
the fuel swap positions were marked-to-market and CL&P recognized a loss of
$5.2 million. In January 2000, the fuel swap positions were liquidated.
Unregulated Energy Services Market Risk
NU's unregulated companies, as major providers of electricity and natural gas,
have certain market risks inherent in their business activities. Market risk
represents the risk of loss that may impact the companies' financial position,
results of operations or cash flows due to adverse changes in commodity market
prices. In 1999, the companies increased their volume of electricity and gas
marketing activities, increasing their risks. Policies and procedures have
been established to manage these exposures including the use of risk management
instruments.
Other Matters
Environmental Matters
NU is subject to environmental laws and regulations structured to mitigate or
remove the effect of past operations and to improve or maintain the quality of
the environment. For further information regarding environmental matters, see
Note 7C, "Commitments and Contingencies - Environmental Matters," to the
consolidated financial statements.
Other Commitments and Contingencies
NU is subject to other commitments and contingencies primarily relating to
nuclear litigation, nuclear insurance contingencies, its constuction program,
long-term contractual arrangements, and the New England Power Pool generation
pricing. For further information regarding these other commitments and
contingencies, see Note 7, "Commitments and Contingencies," to the consolidated
financial statements.
Year 2000 Issues
The transition into the year 2000 was a success for the NU system. Its mission
to provide safe, reliable energy to its customers and to ensure continued
operability of critical business functions was not affected by any year 2000
related issues.
The projected total cost of the year 2000 program is estimated at $21 million.
The total cost to date was funded through operating cash flows. The NU system
has incurred and expensed $20 million related to year 2000 readiness efforts.
Forward Looking Statements
This discussion and analysis includes forward looking statements, which are
statements of future expectations and not facts. Words such as estimates,
expects, anticipates, intends, plans, and similar expressions identify forward
looking statements. Actual results or outcomes could differ materially as a
result of further actions by state and federal regulatory bodies, competition
and industry restructuring, changes in economic conditions, changes in
historical weather patterns, changes in laws, developments in legal or public
policy doctrines, technological developments, and other presently unknown or
unforeseen factors.
Results Of Operations
The components of significant income statement variances for the past two years
are provided in the table below.
Income Statement Variances
(Millions of Dollars)
1999 over/(under) 1998 1998 over/(under) 1997
Amount Percent Amount Percent
Operating Revenues $704 19% $(67) (2)%
Operating Expenses:
Fuel, purchased and net
interchange power 428 29 (8) (1)
Other operation 52 7 (116) (13)
Maintenance (58) (15) (103) (20)
Depreciation (31) (9) (22) (6)
Amortization of regulatory
assets, net 393 (a) 79 64
Federal and state income taxes 93 (a) 4 (a)
Taxes other than income taxes 9 4 (2) (1)
Gain on sale of utility plant (309) - - -
Total operating expenses 584 16 (101) (3)
Operating income 120 53 34 18
Equity in earnings of regional
nuclear generating and
transmission companies (7) (59) (1) (9)
Nuclear unrecoverable costs 72 50 (143) (100)
Other income/(loss), net (19) (a) 19 61
Interest charges, net (5) (2) (3) (1)
Preferred dividends of
subsidiaries (4) (14) (4) (13)
Net income/(loss) 181 (a) (17) (13)
(a) Percentage greater than 100.
Operating Revenues
Total revenues increased by $704 million or 19 percent in 1999 due to higher
revenues from the competitive companies ($552 million), higher regulated
wholesale revenues ($107 million) and higher regulated retail revenues ($45
million). The competitive companies' increase is due to higher revenues from
Select Energy ($526 million) and HEC Inc. (HEC) ($26 million). Select
Energy's revenues were higher in 1999 as a result of new contracts for energy
sales. The regulated wholesale revenue increase is primarily due to higher
energy sales and related capacity and transmission revenues. The regulated
retail increase is primarily due to higher retail sales ($99 million) and the
impact of Millstone 2 and 3 being returned to CL&P's rate base ($13 million).
These retail increases were partially offset by retail rate reductions for CL&P
and WMECO ($55 and $12 million, respectively). Regulated retail kilowatt-hour
sales increased by 3.8 percent.
Retail revenues decreased by $199 million in 1998 due to retail rate reductions
for CL&P, PSNH and WMECO and the accounting impact of Millstone 2 and 3 being
removed from CL&P's rate base. Wholesale revenues decreased by $32 million
primarily as a result of the terminated contract with the Connecticut Municipal
Electric Cooperative (CMEEC). Other revenues decreased $50 million due to
lower billings to outside companies for reimbursable costs and price
differences among customer classes. These decreases were partially offset by
higher fuel recoveries and higher retail sales volumes. Fuel recoveries
increased by $166 million primarily due to higher fuel revenues from PSNH as a
result of a higher fuel and purchased-power adjustment clause rate. Retail
kilowatt-hour sales were 1.9 percent higher and contributed $48 million to
nonfuel revenues in 1998 primarily as a result of economic growth in all
three states.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 1999, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($521 million), regulated wholesale ($86 million) and
regulated retail ($36 million), partially offset by lower replacement power
costs due to the return to service of Millstone 2 and 3 ($215 million).
The change in fuel, purchased and net interchange power expense in 1998 was
not significant.
Other Operation and Maintenance
Other O&M expenses decreased in 1999, primarily due to lower costs at the
Millstone units ($125 million), partially offset by the recognition of
environmental insurance proceeds in 1998 and additional environmental reserves
in 1999 ($30 million), higher transmission and power exchange expenses ($35
million), higher spending at Seabrook ($10 million) as a result of the
refueling outage, higher expenditures for HEC and the competitive businesses
($32 million), and expenses associated with the Con Edison merger ($12 million)
in 1999.
Other O&M expenses decreased in 1998, primarily due to lower costs at the
Millstone units ($159 million), lower costs at the Seabrook and Yankee
companies' nuclear units ($50 million), the recognition of environmental
insurance proceeds ($27 million), and lower administrative and general expenses
($26 million). These decreases were offset partially by higher recognition of
nuclear refueling outage costs primarily as a result of the 1996 CL&P rate
settlement ($29 million).
Depreciation
Depreciation decreased in 1999 and 1998, primarily due to the retirement of
Millstone 1.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased in 1999, primarily due to the
increased amortization associated with the gain on the sale of CL&P's and
WMECO's fossil and hydroelectric generation assets ($309 million), the
amortization of CL&P's and WMECO's Millstone 1 remaining investment ($56
million) and the reclassification of the depreciation on the nuclear plants to
regulatory assets ($23 million).
Amortization of regulatory assets, net increased in 1998, primarily due to
accelerated amortizations in accordance with regulatory decisions for CL&P
($49 million), the amortization of NAEC's Seabrook deferred return ($79
million) and the beginning of the amortization of CL&P's Millstone 1
investment ($23 million). These increases were partially offset by the lower
amortization of the PSNH acquisition premium ($40 million).
Federal and State Income Taxes
The consolidated statement of income taxes provides a reconciliation of actual
and expected tax expense. The tax effect of temporary differences is accounted
for in accordance with the rate-making treatment of the applicable regulatory
commissions. In past years, this rate-making treatment has required the
company to provide the customers with a portion of the tax benefits associated
with accelerated tax depreciation in the year it is generated (flow-through
depreciation). As these flow-through differences turn around, higher tax
expense is recorded.
Federal and state income tax expense increased approximately $93 million in
1999, primarily due to the significant increase in pretax earnings.
Significant variances of other items include a $10 million increase in flow-
through depreciation turnaround and $4.6 million of nontax deductible merger
related expenditures offset by the elimination of a $23 million deferred tax
asset valuation reserve.
Federal and state income taxes increased in 1998, primarily due to higher book
taxable income, partially offset by an increase in income tax credits primarily
due to the Millstone 1 write-off of unrecoverable costs as a result of the
February 1999 CL&P rate decision.
Gain on Sale of Utility Plant
CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric
generation assets in 1999. A corresponding amount of amortization expense
was recorded.
Equity in Earnings of Regional Nuclear Generating and Transmission Companies
Equity in earnings of regional nuclear generating and transmission companies
decreased in 1999 and 1998, primarily due to lower earnings from the
Connecticut Yankee Atomic Power Company.
Nuclear Unrecoverable Costs
Nuclear unrecoverable costs in 1999 are comprised of one-time charges related
to the CL&P write-off of CMEEC nuclear costs ($19.9 million), the CL&P
write-off of capital projects as a result of the Connecticut standard offer
decision ($11 million), the CL&P/WMECO settlement of Millstone 3 joint owner
litigation, net of insurance proceeds ($27 million), the WMECO return
disallowed on Millstone 1 unrecovered plant from March 1998 forward ($10.8
million), and the WMECO disallowed Millstone 1 plant per the Massachusetts
restructuring order ($2.1 million). In comparison, 1998 is comprised of the
write-off of the Millstone 1 entitlement formerly held by CMEEC ($27.8 million)
and the write-off of unrecoverable costs as a result of the February 1999 CL&P
rate decision ($115.3 million).
Other Income/(Loss), Net
Other income/(loss), net decreased in 1999, primarily due to the PSNH
settlement with the New Hampshire Electric Cooperative ($6.2 million) and the
loss on the CL&P assignment of market-based contracts to Select Energy ($15
million).
The 1998 increase over 1997 is primarily due to the proceeds resulting from the
shareholder derivative suit.
