<Page>
Exhibit 99.3
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
NorthWestern Corporation
In our opinion, the accompanying combined balance sheets and the related
combined statements of income, of other equity and of cash flows present fairly,
in all material respects, the financial position of The Utility of The Montana
Power Company and related subsidiaries and business trusts, consisting of the
utility operations of The Montana Power Company, Montana Power Capital I,
Discovery Energy Solutions, Inc., Canadian-Montana Pipe Line Corporation,
Montana Power Services Company, One Call Locators, Ltd., Montana Power Natural
Gas Funding Trust and Colstrip Community Services Company, (collectively
referred to as the "Utility"), at December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001 in conformity with accounting principles generally
accepted in the United States of America. These financial statements are the
responsibility of the Utility's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the combined financial statements, the Company
changed its method of accounting for derivative instruments as of January 1,
2001.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Portland, Oregon
February 22, 2002
1
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
COMBINED STATEMENT OF INCOME
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
REVENUES.................................................... $703,785 $676,053 $657,081
EXPENSES:
Operations and maintenance................................ 507,768 433,699 301,908
Selling, general, and administrative...................... 89,479 118,518 85,356
Taxes other than income taxes............................. 53,070 55,616 67,898
Depreciation and amortization............................. 56,725 54,123 69,694
-------- -------- --------
707,042 661,956 524,856
-------- -------- --------
INCOME (LOSS) FROM OPERATIONS............................... (3,257) 14,097 132,225
INTEREST EXPENSE AND OTHER INCOME:
Interest.................................................. 39,678 35,880 47,363
Distributions on company obligated mandatorily redeemable
preferred securities of subsidiary trust................ 5,492 5,492 5,492
Other income--net......................................... (1,355) (14,481) (2,567)
-------- -------- --------
43,815 26,891 50,288
-------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES......................... (47,072) (12,794) 81,937
INCOME TAX EXPENSE (BENEFIT)................................ (4,074) (19,599) 13,895
-------- -------- --------
NET INCOME (LOSS)........................................... (42,998) 6,805 68,042
DIVIDENDS ON PREFERRED STOCK................................ 3,770 3,690 3,690
-------- -------- --------
NET INCOME (LOSS) AVAILABLE FOR LLC UNITS................... $(46,768) $ 3,115 $ 64,352
======== ======== ========
LLC UNITS OUTSTANDING....................................... 10 10 10
BASIC AND DILUTED EARNINGS (LOSS) PER LLC UNIT.............. $ (4,677) $ 312 $ 6,435
======== ======== ========
</Table>
The accompanying notes are an integral part of these combined financial
statements.
2
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
COMBINED BALANCE SHEET
ASSETS
<Table>
<Caption>
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(THOUSANDS OF DOLLARS)
CURRENT ASSETS:
Cash and cash equivalents................................. $ 7,510 $ --
Accounts receivable:
Unrelated, net of allowances............................ 78,842 135,424
Related................................................. 41,845 76,883
Notes receivable:
Unrelated............................................... 182 254
Related................................................. -- 50,863
Materials and supplies (principally at average cost)...... 10,760 11,287
Prepayments and other assets.............................. 37,857 48,513
Prepaid income taxes...................................... 25,492 11,050
Deferred income taxes..................................... 5,647 17,054
---------- ----------
208,135 351,328
PROPERTY PLANT AND EQUIPMENT:
Plant, less accumulated depreciation and amortization..... 1,091,235 1,089,329
OTHER ASSETS:
Intangibles............................................... 7,418 7,988
Investments............................................... 25,936 25,937
Regulatory assets related to income taxes................. 30,113 60,423
Regulatory assets--other.................................. 173,192 142,434
Other deferred charges.................................... 26,870 7,347
---------- ----------
263,529 244,129
TOTAL ASSETS................................................ $1,562,899 $1,684,786
========== ==========
</Table>
The accompanying notes are an integral part of these combined financial
statements.
3
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
COMBINED BALANCE SHEET
LIABILITIES AND EQUITY
<Table>
<Caption>
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(THOUSANDS OF DOLLARS)
CURRENT LIABILITIES:
Accounts payable:
Unrelated............................................... $ 24,823 $ 72,919
Related................................................. 39,983 77,487
Dividends payable......................................... 776 1,456
Other taxes payable....................................... 25,951 30,827
Regulatory liability--oil and natural gas sale............ 22,166 32,549
Short-term borrowing:
Unrelated............................................... -- 75,000
Related................................................. 24,811 49,372
Long-term debt due within one year........................ 16,061 67,715
Interest accrued.......................................... 7,580 5,895
Current portion of deferred revenue....................... 13,361 12,649
Other current liabilities................................. 35,468 49,754
---------- ----------
210,980 475,623
LONG-TERM LIABILITIES:
Deferred income taxes..................................... 49,333 81,004
Investment tax credits.................................... 12,718 13,163
Deferred revenue.......................................... 28,025 42,381
Net proceeds from the generation sale..................... 223,423 214,887
Other deferred credits.................................... 149,970 67,814
---------- ----------
463,469 419,249
LONG-TERM DEBT:
Long-term debt............................................ 442,680 309,463
Company obligated mandatorily redeemable preferred
securities of subsidiary trust.......................... 65,000 65,000
---------- ----------
507,680 374,463
EQUITY:
Preferred stock........................................... 57,654 57,654
Other equity.............................................. 323,116 357,797
---------- ----------
380,770 415,451
TOTAL LIABILITIES AND EQUITY................................ $1,562,899 $1,684,786
========== ==========
</Table>
The accompanying notes are an integral part of these combined financial
statements.
4
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
COMBINED STATEMENT OF CASH FLOWS
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $(42,998) $ 6,805 $ 68,042
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization........................... 56,725 54,123 69,694
Deferred income taxes................................... 9,601 (13,671) (188,570)
Gains on sales of property and investments.............. -- -- (59)
Other noncash charges to net income--net................ (7,190) 3,807 11,364
Changes in assets and liabilities:
Accounts and notes receivable--unrelated.............. 56,654 (36,519) 62,183
Accounts and notes receivable--related................ 85,901 86,708 (131,293)
Income taxes payable.................................. -- (115,784) 106,948
Prepaid income taxes.................................. (14,442) (11,050) --
Accounts payable--unrelated........................... (48,096) 48,747 2,033
Accounts payable--related companies................... (37,504) (5,267) 50,720
Deferred revenue...................................... (14,356) (49,881) 92,262
Miscellaneous temporary investments................... -- 40,417 (40,417)
Shared proceeds--oil and natural gas sale............. (10,383) 32,549 --
Generation asset sale--net proceeds................... 8,536 (4,839) 219,726
Other assets and liabilities--Net..................... 33,244 19,664 24,213
-------- -------- --------
Net cash provided by operating Activities................. 75,692 55,809 346,846
</Table>
The accompanying notes are an integral part of these combined financial
statements.
5
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
COMBINED STATEMENT OF CASH FLOWS (CONT.)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
-------- --------- ---------
(THOUSANDS OF DOLLARS)
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures...................................... (59,288) (77,867) (79,575)
Proceeds from sales of property and investments........... 2,916 -- 514,844
Investments in property................................... -- (1,091) --
Advances to related companies............................. -- (99,000) --
Additional investments.................................... -- (1,433) (345)
-------- --------- ---------
Net cash (used for) provided by investing activities.... (56,372) (179,391) 434,924
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Purchase of The Montana Power Company treasury stock...... -- (60,784) (144,872)
Dividends from related companies.......................... 9,411 -- 138,900
Issuance of The Montana Power Company common stock........ 467 2,384 357
Dividends paid............................................ (3,690) (67,053) (90,902)
Issuance of long-term debt................................ 149,272 36,990 23,074
Retirement of long-term debt.............................. (67,709) (305,365) (145,201)
Net change in short-term borrowing--unrelated............. (75,000) 75,000 --
Net change in short-term borrowing--related............... (24,561) (626) (123,296)
-------- --------- ---------
Net cash (used for) provided by financing activities.... (11,810) (319,454) (341,940)
-------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 7,510 (443,036) 439,830
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.............. -- 443,036 3,206
-------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................... $ 7,510 $ -- $ 443,036
======== ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid for:
Income taxes, net of refunds................................ $ 93,405 $ 132,944 $ 126,514
Interest.................................................... 41,104 44,419 56,356
</Table>
The accompanying notes are an integral part of these combined financial
statements.
6
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
COMBINED STATEMENT OF OTHER EQUITY
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
-------- --------- ---------
(THOUSANDS OF DOLLARS)
Other equity at beginning of period......................... $357,797 $ 574,050 $ 602,493
Comprehensive income (loss):
Net income (loss)......................................... (42,998) 6,805 68,042
Other comprehensive income (loss):
SFAS No. 133 cumulative transition adjustment........... 11,304 -- --
Unrealized loss on derivative transactions.............. (4,104) -- --
Realized gain on derivative transactions transferred to
income................................................ (7,200) -- --
Loss on benefit restoration plan........................ (298) (1,710)
Foreign currency translation adjustments................ (112) 15 63
-------- --------- ---------
(43,408) 5,110 68,105
Equity:
Issuance of The Montana Power Company common stock........ 467 2,384 357
Reacquisition of The Montana Power Company common stock... -- (60,784) (144,872)
Dividends on The Montana Power Company common stock....... -- (62,426) (88,155)
Dividends on The Montana Power Company preferred stock.... (3,770) (3,690) (3,690)
Distributions on unallocated stock held by trustee for
retirement savings plan................................. 4,465 3,174 2,897
Equity transfers and distributions........................ 9,411 (99,000) 138,900
Other..................................................... (1,846) (1,021) (1,985)
-------- --------- ---------
8,727 (221,363) (96,548)
Other equity at end of period............................... $323,116 $ 357,797 $ 574,050
======== ========= =========
</Table>
The accompanying notes are an integral part of these combined financial
statements.
7
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- - PRINCIPLES OF COMBINATION
The combined financial statements of The Utility of The Montana Power
Company include the utility operations of The Montana Power, L.L.C. (MPLLC), and
its wholly owned subsidiaries Canadian-Montana Pipe Line Corporation, Montana
Power Capital I, Montana Power Natural Gas Funding Trust, Colstrip Community
Services Company, One Call Locators, Ltd., Discovery Energy Solutions, Inc., and
Montana Power Services Company. All intercompany transactions and balances have
been eliminated in the combination of these entities. These entities are being
combined because they represent the entities which are wholly owned by MPLLC as
of February 15, 2002, and included in the sale to NorthWestern discussed below.
Prior to the February 15, 2002 sale, these entities were commonly owned and
controlled by The Montana Power Company (MPC).
When we use the terms "we," "us," or "our" in this financial presentation,
we mean the utility operations of MPLLC and its wholly owned subsidiaries.
- - THE MONTANA POWER, L.L.C.
On September 29, 2000, MPC, our former parent company, entered into a Unit
Purchase Agreement with NorthWestern Corporation (NorthWestern), a South
Dakota-based energy company, to sell its affiliate, MPLLC. MPLLC holds--among
other assets, liabilities, commitments, and contingencies--primarily an electric
and natural gas utility business.
After receiving approval of its shareholders and regulatory approvals from
the Federal Energy Regulatory Commission (FERC) and the Montana Public Service
Commission (PSC), on February 15, 2002, MPC sold the utility operations to
NorthWestern for $602,000,000 in cash and the assumption of $488,000,000 of its
debt.
- - BASIS OF ACCOUNTING
Our accounting policies conform with generally accepted accounting
principles. With respect to our utility operations, these policies are in
accordance with the accounting requirements and ratemaking practices of
applicable regulatory authorities.
- - USE OF ESTIMATES
Preparing financial statements requires the use of estimates based on
available information. Actual results may differ from our accounting estimates
as new events occur or we obtain additional information.
- - CASH AND CASH EQUIVALENTS AND TEMPORARY CASH INVESTMENTS
We consider all liquid investments with original maturities of three months
or less to be cash equivalents, and investments with original maturities over
three months and up to one year as temporary investments. We had no temporary
investments at December 31, 2001 or December 31, 2000.
8
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
- - ACCOUNTS RECEIVABLE UNRELATED
Accounts receivable are presented net of allowances for doubtful accounts of
$1,224,000 in 2001 and $1,164,000 in 2000.
- - PROPERTY, PLANT, AND EQUIPMENT
The following table provides year-end balances of the major classifications
of our property, plant, and equipment, which we record at cost:
<Table>
<Caption>
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(THOUSANDS OF DOLLARS)
UTILITY PLANT:
Electric:
Generation (including our share of jointly
owned)......................................... $ 53,922 $ 54,477
Transmission..................................... 414,886 412,885
Distribution..................................... 629,296 604,070
Other............................................ 136,740 135,477
Natural Gas:
Production and storage........................... 72,616 71,681
Transmission..................................... 173,751 167,416
Distribution..................................... 154,451 151,039
Other............................................ 38,882 39,841
Other............................................ 6,203 6,265
---------- ----------
Total Utility.................................. 1,680,747 1,643,151
Less: Accumulated depreciation and
amortization................................... 589,512 553,822
---------- ----------
Total Property, Plant, and Equipment, net of
accumulated depreciation and amortization.... $1,091,235 $1,089,329
========== ==========
</Table>
We capitalize the cost of plant additions and replacements, including an
allowance for funds used during construction (AFUDC) of utility plant. We
determine the rate used to compute AFUDC in accordance with a formula
established by FERC. This rate averaged 6.1 percent for 2001, 8.6 percent for
2000, and 7.1 percent for 1999.
We charge costs of utility depreciable units of property retired, plus costs
of removal less salvage, to accumulated depreciation and recognize no gain or
loss. We charge maintenance and repairs of plant and property, as well as
replacements and renewals of items determined to be less than established units
of plant, to operating expenses.
Included in the plant classifications are utility plant under construction
in the amounts of $13,493,000 and $2,637,000 for 2001 and 2000, respectively.
We record provisions for depreciation at amounts substantially equivalent to
calculations made on straight-line and unit-of-production methods by applying
various rates based on useful lives of properties determined from engineering
studies and production as a percentage of the beginning of the
9
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
year reserves. As a percentage of the depreciable utility plant at the beginning
of the year, our provision for depreciation of utility plant was approximately
3.4 percent for 2001, 3.5 percent for 2000, and 3.0 percent for 1999.
- - JOINTLY OWNED ELECTRIC PLANT
Prior to the December 17, 1999 sale of the electric generating assets
discussed in Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of
Electric Generating Assets," we were a joint-owner of Colstrip Units 1, 2, and
3. We owned 50 percent of Units 1 and 2 and 30 percent of Unit 3. We continue to
own a leasehold interest in 30 percent of Colstrip Unit 4. We also own an
approximate 30-percent interest in the transmission facilities serving these
units. At December 31, 2001, our investment in these facilities was $132,331,000
and the related accumulated depreciation was $48,103,000.
Each joint-owner provides its own financing. Our share of direct expenses
associated with the operation and maintenance of these joint facilities,
including Colstrip Units 1, 2, and 3 through December 17, 1999, is included in
the corresponding operating expenses in the Combined Statement of Income.
- - REVENUE AND EXPENSE RECOGNITION
We record operating revenues monthly on the basis of consumption or services
rendered. To match revenues with associated expenses, we accrue unbilled
revenues for electric and natural services delivered to customers but not yet
billed at month-end.
The Emerging Issues Task Force (EITF) Issue No. 98-10 requires that energy
contracts entered into under "trading activities" be marked to market with the
gains or losses shown net in the income statement. EITF 98-10 became effective
for fiscal years beginning after December 15, 1998. We adopted EITF 98-10 as of
January 1, 1999, and accordingly mark to market energy contracts that qualify as
"trading activities." The cumulative effect of adopting EITF 98-10 had no
material effect on our combined financial position, results of operations, or
cash flows.
- - INTANGIBLES
Intangibles at December 31, 2001 and 2000 consisted of $8,559,000 of
goodwill. The associated accumulated amortization was $1,141,000 and $571,000 at
December 31, 2001 and December 31, 2000, respectively. The excess of the
January 2000 purchase price over the net assets of One Call Locators, Ltd., was
recorded as goodwill. See Note 13, "New Accounting Pronouncements," for
information regarding the implementation of SFAS No. 142, "Goodwill and Other
Intangibles."
- - REGULATORY ASSETS AND LIABILITIES
For our regulated operations, we follow SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." Pursuant to this pronouncement, certain
expenses and credits, normally reflected in income as incurred, are recognized
when included in rates and recovered from or refunded to the customers.
Accordingly, we have recorded the following major classifications of regulatory
assets and
10
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
liabilities that will be recognized in expenses and revenues in future periods
when the matching revenues are collected or refunded.
<Table>
<Caption>
DECEMBER 31,
-----------------------------------------------
2001 2000
---------------------- ----------------------
ASSETS LIABILITIES ASSETS LIABILITIES
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
Income Taxes........................................ $ 27,280 $ -- $ 58,452 $ --
Colstrip Unit 3 carrying charge..................... 38,337 -- 38,337 --
Conservation programs............................... 27,956 -- 27,956 --
Competitive transition charges (CTCs)............... 47,487 -- 50,965 --
Generation net proceeds in excess of book value..... -- 223,423 -- 214,887
Proceeds from oil and natural gas sale.............. -- 33,426 -- 32,549
Investment tax credits.............................. -- 12,718 -- 13,163
Other............................................... 76,402 29,555 40,384 18,816
-------- -------- -------- --------
Subtotal.......................................... 217,462 299,122 216,094 279,415
Less:
Current portions.................................. 14,157 24,596 13,237 34,979
-------- -------- -------- --------
Total............................................... $203,305 $274,526 $202,857 $244,436
======== ======== ======== ========
</Table>
Income taxes reflect the effects of temporary differences that we will
recover in future rates. In August 1985, the PSC issued an order allowing us to
recover deferred carrying charges and depreciation expenses over the remaining
life of Colstrip Unit 3. These recoveries compensated us for unrecovered costs
of our investment for the period from January 10, 1984 to August 29, 1985, when
we placed the plant in service. We were amortizing this asset to expense and
recovering in rates $1,831,000 per year. Conservation programs represent our
Demand Side Management programs, which are in rate base and which we were
amortizing to income over a 10-year period. We are recovering the CTCs, which
relate to natural gas properties that we removed from regulation on November 1,
1997, through rates over 15 years. Investment tax credits and account balances
included in "Other" represent items that we are amortizing currently or are
subject to future regulatory confirmation. For information regarding the
proceeds from the oil and natural gas sale, see Note 2, "Deregulation,
Regulatory Matters, and 1999 Sale of Electric Generating Assets," under the
"Natural Gas Rates" section.
Regulatory assets and liabilities related to the generation assets formerly
owned by the Company were included in its filing with the PSC to address
stranded costs. These amounts offset the gain realized on the sale of the
generation assets in the determination of net stranded costs. Amortization of
these assets stopped in February 2000 when they were removed from rates. For
further information on the effects of the sale of our electric generating
assets, see Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of Electric
Generating Assets."
- - STORM DAMAGE AND ENVIRONMENTAL REMEDIATION COSTS
When losses from costs of storm damage and environmental remediation
obligations for our utility operations are probable and reasonably estimable, we
charge these costs against established, approved operating reserves. The
reserves' balance was approximately $8,881,000 at December 31, 2001 and
11
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
approximately $11,080,000 at December 31, 2000. We have included these reserves
on the Combined Balance Sheet in "Other current liabilities."
- - INCOME TAXES
Prior to the February 15, 2002 sale of our utility operations to
NorthWestern, we were included in a consolidated United States income tax return
filed by MPC. MPC allocates consolidated United States income taxes to utility
and nonutility operations as if MPC filed separate United States income tax
returns for each operation. Any differences between taxes calculated on a stand
alone basis and total taxes on a consolidated basis were recognized by MPC. We
defer income taxes to provide for the temporary differences between the
financial reporting basis and the tax basis of our assets and liabilities. For
further information on income taxes, see "Regulatory Assets and Liabilities"
mentioned above and Note 4, "Income Tax Expense."
- - DEFERRED REVENUES
We defer revenues to account for the timing differences between cash
received and revenues earned and reflect these amounts on the Combined Balance
Sheet in "Deferred revenue." We reflect the current portion of these amounts in
"Other current liabilities" on the Combined Balance Sheet. We are recognizing a
prepayment received in December 1999 from the Los Angeles Department of Water
and Power in revenues over the original term of the agreement, approximately
11 years.
- - OTHER INCOME--NET
The following table provides the components of other income--net:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
Interest income............................................. $(2,699) $(14,547) $(3,686)
Other....................................................... 1,344 66 1,119
------- -------- -------
$(1,355) $(14,481) $(2,567)
======= ======== =======
</Table>
Other includes gains and losses from the disposition of assets, income and
expenses from non-regulated activities, and various other items.
- - ASSET IMPAIRMENT
In accordance with SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of," we periodically
review long-lived assets for impairment whenever events or changes in
circumstances indicate that we may not recover the carrying amount of an asset.
- - COMPREHENSIVE INCOME
Comprehensive income consists of net income (loss) and other comprehensive
income (loss). For the years ended December 31, 2001 and 2000, other
comprehensive loss consisted of marked to market
12
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
adjustments related to derivative financial instruments, loss on a benefit
restoration plan, and foreign currency translation adjustments of the assets and
liabilities of Canadian-Montana Pipe Line Corporation (CMP). These amounted to a
decrease to other equity of approximately $410,000 and $1,695,000, respectively.
For the year ended December 31, 1999, our only item of other comprehensive
income was foreign currency translation adjustments related to CMP amounting to
approximately $63,000.
The accumulated balance of other comprehensive income (loss) at
December 31, 2001 and 2000, was $2,086,000 and $1,676,000, respectively.
- - DERIVATIVE FINANCIAL INSTRUMENTS
ELECTRIC SWAP AGREEMENTS
Long-term power supply agreements, primarily one with a large industrial
customer, exposed us to commodity price risk. We were exposed to this risk to
the extent that a portion of the electric energy we were required to sell to our
industrial customers at fixed rates was purchased at prices indexed to a
wholesale electric market, which can be higher than the fixed sales rate that we
received pursuant to our power supply agreements. We mitigated our exposure to
losses on these agreements with financial derivative instruments called "price
swaps" and offsetting electric energy purchase and sales agreements.
Since June 1998, we have had a price swap agreement with one of our
industrial customers that converts 43 MWs of the Mid-Columbia (Mid-C) index
price of our supply agreement with that customer to a fixed price through
May 2001. In fiscal year 2000, we also entered into another price swap with a
counterparty that effectively hedged 35 MWs of the anticipated market-based
purchases to supply that agreement through March 2001.
Prior to fiscal year 2001, in accordance with the provisions of SFAS
No. 80, "Accounting for Futures Contracts," we recognized gains and losses from
the financial swaps in the same period in which we recognized the sales and
related purchases under that agreement. For fiscal year 2000, we recognized a
net gain of approximately $16,000,000 from these financial swaps and losses of
approximately $32,200,000 from supplying large industrial customers. For more
specific information about the commodity price risk that we face as a result of
our long-term power supply agreements, see Note 11, "Contingencies," in the
"Long-Term Power Supply Agreements" section.
An estimate of the fair market value of the swaps based on the Mid-C forward
prices as of December 29, 2000 aggregated a gain of approximately $21,800,000 as
of December 31, 2000, which would offset approximately 40 percent of the
expected losses on the above power supply agreements.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Transactions and Hedging Activities." These
pronouncements expand the definition of a derivative and require that all
derivative instruments be recorded as assets or liabilities on an entity's
balance sheet at fair value. Accounting for gains and losses resulting from
changes in the fair value of those derivatives is dependent on the use of the
derivative and whether it qualifies for hedge accounting.
At January 1, 2001, we had price swap agreements that hedged our exposure to
variability in expected cash flows attributable to commodity price risk.
Specifically, long-term power supply
13
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
agreements, primarily one with a large industrial customer, expose us to that
risk, to the extent that a portion of the electric energy we are required to
sell to our industrial customers at fixed rates is purchased at prices indexed
to the Mid-Columbia (Mid-C) wholesale electric market, which can be higher than
the fixed sales rates. Another agreement to sell 1,760,000 dekatherms of natural
gas storage at a monthly price based on the Alberta Energy Company "C" Hub
(AECO-C) index, from October 2000 to March 2001, exposed us to adverse
fluctuation in that market price index. In accordance with the provisions of
SFAS No. 133, we marked to market at January 1, 2001 our price swap agreements
hedging these forecasted electric energy and natural gas sales, with a
corresponding credit entry to "Other comprehensive income" for approximately
$11,300,000 after income taxes. That entry represented our cumulative transition
adjustment in adopting SFAS No. 133, and is reflected in the Combined Statement
of Other Equity in 2001.
For the first seven months of 2001, we were exposed to commodity price risk
because a portion of the electric energy we were required to sell at fixed rates
to industrial customers was purchased at prices indexed to a wholesale electric
market, which could be and was higher than the fixed sales rate. We used
derivative financial instruments called "price swaps" and offsetting electric
energy purchase and sales agreements to hedge our exposure to losses on these
power supply agreements with large industrial customers.
For the year ended December 31, 2001, the electric energy sales resulted in
an after-tax loss of $25,300,000, and the price swaps hedging those sales in an
after-tax gain of approximately $7,200,000. At December 31, 2001, we did not
have agreements to purchase electric energy for sales to industrial customers or
power marketers, nor did we have financial derivative agreements to hedge such
transactions.
NATURAL GAS UTILITY SWAPS
By drilling wells and adding compression at our Cobb storage reservoir, we
were able to sell natural gas that had been held in reserve to provide firm
storage deliverability to our customers. We therefore contracted to sell, from
October 2000 through March 2001, 1,760,000 dekatherms from that reservoir at a
monthly price based on the Alberta Energy Company "C" Hub (AECO-C) index. To
reduce our exposure to fluctuations of the market index price, we entered into a
swap agreement with a counterparty that effectively converted that index price
to a fixed price for 903,000 dekatherms associated with these sales from
December 2000 through February 2001.
For December 2000, we recognized a loss of approximately $300,000 on the
swap and a profit of approximately $1,200,000 on the sale of the Cobb storage
natural gas. Based on the AECO-C forward prices at December 29, 2000, we
estimated a loss of approximately $3,000,000 on the swap to offset profits of
$4,900,000 on the sale through February 2001. We deferred the net profit of
these transactions in accordance with SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," and will recognize this amount in income as
amounts are reflected in rates.
14
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
- - FAIR VALUE OF FINANCIAL INSTRUMENTS
<Table>
<Caption>
2001 2000
---------------------------- ----------------------------
CARRYING AMOUNT FAIR VALUE CARRYING AMOUNT FAIR VALUE
--------------- ---------- --------------- ----------
(THOUSANDS OF DOLLARS)
ASSETS:
Investments.............................. $ 25,936 $ 25,936 $ 25,901 $ 25,901
LIABILITIES:
Company obligated mandatorily redeemable
preferred securities................... $ 65,000 $ 60,450 $ 65,000 $ 65,000
Long-term debt (including due within one
year).................................. 458,741 454,534 377,179 377,563
</Table>
The following methods and assumptions were used to estimate fair value:
- Investments--The carrying value of most of the investments approximates
fair value as they have short maturities or the carrying value equals
their cash surrender value. The investments consist mainly of the cash
value of insurance policies associated with an unfunded, nonqualified
benefit plan for senior management, executives, and directors and funds
deposited with the trustee of our securitization bonds discussed in
Note 8, "Long-Term Debt."
- Mandatorily redeemable preferred securities and long-term debt--The fair
value was estimated using quoted market rates for the same or similar
instruments. Where quotes were not available, fair value was estimated by
discounting expected future cash flows using year-end incremental
borrowing rates.
NOTE 2--DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING
ASSETS
- - DEREGULATION
The electric and natural gas utility businesses in Montana are transitioning
to a competitive market in which commodity energy products and related services
are sold directly to wholesale and retail customers.
ELECTRIC
Montana's Electric Utility Industry Restructuring and Customer Choice Act
(Electric Act), passed in 1997, provides that all customers will be able to
choose their electric supplier by July 1, 2002, with our electric utility acting
as default supplier through the transition period. As default supplier, we are
obligated to continue to supply electric energy to customers in our service
territory who have not chosen, or have not had an opportunity to choose, other
power suppliers during the transition period. This obligation requires us to
develop an energy supply portfolio to meet these customers' electric needs.
Buyback contracts with PPL Montana, LLC (PPL Montana), the purchaser of our
former electric generating assets, allow us to purchase power necessary to serve
these customers through the transition period ending June 30, 2002.
15
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 2--DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING
ASSETS (CONTINUED)
In its 2001 session, the Montana Legislature passed House Bill 474 (HB 474),
which extends the transition period through June 30, 2007. This law also
provides for the use of a cost-recovery mechanism that ensures all prudently
incurred electric energy supply costs of the default supplier are fully
recoverable in rates. Initiative 117, which if passed would repeal HB 474, has
been approved for inclusion on the November 2002 ballot in Montana. In the event
that HB 474 is repealed, Montana Law would continue the transition period
through at least June 30, 2007, and provide full cost recovery.
On October 29, 2001, we filed with the PSC our default supply portfolio,
containing a mix of long and short-term contracts that we negotiated in order to
provide electricity to default supply customers. This filing seeks approval of
the default supply portfolio contracts and establishment of default supply rates
for customers who have not chosen alternative suppliers by July 1, 2002. We
expect that the costs of the supply portfolio and a competitive transition
charge for out-of-market Qualifying Facility (QF) costs, as discussed below,
will increase residential electric rates by approximately 20 percent beginning
July 1, 2002. As discussed below, this will be offset for one year by a credit
that reduces the increase to 12.8 percent. If the PSC does not approve our
default supply portfolio, we may be required to seek alternative sources of
supply. While we believe that we have met our default supply obligations
prudently, the PSC could also disallow the recovery of costs incurred in
entering into the default supply portfolio if a determination is made that the
contracts were not entered into prudently.
On that same day, we submitted an updated Tier II filing with the PSC,
addressing the recovery of transition costs of generation assets and other
power-purchase contracts, generation-related regulatory asset transition costs,
and transition costs associated with the out-of-market QF power-purchase
contract costs. Previously, we initiated litigation in Montana District Court in
Butte to address our ability to use tracking mechanisms to ensure fair and
accurate recovery of these costs. Although the District Court ruled that the PSC
must allow us to incorporate tracking mechanisms in our transition plan
proposal, the Montana Supreme Court reversed this decision on appeal by the PSC
and the Large Customer Group, which consists of various large industrial
customers. Together with NorthWestern, the Montana Consumer Counsel, Commercial
Energy and the Large Customer Group, on December 28, 2001, we submitted to the
PSC an agreed upon stipulation settling the transition cost recovery in the Tier
II filing and approving our sale to NorthWestern. The stipulation calls for
Montana Power and NorthWestern to establish a $30,000,000 account that will be
used to provide a credit for our electric distribution customers. The credit
will be provided over a one year period to customers on a per kilowatt-hour
(Kwh) basis beginning on July 1, 2002, when our current below market energy
supply contract expires. The credit will reduce a projected 20 percent increase
in electric rates at that time to about 12.8 percent for the next 12 months. The
stipulation also states that customers shall have no obligation to pay any
transition costs accrued under or relating to the accounting orders issued by
the PSC. These accrued transition costs through December 31, 2001, amount to
$23,000,000. Another portion of the stipulation establishes the net present
value (NPV) of out-of-market QF transition costs at $244,711,065, a reduction of
$60,000,000, from the NPV presented in our October 29, 2001 filing. On
January 31, 2002, the PSC unanimously approved the stipulation. The effects of
the stipulation were contingent upon the approval of the PSC and the
consummation of the sale.
16
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 2--DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING
ASSETS (CONTINUED)
NATURAL GAS
Montana's Natural Gas Utility Restructuring and Customer Choice Act, also
passed in 1997, provides that a natural gas utility may voluntarily offer its
customers choice of natural gas suppliers and provide open access. We have
opened access on our gas transmission and distribution systems, and all of our
natural gas customers have the opportunity of gas supply choice.
- - REGULATORY MATTERS
The PSC regulates our transmission and distribution services and approves
the rates that we charge for these services, while FERC regulates our
transmission services and our remaining generation operations. Current
regulatory issues are discussed below.
SALE OF THE UTILITY BUSINESS
Together with NorthWestern, MPC filed joint applications with FERC on
December 20, 2000, and with the PSC on January 11, 2001, seeking approval of the
sale of our utility business to NorthWestern. FERC issued its approval on
February 20, 2001. The PSC issued an order in June 2001 denying the joint
application, claiming that insufficient information had been provided for it to
fully evaluate whether the transaction is in the public interest. The PSC
itemized additional information that must be provided before processing of the
case could continue. MPC re-filed the joint application with the PSC in
August 2001 and the PSC established a procedural schedule setting January 31,
2002 as the date for issuance of an order. As discussed above, together with
NorthWestern, the Montana Consumer Counsel, Commercial Energy, and the Large
Customer Group, on December 28, 2001, we submitted to the PSC an agreed-upon
stipulation relating to the Tier II filing and the approval of our sale to
NorthWestern Corporation. On January 31, 2002, the PSC unanimously approved the
stipulation. The stipulation and the following PSC Order recognized that
NorthWestern sufficiently demonstrated its capability to assume responsibility
for our operations and will continue to be fit, willing and able provider of
adequate service and facilities at just and reasonable rates. The utility
business was sold to NorthWestern on February 15, 2002. For accounting
convenience, due to the burden of a mid-month closing, both parties agreed to an
effective date for the sale as of the opening of business on February 1, 2002.
PENDING TRANSMISSION ASSET SALE
In accordance with our Asset Purchase Agreement with PPL Montana, we expect
to sell our portion of the 500-kilovolt transmission system associated with
Colstrip Units 1, 2, and 3 for $97,100,000, subject to the receipt of required
regulatory approvals. We expect this transaction to close in 2002.
PSC
ELECTRIC RATES
In August 2000, we filed a combined request for increased electric and
natural gas rates with the PSC, requesting increased annual electric
transmission and distribution revenues of approximately
17
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 2--DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING
ASSETS (CONTINUED)
$38,500,000, with a proposed interim annual increase of approximately
$24,900,000. On November 28, 2000, the PSC granted us an interim electric rate
increase of approximately $14,500,000, with hearings on this submission
beginning in January 2001. On May 8, 2001, we received a final order from the
PSC resulting in an annual delivery service revenue adjustment of $16,000,000,
including the $14,500,000 interim increase granted on November 28, 2000.
On June 27, 2001, the PSC issued an order stating that they continue to have
jurisdiction over us as a fully integrated public utility, in spite of the
December 17, 1999 sale of our electric generating facilities. The order requires
that, if we desire a power supply rate change at the end of the rate moratorium
on July 1, 2002, we must make a filing containing information that supports what
rates would be if the regulatory system in place prior to deregulation remained
intact. We filed a motion for reconsideration with the PSC, which was
subsequently denied. We have since filed a complaint against the PSC in Montana
State District Court in Helena, disputing this order. We cannot predict the
ultimate outcome of this matter or its potential effect on our financial
position or results of operation.
NATURAL GAS RATES
As discussed above, in August 2000, we filed a combined request for
increased natural gas and electric rates with the PSC. We requested increased
annual natural gas revenues of approximately $12,000,000, with a proposed
interim annual increase of approximately $6,000,000. On November 28, 2000, the
PSC granted us an interim natural gas rate increase of approximately $5,300,000.
On May 8, 2001, we received a final order from the PSC resulting in an annual
delivery and gas storage service revenue increase of $4,300,000. Because the
amount established in the final order was less than the interim order, we began
including a credit for the difference collected from November 2000 through
May 2001, with interest, in our customers' bills over a six-month period
starting October 1, 2001.
In January 2001, we submitted to the PSC an Annual Gas Cost Tracker
requesting an increase of approximately $51,000,000. At that time, we also
submitted a Compliance Filing for a credit of approximately $32,500,000
associated with a sharing of the proceeds from the sale of gathering and
production properties previously included in the natural gas utility's rate
base. As a result, effective February 1, 2001, we began collecting a net amount
of approximately $18,500,000 in revenues over a one-year period. In
September 2001, after all testimony addressing the amount of sharing had been
filed with the PSC, we reached an agreement with intervening parties to increase
the amount of the credit to approximately $56,300,000. This $23,800,000
increase, along with approximately $5,300,000 in interest from the date of sale,
was charged to expense during 2001 and will be credited to customers' bills over
a two-year period beginning January 1, 2002.
On December 7, 2001, we filed our Annual Gas Cost Tracker request with the
PSC for the tracking year beginning November 1, 2001.
FERC
Through a filing with FERC in April 2000, we are seeking recovery of
transition costs associated with serving two wholesale electric cooperatives. A
FERC decision on this filing, which corresponds with our transition-costs
recovery proceedings with the PSC in Montana, has been on hold pending a PSC
Tier II order. On January 29, 2002, the Montana PSC approved a stipulation
settling transition
18
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 2--DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING
ASSETS (CONTINUED)
cost recovery for retail customers in Montana. Discussions with the wholesale
electric cooperatives involved in the FERC filing are expected to resume in the
near future.
- - 1999 SALE OF ELECTRIC GENERATING ASSETS
ASSETS SOLD
On December 17, 1999, in accordance with the Asset Purchase Agreement
entered into with PPL Montana, MPC sold substantially all of our electric
generating assets and related contracts. MPC also sold an immaterial amount of
associated transmission assets, totaling less than 40 miles. The asset sale did
not include the Milltown Dam near Missoula, Montana (gross capacity of
approximately 3 MWs) or any of our QF purchase-power contracts. It also did not
include our leased share of the Colstrip Unit 4 generation or transmission
assets.
As expected, the sale of our electric generating assets in December 1999
reduced the utility's net income for 2000. Utility revenues decreased because of
discontinued off-system revenues that related to the electric generating assets
sold. In addition, we no longer earn a return on our shareholders' investment in
the electric generating assets. Before the sale, revenues covered the costs of
operating the generating plants, taxes and interest, and earned a return on our
shareholders' investment. Since the sale, we continue to bill our core customers
for energy supply, but now these revenues recover the costs of the power that we
purchase to serve these customers. The energy that we formerly generated and
sold to core customers is now purchased pursuant to buyback contracts. The
maximum price that we pay for power in the buyback contracts, $22.25/MWh,
represents our net fully allocated supply costs of service in current rates,
replacing operations and maintenance expense, property tax expense, depreciation
expense, and return on investment associated with the electric generating
assets.
In the sale of these assets, we generally retained all pre-closing
obligations, and the purchaser generally assumed all post-closing obligations.
However, with respect to environmental liabilities, the purchaser assumed all
pre-closing (with certain limited exceptions) and post-closing environmental
liabilities associated with the purchased assets.
While the purchaser assumed pre-closing environmental liabilities, we agreed
to indemnify the purchaser from these pre-closing environmental liabilities,
including a limited indemnity obligation for losses arising from required
remediation of pre-closing environmental conditions, whether known or unknown at
the closing, limited to:
- 50 percent of the loss. (Our share of this indemnity obligation at the
Colstrip Project is limited to our pro-rata share of this 50 percent based
on our pre-sale ownership share.)
- A two-year period after closing for unknown conditions. The indemnity for
required remediation of pre-closing conditions known at the time of the
closing continues indefinitely.
- An aggregate amount no greater than 10 percent of the purchase price paid
for the assets.
We have received claim notices related to this indemnity obligation. Based
on available information, we do not expect this indemnity claim on the indemnity
obligation to have a material adverse effect on our combined financial position,
results of operations, or cash flows.
19
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 2--DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING
ASSETS (CONTINUED)
CASH PROCEEDS
At December 31, 1999, we recorded a regulatory liability and related
deferred income tax to reflect the generation sale proceeds in excess of book
value. The Company's liability, which was determined in the Tier II docket, is
approximately $250,000,000 before income taxes. This liability represents a
deferral of the gain on the generation sale and nothing has been reflected in
the Statement of Income.
As part of our Tier II filing, we deducted from the regulatory liabilities
approximately $15,000,000 of other after-tax generation-related transition costs
and approximately $65,600,000 of regulatory asset transition costs. The other
generation-related transition costs consist mainly of environmental costs and
costs to retire debt. The regulatory asset transition costs consist mainly of
capitalized conservation costs and carrying charges associated with Colstrip
Unit 3.
We have used a portion of the net cash proceeds received (excluding the
proceeds in excess of book value) to purchase treasury shares of MPC's common
stock, to reduce debt, and to fund projects involving expansion of Touch
America, a wholly owned subsidiary of MPC.
EFFECT ON 1999 EARNINGS
The asset sale affected positively our electric utility's 1999 earnings
through the reversal of approximately $3,000,000 (after taxes) in interest
expense recorded in prior years relating to Kerr Project liabilities and through
recognition of approximately $10,000,000 in Investment Tax Credits.
NOTE 3--RELATED PARTY TRANSACTIONS
- - COAL PURCHASES AND TRANSPORTATION
We purchased significant quantities of coal from Western Energy, which was a
subsidiary of MPC through April 2001, under two long-term purchase coal
contracts. We also had a long-term contract with Western Energy to transport
some of this coal. Purchases under these contracts were $3,456,000, $10,372,000,
and $39,729,000 for the years ending December 31, 2001, 2000, and 1999,
respectively. As a result of the December 1999 sale of substantially all of our
electric generating assets, long-term coal purchase contracts associated with
Colstrip Units 1, 2, and 3 were transferred to PPL Montana.
- - SALES OF ELECTRICITY
We sold electric energy to Western Energy primarily for use in the
operations of their Rosebud mine in Colstrip, Montana. Prior to the April 30,
2001 sale of MPC's former coal operations, these related sales amounted to
approximately $1,100,000 for the year ended December 31, 2001, and approximately
$3,300,000 per year for the years ended December 31, 2000 and 1999.
- - OIL AND NATURAL GAS PURCHASES
We purchased natural gas through October 2000 from MP Gas, MPC's former
subsidiary. Total purchases from MP Gas were $11,561,000 and $16,651,000 for the
years ending December 31, 2000 and 1999, respectively.
20
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 3--RELATED PARTY TRANSACTIONS (CONTINUED)
- - MPT&M ELECTRIC SALES
Prior to the December 1999 electric generating asset sale, we sold excess
electric energy to The Montana Power Trading & Marketing Company (MPT&M). MPT&M
then sold the excess energy in the secondary markets. Sales were approximately
$59,200,000 for the year ended December 31, 1999.
- - INTEREST INCOME & EXPENSE
During 2001, 2000, and 1999, we earned approximately $1,576,000, $2,639,000,
and $1,547,000, respectively, of interest income from outstanding notes
receivable with MPC's nonutility subsidiaries. We also incurred interest expense
of approximately $2,063,000, $2,748,000, and $7,014,000 for the same periods
from outstanding notes payable with MPC's nonutility subsidiaries.
- - RECEIVABLES AND PAYABLES
Related party receivables primarily result from either services we provide
to, or payments we make on behalf of, MPC's nonutility subsidiaries. Related
party payables primarily result from services that we receive from MPC's
nonutility subsidiaries.
<Table>
<Caption>
DECEMBER 31,
-------------------
2001 2000
-------- --------
(THOUSANDS OF
DOLLARS)
Accounts receivable:
Entech.................................................... $ 439 $17,030
Telecommunications........................................ 41,406 39,065
Oil and Gas............................................... -- --
Coal...................................................... -- 20,343
Continental Energy Services............................... -- 445
------- -------
$41,845 $76,883
Notes receivable:
Entech.................................................... -- 48,596
Continental Energy Services............................... -- 2,267
------- -------
$ -- $50,863
Accounts payable:
Entech.................................................... 559 73,509
Telecommunications........................................ 39,424 2,180
Oil and Gas............................................... -- --
Coal...................................................... -- 1,798
Continental Energy Services............................... -- --
------- -------
$39,983 $77,487
Short-term borrowing:
Continental Energy Services............................... $ -- $49,372
</Table>
21
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 4--INCOME TAX EXPENSE
Income (loss) before income taxes was as follows:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
United States.......................................... $(47,072) $(12,794) $81,937
</Table>
Income tax expense (benefit) as shown in the Combined Statement of Income
consists of the following components:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
Current:
United States....................................... $(20,998) $ 102 $193,192
Canada.............................................. 24 16 17
State............................................... 3,170 (2,216) 39,186
-------- -------- --------
(17,804) (2,098) 232,395
-------- -------- --------
Deferred:
United States..................................... 12,319 (16,625) (183,546)
Canada............................................ -- -- --
State............................................. 1,411 (876) (34,954)
-------- -------- --------
13,730 (17,501) (218,500)
-------- -------- --------
$ (4,074) $(19,599) $ 13,895
======== ======== ========
</Table>
The provision (benefit) for income taxes differs from the amount of income
tax determined by applying the applicable U. S. statutory federal rate to pretax
income as a result of the following differences:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
Computed "expected" income tax expense (benefit)....... $(16,475) $ (4,478) $ 28,678
Adjustments for tax effects of:
Tax credits.......................................... (445) (167) (20,489)
State income tax, net................................ 4,627 (5,089) 1,342
Reversal of utility book/tax depreciation............ 5,026 3,771 5,399
Federal credits...................................... -- (7,309) --
Resolution of tax contingencies...................... -- (4,284) --
Other................................................ 3,193 (2,043) (1,035)
-------- -------- --------
Actual income tax expense (benefit).................... $ (4,074) $(19,599) $ 13,895
======== ======== ========
</Table>
Under Montana regulations, certain tax benefits flow through to customers on
a basis consistent with the accelerated deduction of expenses for income tax
purposes. As such, when these expenses are recognized for financial reporting
purposes, there is not an offsetting tax savings. During periods of
22
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 4--INCOME TAX EXPENSE (CONTINUED)
income, our utility's effective tax rate is higher than the statutory rate due
to this timing difference. During periods of losses, tax benefits will appear
lower than expected.
Deferred tax liabilities (assets) are comprised of the following at
December 31:
<Table>
<Caption>
2001 2000
--------- ---------
(THOUSANDS OF
DOLLARS)
Plant related............................................... $ 203,578 $ 227,980
Other....................................................... 37,854 36,771
--------- ---------
Gross deferred tax liabilities............................ 241,432 264,751
Amortization of gain on sale/leaseback...................... (9,409) (10,969)
Investment tax credit amortization.......................... (8,265) (14,056)
Electric Generation Sale.................................... (101,430) (98,557)
Income Stabilization Adjustments............................ (15,345) (40,738)
Other....................................................... (63,297) (36,481)
--------- ---------
Gross deferred tax assets................................. (197,746) (200,801)
Net deferred tax liabilities.............................. $ 43,686 $ 63,950
========= =========
</Table>
The change in net deferred tax liabilities differs from current year 2001
deferred tax expense as a result of the following:
<Table>
<Caption>
THOUSANDS
OF DOLLARS
----------
Change in deferred tax...................................... $(20,264)
Regulatory assets related to income taxes................... 27,513
Benefit restoration plan equity adjustment.................. 1,022
Pension plan equity adjustment.............................. 5,904
Amortization of investment tax credits...................... (445)
--------
Deferred tax expense...................................... $ 13,730
========
</Table>
23
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 5--PREFERRED STOCK
At December 31, 2001, MPC had 5,000,000 authorized shares of preferred
stock. MPC's preferred stock is in three series as detailed in the following
table:
<Table>
<Caption>
SHARES ISSUED THOUSANDS
STATED AND AND OUTSTANDING OF DOLLARS
LIQUIDATION ------------------- -------------------
SERIES PRICE* 2001 2000 2001 2000
- ------ ----------- -------- -------- -------- --------
$6.875................................ $100 360,800 360,800 $36,080 $36,080
6.00 ................................ 100 159,589 159,589 15,959 15,959
4.20 ................................ 100 60,000 60,000 6,025 6,025
Discount.............................. -- -- (410) (410)
------- ------- ------- -------
580,389 580,389 $57,654 $57,654
======= ======= ======= =======
</Table>
- ------------------------
* Plus accumulated dividends.
At a special meeting of MPC shareholders held on September 21, 2001,
shareholders representing more than two-thirds of MPC's outstanding common stock
approved (among others) the following proposals:
- Holders of Preferred Stock, $6.875 Series, of MPC will receive one share
of Touch America Holdings, Inc. Preferred Stock, $6.875 Series, for each
share of MPC Preferred Stock.
- The redemption of MPC's outstanding Preferred Stock, $4.20 Series, and
Preferred Stock, $6.00 Series.
Responsibility for the preferred stock has reverted to Touch America with
the February 15, 2002 sale of the utility to NorthWestern. On February 15, 2002,
Touch America called its $6.00 Series and $4.20 Series preferred stock at $110
per share and $103 per share, respectively, plus accumulated dividends. As of
February 22, 2002, no redemption has occurred. Touch America's $6.875 Series
preferred stock is redeemable in whole or in part with the consent or
affirmative vote of the holders of a majority of the common shares, at any time
on or after November 1, 2003, for a price beginning at $103.438 per share, which
decreases annually through October 2013. After that time, the redemption price
is $100 per share.
Touch America cannot declare or pay dividends on its common stock while it
has not either declared and set apart cumulative dividends or paid dividends on
any of its preferred stock.
24
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 6--OTHER EQUITY
- - LLC UNITS
Our LLC units represent the MPLLC included in the sale to NorthWestern. The
MPLLC consists of the former utility operations of MPC and MPC's wholly owned
subsidiaries Canadian-Montana Pipe Line Corporation, Montana Power Capital I,
Montana Power Natural Gas Funding Trust, Colstrip Community Services Company,
One Call Locators, Ltd., Discovery Energy Solutions, Inc., and Montana Power
Services Company. Prior to the February 15, 2002 sale of the utility business to
NorthWestern, other equity represented the equity of MPC.
- - RETIREMENT SAVINGS PLAN
MPC has a 401(k) Retirement Savings Plan that covers eligible employees. MPC
contribute, on behalf of the employee, a matching percentage of the amount
contributed to the Plan by the employee. In 1990, MPC borrowed $40,000,000 at an
interest rate of 9.2 percent to be repaid in equal annual installments over
15 years. The loan was issued under similar terms to the Plan Trustee, which
used the proceeds to purchase 3,844,594 shares of MPC's common stock. Shares
acquired with loan proceeds are allocated monthly to Plan participants to help
meet MPC's matching obligation. The loan, which is reflected as long-term debt
(ESOP Notes Payable), is offset by a similar amount in other equity as
unallocated stock. MPC's contributions plus the dividends on the shares held
under the Plan are used to meet principal and interest payments on the loan with
the Plan Trustee. Historically, as principal payments on the loan are made,
long-term debt and the offset in common shareholders' equity were both reduced
on MPC's financial statements. At December 31, 2001, 3,012,646 shares had been
allocated to the participants' accounts. MPC recognized expense for the Plan
using the Shares Allocated Method, and the pretax expense was $3,385,000,
$2,570,000, and $3,768,000 for 2001, 2000, and 1999, respectively.
On February 15, 2002, MPC retired the ESOP notes. For more information
regarding the ESOP notes, see Note 8, "Long-Term Debt."
The ESOP Plan was transferred to Touch America prior to the sale of the
utility business to NorthWestern. The utility no longer maintains an employee
stock ownership plan.
- - LONG-TERM INCENTIVE PLAN
Under the Long-Term Incentive Plan, MPC has issued options to our employees.
Options issued to employees are not reflected in balance sheet accounts until
exercised, at which time: (1) authorized, but unissued shares are issued to the
employee; (2) the capital stock account is credited with the proceeds; and
(3) no charges or credits to income are made. Although these options were
vested, all options related to the utility employees were cancelled upon the
sale of the utility business to NorthWestern.
Options were granted at the average of the high and low prices of MPC stock
as reported on the New York Stock Exchange composite tape on the date granted
and expire ten years from that date.
25
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 6--OTHER EQUITY (CONTINUED)
MPC option activity is summarized below:
<Table>
<Caption>
2001 2000 1999
-------------------- -------------------- --------------------
WTD AVG WTD AVG WTD AVG
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- --------- --------
Outstanding, beginning of
year...................... 4,076,244 $28.43 3,280,325 $25.63 2,548,094 $22.71
Granted................... 35,500 17.38 1,199,545 34.36 919,510 32.14
Exercised................. 32,984 13.49 149,834 17.07 88,857 10.83
Cancelled................. 1,051,313 27.75 253,792 26.88 98,422 24.08
--------- ------ --------- ------ --------- ------
Outstanding, end of year.... 3,027,447 $28.70 4,076,244 $28.43 3,280,325 $25.63
========= ====== ========= ====== ========= ======
</Table>
MPC shares under option at December 31, 2001, are summarized below:
<Table>
<Caption>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------- --------------------
WTD AVG WTD AVG WTD AVG
EXERCISE EXERCISE EXERCISE
EXERCISE PRICE RANGE SHARES PRICE LIFE SHARES PRICE
- -------------------- --------- -------- -------- --------- --------
$6.45................................. 6,000 $ 6.45 10 yrs -- $ --
$10.73 to $14.29...................... 154,725 11.11 4 yrs 148,725 11.08
$18.00 to $24.66...................... 399,929 19.60 7 yrs 317,446 18.62
$26.53 to $32.50...................... 1,689,863 28.72 8 yrs 1,194,039 27.67
$35.36 to $38.69...................... 776,930 37.00 8 yrs 394,930 35.36
--------- ---------
3,027,447 2,055,140
========= =========
</Table>
As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," MPC
has elected to follow Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" (APB 25), and related interpretations in
accounting for MPC employee stock options. Under APB 25, because the exercise
price of the employee stock options equals the market price of the underlying
stock on the date of grant, no compensation expense is recognized. Disclosure of
pro-forma information regarding net income and earnings per share is required by
SFAS No. 123. This information has been determined as if MPC had accounted for
employee stock options under the fair value method of that statement. The
weighted-average fair value of options granted in 2001, 2000, and 1999 was
$10.23, $16.35, and $7.03 per share, respectively. MPC employed the binomial
option-pricing model to estimate the fair value of each option grant on the date
of grant. MPC used the following weighted-average assumptions for grants in
2001, 2000, and 1999, respectively: (1) risk-free interest rate of
5.07 percent, 6.05 percent, and 6.35 percent; (2) expected life of 7.0, 6.2, and
9.8 years; (3) expected volatility of 51.00 percent, 42.00 percent, and
24.92 percent; and (4) a dividend yield of zero percent, zero percent, and
5.97 percent. Had MPC elected to use SFAS No. 123, MPC's compensation expense
would have increased $10,904,000 in 2001, $11,827,000 in 2000, and $5,280,000 in
1999, a portion of which would have been allocated to the utility.
26
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 7-- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST
MPC established Montana Power Capital I (Trust) as a wholly owned business
trust to issue common and preferred securities and hold Junior Subordinated
Deferrable Interest Debentures (Subordinated Debentures) that we issue. At
December 31, 2001 and 2000, the Trust had issued 2,600,000 units of
8.45 percent Cumulative Quarterly Income Preferred Securities, Series A (QUIPS).
Holders of the QUIPS are entitled to receive quarterly distributions at an
annual rate of 8.45 percent of the liquidation preference value of $25 per
security. The sole asset of the Trust is $67,000,000 of our Subordinated
Debentures, 8.45 percent Series due 2036. The Trust will use interest payments
received on the Subordinated Debentures that it holds to make the quarterly cash
distributions on the QUIPS. The QUIPS' $65,000,000 liquidation value is included
with Other Long-Term Debt on the Combined Balance Sheet.
Since November 6, 2001, we can wholly redeem the Subordinated Debentures at
any time, or partially redeem the Subordinated Debentures from time to time. We
also can wholly redeem the Subordinated Debentures if certain events occur
before that time. Upon repayment of the Subordinated Debentures at maturity or
early redemption, the Trust Securities must be redeemed. In addition, we can
terminate the Trust at any time and cause the pro rata distribution of the
Subordinated Debentures to the holders of the Trust Securities.
Besides our obligations under the Subordinated Debentures, we have agreed to
certain Back-up Undertakings. We have guaranteed, on a subordinated basis,
payment of distributions on the Trust Securities, to the extent the Trust has
funds available to pay such distributions. We also have agreed to pay all of the
expenses of the Trust. Considered together with the Subordinated Debentures, the
Back-up Undertakings constitute a full and unconditional guarantee of the
Trust's obligations under the QUIPS. We are the owner of all the common
securities of the Trust, which constitute 3 percent of the aggregate liquidation
amount of all the Trust Securities.
NOTE 8--LONG-TERM DEBT
The Mortgage and Deed of Trust (Mortgage) imposes a first mortgage lien on
all physical properties owned, exclusive of subsidiary company assets and
certain property and assets specifically excepted. The obligations
collateralized are First Mortgage Bonds, including those First Mortgage Bonds
designated as Secured Medium-Term Notes (MTNs) and those securing Pollution
Control Revenue Bonds.
27
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 8--LONG-TERM DEBT (CONTINUED)
Long-term debt consists of the following:
<Table>
<Caption>
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(THOUSANDS OF DOLLARS)
First Mortgage Bonds:
7% series, due 2005....................................... $ 5,386 $ 5,386
7.30% series, due 2006.................................... 150,000 --
8 1/4% series, due 2007................................... 365 365
8.95% series, due 2022.................................... 1,446 1,446
Secured Medium-Term Notes--maturing 2000-2025
7.20%-8.11%............................................. 28,000 28,000
Pollution Control Revenue Bonds:
City of Forsyth, Montana
6 1/8% series, due 2023................................. 90,205 90,205
5.90% series, due 2023.................................. 80,000 80,000
Unsecured Medium-Term Notes Series B--maturing 2001-2026
7.20%-8.11%............................................... 40,000 100,000
Natural Gas Transition Bonds--6.20%, due 2012............... 54,250 58,412
ESOP Notes Payable--9.20%, due 2004......................... 12,666 16,197
Capital Leases.............................................. 11 26
Unamortized Discount and Premium............................ (3,588) (2,859)
-------- --------
458,741 377,178
Less: Portion due within one year........................... 16,061 67,715
-------- --------
$442,680 $309,463
======== ========
</Table>
On November 27, 2001, we issued $150,000,000 of our 7.3 percent series First
Mortgage Bonds (Bonds) due December 1, 2006. The net proceeds from the sale of
the bonds were used to repay outstanding short-term debt and for general
corporate purposes. In addition, we retired the 9.20 percent ESOP notes on
February 15, 2002 with a portion of the proceeds. The entire $12,666,000
outstanding balance of ESOP notes is shown as due within one year in the above
table.
On April 6, 2001, we retired $60,000,000 of our variable rate Series B
Unsecured Medium Term Notes at maturity.
The electric and natural gas legislation discussed in Note 2, "Deregulation,
Regulatory Matters, and 1999 Sale of Electric Generating Assets" authorized the
issuance of transition bonds. These securitization bonds involve the issuance of
a non-recourse debt instrument. The bonds are repaid through, and secured by, a
specified component of future revenues meant to recover the regulatory assets,
thereby reducing the credit risk of the securities. This specific component of
revenues is referred to as a CTC. An April 1998 PSC Financing Order relating to
natural gas approved the issuance of up to $65,000,000 of such bonds. We
established a special purpose entity (SPE), which is a wholly owned subsidiary,
to issue the bonds. In December 1998, we issued $62,700,000 of 6.2 percent
bonds. We will retire these bonds at six-month intervals from September 15,
1999, through March 15, 2012. Retirements are in varying amounts depending on
revenues collected from customers. At December 31,
28
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 8--LONG-TERM DEBT (CONTINUED)
2001, approximately $54,250,000 was outstanding, of which approximately
$3,384,000 was classified as due within one year in the above table.
Although the bonds were issued by an SPE and are without recourse to our
general credit, the bonds are included on the Combined Balance Sheet. Similarly,
the right to receive the revenues pledged to secure the bonds is a specific
right of the SPE and not of Montana Power. However, as a wholly owned
subsidiary, the SPE's revenues and expenses are included in the Combined
Statement of Income. Due to the regulatory mechanism for recognizing the
operations of the SPE, including the amortization of the regulatory assets, we
do not expect it to have a material effect on our consolidated financial
position, results of operations, or cash flows.
To ensure that collections by the SPE are neither more nor less than the
amount necessary to pay interest, principal, and other related issuance costs,
we are required to file for periodic adjustments, or reconciliations, to the
annual amounts to be collected by the SPE. The PSC is required to approve these
adjustments.
Scheduled debt repayments on the long-term debt outstanding at December 31,
2001, amount to: $16,061,000 in 2002; $19,364,000 in 2003; $4,052,000 in 2004;
$10,130,000 in 2005; $169,712,000 in 2006; and $239,422,000 thereafter.
NOTE 9--SHORT-TERM BORROWING
Our committed and uncommitted credit lines expired at the end of
November 2001 and were not renewed by December 31, 2001. On November 21, 2001,
we issued $150,000,000 in First Mortgage Bonds and used the proceeds from the
bonds to repay the $60,000,000 balance outstanding under our committed credit
line, repay short-term borrowings, and repay an intercompany loan between
Montana Power and Entech. The remaining balance was used for existing cash
requirements and to redeem our ESOP Notes. At December 31, 2001, we had no
outstanding short-term borrowing.
At December 31, 2000, we had outstanding notes payable to banks for
$75,000,000 at a weighted average annual interest rate of 8.05 percent. Of those
outstanding notes, $25,000,000 were issued from our committed lines of credit
and the other $50,000,000 from our uncommitted lines of credit.
NOTE 10--RETIREMENT PLANS
MPC maintains trusteed, noncontributory retirement plans covering
substantially all of our employees. Prior to 1998, our retirement benefits were
based on salary, years of service, and social security integration levels. In
1998, we amended our retirement plan's benefit provisions. Our retirement
benefits are now based on salary, age, and years of service. Northwestern has
agreed to assume certain retirement plans and participants and maintain such
plans or equivalent plans for a period of two years.
Our plan assets consist primarily of domestic and foreign corporate stocks,
domestic corporate bonds, and United States Government securities.
We also have an unfunded, nonqualified benefit plan for senior management
executives and directors. In December 1998, we froze the benefits earned and
curtailed the plan. We own life insurance policies, the cash value/death benefit
of which is intended to finance this plan.
29
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 10--RETIREMENT PLANS (CONTINUED)
As a result of the sale of our electric generating assets to PPL Montana,
454 participants related to electric generation operations were curtailed from
the retirement plan and approximately $22,700,000 in assets were transferred
from the retirement plan trust in December 1999. Pursuant to the agreement, when
the calculation was finalized in February 2000, approximately $3,200,000 of
additional assets were transferred to the PPL trust. In accordance with SFAS 88,
we calculated a curtailment gain of approximately $4,100,000 and a settlement
gain of approximately $7,800,000 in 1999. Due to regulatory accounting
treatment, the gains were recorded as regulatory liabilities or offsets to
regulatory assets, resulting in no income statement impact.
We offered a Special Retirement Program (SRP) to certain eligible employees
during 2000. The SFAS 88 special termination charge resulting from 201 utility
participants electing the SRP amounted to approximately $9,814,000. Due to
regulatory accounting treatment, the expense was recorded as regulatory
liabilities or offsets to regulatory assets, resulting in no income statement
impact.
We also provide certain health care and life insurance benefits for eligible
retired employees. In 1994, we established a pre-funding plan for postretirement
benefits for utility employees retiring after January 1,1993. The plan assets
consist primarily of domestic and foreign corporate stocks, domestic corporate
bonds, and United States Government securities. The PSC allows us to include in
rates all utility Other Postretirement Benefits costs on the accrual basis
provided by SFAS No. 106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions."
We also have a voluntary retirement savings plan in conjunction with our
retirement plans. Through October 30, 2001, MPC contributed a matching
percentage comprised of shares of MPC stock from a leveraged Employee Stock
Ownership Plan (ESOP) arrangement and MPC shares purchased on the open market.
Beginning November 1, 2002, we make cash contributions matching employee
contributions up to 4 percent of their salaries. For costs associated with these
plans and for information about the transfer of the ESOP Plan to Touch America,
see Note 6, "Other Equity."
30
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 10--RETIREMENT PLANS (CONTINUED)
The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of plan assets over the two-year period
ending December 31, 2001, and a statement of the funded status as of
December 31 of both years:
<Table>
<Caption>
PENSION BENEFITS OTHER BENEFITS
------------------- -------------------
2001 2000 2001 2000
-------- -------- -------- --------
(THOUSANDS OF DOLLARS)
Change in benefit obligation:
Benefit obligation at January 1............ $235,515 $197,333 $ 23,168 $ 18,918
Service cost on benefits earned............ 3,676 4,090 420 430
Interest cost on projected benefit
obligation............................... 16,992 15,893 1,851 1,561
Plan amendments............................ 1,717 7,578 -- --
Assumption changes......................... -- 5,859 -- --
Actuarial (gain)/loss...................... 24,909 (4,988) 3,598 4,920
Adjustments for liability transfers........ 14,072 11,630 (324) --
Special termination benefits............... -- 9,814 -- --
Gross benefits paid........................ (16,488) (11,694) (4,688) (2,661)
-------- -------- -------- --------
Benefit obligation at December 31.......... $280,393 $235,515 $ 24,025 $ 23,168
======== ======== ======== ========
Change in plan assets:
Fair value of plan assets at January 1..... $223,921 $230,606 $ 9,706 $ 9,916
Actual return/(loss) on plan assets........ (4,917) (4,955) 107 329
Employer contributions..................... 1,834 1,818 746 2,122
Acquisitions/divestitures.................. -- (3,200) -- --
Assets allocated (to)/from related
companies................................ 10,793 11,346 -- --
Gross benefits paid........................ (16,488) (11,694) (4,688) (2,661)
-------- -------- -------- --------
Fair value of plan assets at December 31... $215,143 $223,921 $ 5,871 $ 9,706
======== ======== ======== ========
Reconciliation of funded status:
Funded status at end of year............... $(65,250) $(11,594) $(18,153) $(13,461)
Unrecognized net:
Actuarial gain........................... 24,642 (22,707) 2,855 (97)
Prior service cost....................... 20,459 21,295 1,248 1,459
Transition obligation.................... (129) (196) 8,721 10,034
Acquisitions/divestitures................ 3,615 -- -- --
-------- -------- -------- --------
Net amount recognized at December 31..... $(16,663) $(13,202) $ (5,329) $ (2,065)
======== ======== ======== ========
</Table>
31
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 10--RETIREMENT PLANS (CONTINUED)
The following table provides the amounts recognized in the statement of
financial position as of December 31:
<Table>
<Caption>
PENSION BENEFITS OTHER BENEFITS
------------------- -------------------
2001 2000 2001 2000
-------- -------- -------- --------
(THOUSANDS OF DOLLARS)
Prepaid benefit cost.......................... $ 2,170 $ 11,028 $ -- $ --
Accrued benefit cost.......................... (18,833) (24,230) (5,329) (2,065)
Additional minimum liability.................. (40,374) (2,594) -- --
Intangible asset.............................. 21,367 -- -- --
Regulatory asset--pension plan................ 14,990 -- -- --
Accum. other comprehensive inc................ 4,017 2,594 -- --
-------- -------- ------- --------
Net amount recognized at December 31........ $(16,663) $(13,202) $(5,329) $ (2,065)
======== ======== ======= ========
</Table>
The following tables provide the components of net periodic benefit cost for
the pension and other postretirement benefit plans, portions of which have been
deferred or capitalized, for fiscal years 2001, 2000, and 1999:
<Table>
<Caption>
PENSION BENEFITS
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
Service cost on benefits earned........................ $ 3,676 $ 4,090 $ 6,288
Interest cost on projected benefit obligation.......... 16,992 15,893 16,193
Expected return on plan assets......................... (17,921) (20,273) (21,767)
Amortization of:
Transition obligation................................ (47) (49) (49)
Prior service cost................................... 1,947 1,607 1,522
Actuarial gain....................................... 67 (2,830) (1,395)
-------- -------- --------
Net periodic benefit cost (credit)..................... 4,714 (1,562) 792
Special termination benefit charge..................... -- 9,814 --
Curtailment (gain)/loss................................ -- -- (3,751)
Settlement gain........................................ -- -- (7,844)
-------- -------- --------
Net periodic benefit cost (credit) after curtailments
and settlements...................................... $ 4,714 $ 8,252 $(10,803)
======== ======== ========
</Table>
32
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 10--RETIREMENT PLANS (CONTINUED)
<Table>
<Caption>
OTHER BENEFITS
------------------------------
2001 2000 1999
-------- -------- --------
(THOUSANDS OF DOLLARS)
Service cost on benefits earned............................. $ 420 $ 430 $ 662
Interest cost on projected benefit obligation............... 1,851 1,561 1,585
Expected return on plan assets.............................. (706) (819) (723)
Amortization of:
Transition obligation..................................... 792 837 1,036
Prior service cost........................................ 138 146 158
Actuarial gain............................................ -- (128) (111)
Net periodic benefit cost (credit).......................... 2,495 2,027 2,607
------ ------ ------
Curtailment (gain)/loss..................................... -- -- (374)
------ ------ ------
Net periodic benefit cost (credit) after curtailments and
settlements............................................... $2,495 $2,027 $2,233
====== ====== ======
</Table>
In 2001, funding for pension costs was less than SFAS No. 87, "Employers
Accounting for Pensions," pension expense by $3,138,000. In 2000, pension costs
exceeded SFAS No. 87 pension expense by $3,078,000. The PSC allows recovery for
the funding of pension costs through rates. Any differences between funding and
expense are deferred for recognition in future periods. At December 31, 2001,
the regulatory liability was $7,487,000.
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
<Table>
<Caption>
PENSION BENEFITS OTHER BENEFITS
------------------- -------------------
2001 2000 2001 2000
-------- -------- -------- --------
Weighted average assumptions as of December 31:
Discount rate..................................... 7.00% 7.50% 7.00% 7.50%
Expected return on plan assets.................... 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase..................... 4.40% 4.40% 4.40% 4.40%
</Table>
Assumed health care costs trend rates have a significant effect on the
amounts reported for the health care plans. A change of 1 percent in assumed
health care cost trend rates would have the following effects:
<Table>
<Caption>
1% INCREASE 1% DECREASE
----------- -----------
(THOUSANDS OF DOLLARS)
Effect on the total of service and interest cost components
of net periodic post-retirement health care benefit
cost...................................................... $ 95 $ (82)
Effect on the health care component of the accumulated
postretirement benefit obligation......................... 687 (604)
</Table>
The assumed 2001 health care cost trend rates used to measure the expected
cost of benefits covered by the plans is 9.00 percent. The trend rate decreases
through 2007 to 5.50 percent.
33
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 11--CONTINGENCIES
- - KERR PROJECT
A FERC order that preceded our sale of the Kerr Project required us to
implement a plan to mitigate the effect of the Kerr Project operations on fish,
wildlife, and habitat. To implement this plan, we were required to make payments
of approximately $135,000,000 between 1985 and 2020, the term during which we
would have been the licensee. The net present value of the total payments,
assuming a 9.5 percent annual discount rate, was approximately $57,000,000, an
amount we recognized as license costs in plant and long-term debt on the
Comparative Balance Sheet in 1997. In the sale of the Kerr Project, the
purchaser of our electric generating assets assumed the obligation to make
post-closing license compliance payments.
In December 1998 and January 1999, we requested a review by the United
States Court of Appeals for the District of Columbia Circuit of this order and
another FERC order which included the United States Department of Interior's
conditions. In December 2000, FERC issued an order approving a settlement among
the parties. On February 15, 2001, the Circuit Court dismissed the petitions for
review. Consequently, the approximately $24,000,000 that we paid into escrow in
2000 was released to the Confederated Salish and Kootenai Tribes (Tribes) to be
used in accordance with the terms of the settlement. We have also transferred
669 acres of land on the Flathead Indian Reservation to the Tribes. With the
payment and the transfer of land, we have fulfilled our obligations under the
terms of this settlement. Because PPL Montana, the purchaser, assumed the
obligation in excess of $24,000,000, the basis in the properties sold decreased
and the regulatory liability associated with the deferred gain on the sale
increased accordingly.
- - LONG-TERM POWER SUPPLY AGREEMENTS
Long-term power supply agreements, primarily an agreement with a large
industrial customer, exposed us to losses and potential future losses mainly
because of unusually high electric energy market prices. To eliminate our
exposure to expected future losses through December 2002 when the agreement with
that customer terminated, we executed a termination agreement effective
June 30, 2001. Under the termination agreement, we made a one-time payment of
$62,500,000 to the customer and ended our obligations under this power supply
agreement. We recorded a pretax loss of $62,500,000, or approximately
$37,900,000 after income taxes, in the second quarter 2001. Prior to the
termination agreement, we recorded pretax losses associated with the power
supply agreement of approximately $2,500,000 in the first quarter 2001, and
$22,500,000 in the second quarter 2001, and approximately $16,200,000 for the
year ended December 31, 2000.
- - CLASS ACTION LAWSUIT
On August 16, 2001, eight individuals filed a lawsuit in Montana State
District Court, naming MPC, eleven of its current Board of Directors, three
officers of both Touch America and MPC, and PPL Montana as defendants. In their
complaint, the plaintiffs allege that MPC and its directors and officers had a
legal obligation and a fiduciary duty to obtain shareholder approval before the
sale of our former electric generation assets to PPL Montana. On September 14,
2001, the complaint was amended to add one other current officer of Touch
America, one other current officer of MPC, and our investment banking
consultants as additional defendants. As previously reported, MPC completed
34
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE FINANCIAL STATEMENTS
NOTE 11--CONTINGENCIES (CONTINUED)
the sale of the electric generation assets to PPL Montana in December 1999. The
plaintiffs further allege that because MPC shareholders did not vote, the sale
of the generation assets is void and PPL Montana is holding these assets in
constructive trust for the shareholders.
Alternatively, the plaintiffs allege that MPC shareholders should have been
allowed to vote on the sale of the generation assets and, if an appropriate
majority vote was obtained in favor of the sale, the shareholders should have
been given dissenters' rights. The plaintiffs also make various claims of
breaches of duty and negligence against the Board of Directors and the
individual officers. The plaintiffs have indicated that they will seek court
approval to proceed with this suit as a class action.
It is MPC's position that MPC and its former directors and officers, and one
current officer, have fully complied with their statutory and fiduciary duties.
Accordingly, MPC is defending the suit vigorously. MPC filed a motion to dismiss
the complaint in late November 2001. At this early stage, however, we cannot
predict the ultimate outcome of this matter or how it may affect our combined
financial position, results of operations, or cash flows.
- - MISCELLANEOUS
We are parties to various other legal claims, actions, and complaints
arising in the ordinary course of business. We do not expect the conclusion of
any of these matters to have a material adverse effect on our combined financial
position, results of operations, or cash flows.
NOTE 12--COMMITMENTS
- - PURCHASE COMMITMENTS
ELECTRIC UTILITY
The Public Utilities Regulatory Policies Act (PURPA) requires a public
utility to purchase power from QFs at a rate equal to what it would pay to
generate or purchase power. These QFs are power production or co-generation
facilities that meet size, fuel use, ownership, and operating and efficiency
criteria specified by PURPA. The electric utility has 15 long-term QF contracts
with expiration terms ranging from 2003 through 2032 that require us to make
payments for energy capacity and energy received at prices established by the
PSC. Three contracts account for 96 percent of the 101 MWs of capacity provided
by these facilities. Montana's Electric Act designates above-market portion of
the QF costs as Competitive Transition Costs (CTCs) and allows for their
recovery. For more information about CTCs, see Note 2, "Deregulation, Regulatory
Matters, and 1999 Sale of Electric Generating Assets".
Montana's Electric Act also designated us as the default power supplier for
those customers who had not chosen another supplier by July 1, 2002. To fulfill
that obligation, there was included in the Asset Purchase Agreement with PPL
Montana, dated as of October 31, 1998 and amended June 29, 1999 and October 29,
1999, two Wholesale Transition Service Agreements (WTSAs), effective
December 17, 1999. One agreement terminated at December 31, 2001. The other
agreement continues to commit us to purchase through June 2002 any power
requirements remaining after having received power from the QFs and Milltown
Dam, and prices the power purchased from PPL Montana at a market index, with a
monthly floor and an annual cap.
35
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 12--COMMITMENTS (CONTINUED)
In its 2001 session, the Montana Legislature passed House Bill 474, which
extends the transition period of electric deregulation in Montana from July 1,
2002 to June 30 2007 and, therefore, our obligation as a default supplier
through June 30, 2007. We entered into three power purchase agreements in
October 2001 that enable us to satisfy, in part, our "Default Supply"
obligation. These agreements commit us to purchase a total of 561 MWs per hour
during peak hours and 411 MWs per hour during the off-peak hours in the first
year of the extended transition period. In the remaining years of the transition
period, these agreements also obligate us to purchase 450 MWs per hour during
the peak hours and 300 MWs per hour during the off-peak hours. These purchases
are included in our "Default Supply Portfolio" filing with the PSC (Docket
No. D2001.10.144) dated October 29, 2001. House Bill 447 also provides for the
complete recovery in rates of the default supplier's costs that are prudently
incurred to supply electric energy. For more information about electric
deregulation, see Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of
Electric Generating Assets," in the "Electric Deregulation" section.
NATURAL GAS UTILITY
Since 1998, because of uncertainty about the number and timing of customers
who could choose another natural gas supplier under the provisions of Montana's
1997 Natural Gas Act, we entered primarily into one-year take-or-pay contracts
with Montana natural gas producers. We currently have six of these contracts,
five of which expire in 2002, and one in 2006. After July 1, 2002, we are not
obligated to supply natural gas to those who do not choose another supplier. We
have a request before the PSC to designate us as the natural gas default
supplier for the five-year period beyond July 1, 2002. Upon such designation, we
will secure additional supply contracts to meet the needs of our customers.
CONTRACTUAL PAYMENTS AND PRESENT VALUE
Total payments under all of these contracts for the prior three years were
as follows:
<Table>
<Caption>
ELECTRIC NATURAL GAS TOTAL
-------- ----------- --------
(THOUSANDS OF DOLLARS)
2001................................................. $263,924 $16,764 $280,688
2000................................................. 272,075 7,101 279,176
1999................................................. 61,274 4,069 65,343
</Table>
Under the above agreements, the present value of future minimum payments, at
a discount rate of 3.615 percent, is as follows:
<Table>
<Caption>
ELECTRIC NATURAL GAS TOTAL
-------- ----------- --------
(THOUSANDS OF DOLLARS)
2002................................................. $103,724 $ 8,871 $112,595
2003................................................. 118,985 613 119,598
2004................................................. 104,289 612 104,901
2005................................................. 100,677 593 101,270
2006................................................. 87,723 566 88,289
Remainder............................................ 241,009 -- 241,009
-------- ------- --------
$756,407 $11,255 $767,662
======== ======= ========
</Table>
36
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 12--COMMITMENTS (CONTINUED)
- - LEASE COMMITMENTS
On December 30, 1985, we sold our 30 percent share of Colstrip Unit 4 and
agreed to lease back our share under a net, 25-year lease with annual payments
of approximately $32,000,000. We have been accounting for this transaction as an
operating lease. We did not sell this nonutility leasehold interest and its
related assets and liabilities and contract obligations to PPL Montana in 1999.
This lease was included in the sale of the utility businesses to NorthWestern.
On September 24, 1997, we entered into a seven-year operating lease with a
banking institution--for an automated meter reading system--with annual payments
of approximately $2,400,000. This lease was terminated by NorthWestern on
February 15, 2002. We have no other material minimum operating lease payments.
Rental expense for the prior three years was $44,333,000 for 2001,
$41,270,000 for 2000, and $56,316,000 for 1999.
The present value of future minimum lease payments for Colstrip Unit 4, at a
discount rate of 3.615 percent (our minimum short-term borrowing rate at
December 31, 2001), is as follows:
<Table>
<Caption>
(THOUSANDS OF
DOLLARS)
-------------
2002................................................... $ 30,624
2003................................................... 29,715
2004................................................... 28,825
2005................................................... 27,820
2006................................................... 26,849
Remainder.............................................. 98,351
--------
$242,184
========
</Table>
Capitalized leases are not material and are included in other long-term
debt.
37
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 13--NEW ACCOUNTING PRONOUNCEMENTS
- - SFAS NOS. 141, 142, 143, AND 144
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141, "Business Combinations." SFAS No. 141 eliminates the use of the pooling
of interests method of accounting, and requires that all mergers and
acquisitions be accounted for using the purchase method of accounting. SFAS
No. 141 also establishes specific criteria for the recognition of intangible
assets separately from goodwill and adds new disclosure requirements. This
statement is effective for all mergers and acquisitions initiated after
June 30, 2001. Adoption of this pronouncement is not expected to have a material
impact on our financial position, results of operations, or cash flows.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangibles." The amortization provisions of SFAS No. 142 apply to goodwill and
other intangibles acquired after June 30, 2001. For goodwill and other
intangible assets acquired prior to July 1, 2001, adoption of SFAS No. 142 is
required for fiscal years beginning after December 15, 2001. SFAS No. 142
primarily addresses the accounting for goodwill and intangible assets subsequent
to their initial recognition. The provisions of SFAS 142:
- prohibit the amortization of goodwill and indefinite-lived intangible
assets;
- require that reporting units be identified for the purpose of assessing
potential future impairments of goodwill;
- remove the forty-year limitation on the amortization period of intangible
assets that have finite lives; and
- prohibit amortization of the excess of cost over the underlying equity in
the net assets of an equity-method investee that is recognized as
goodwill.
In addition, SFAS No. 142 requires that goodwill be tested annually for
impairment--and in interim periods if certain events occur indicating that the
carrying value of goodwill and/or indefinite-lived intangible assets may be
impaired--using a two-step process. The first step is to identify a potential
impairment and, in transition, this step must be measured as of the beginning of
the fiscal year. However, a company has six months from the date of adoption to
complete the first step. The second step of the goodwill impairment test
measures the amount of the impairment loss (measured as of the beginning of the
year of adoption), if any, and must be completed by the end of the fiscal year.
Intangible assets deemed to have an indefinite life will be tested for
impairment using a one-step process which compares the fair value to the
carrying amount of the asset as of the beginning of the fiscal year, and
pursuant to the requirements of SFAS 142 will be completed during the first
quarter of 2002. Any impairment loss resulting from the transitional impairment
tests will be reflected as the cumulative effect of a change in accounting
principle in the first quarter 2002. Adoption of this pronouncement is not
expected to have a material impact on our financial position, results of
operations, or cash flows.
In June 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires entities to record the fair value of a legal
liability for an asset retirement obligation in the period it is incurred. The
asset retirement costs are capitalized as part of the carrying amount of the
long-lived asset. This statement is effective for financial statements issued
for fiscal years beginning after June 15, 2002. We are currently evaluating this
pronouncement, but we do not expect it to have a material impact on our
financial position, results of operations, or cash flows.
38
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 13--NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)
In August 2001, the FASB issued SFAS No. 144 "Accounting for the Impairment
of Long-Lived Assets." SFAS No. 144 addresses financial accounting and reporting
for the impairment or disposal of long-lived assets. This statement is effective
for financial statements issued for fiscal years beginning after December 15,
2001. Adoption of this pronouncement is not expected to have a material impact
on our financial position, results of operations, or cash flows.
NOTE 14--INFORMATION ON INDUSTRY SEGMENTS
Our utility business purchases, transmits, and distributes electric energy
and natural gas, and the Colstrip Unit 4 division manages long-term power supply
agreements. Our other operations consists primarily of Montana Power Services
Company, One Call Locators, Ltd., and Discovery Energy Solutions, Inc. (DES).
One Call Locators, Ltd., locates underground lines while DES handles the energy
productivity improvement activities.
Identifiable assets of each industry segment are principally those assets
used in our operation of those industry segments. Corporate assets are
principally cash and cash equivalents and temporary investments. We consider
segment information for foreign operations to be insignificant.
OPERATIONS INFORMATION
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 2001
-------------------------------------
(THOUSANDS OF DOLLARS)
INDUSTRY SEGMENTS
<Caption>
ELECTRIC NATURAL GAS OTHER
---------- ----------- ----------
Sales to unaffiliated customers......................... $ 538,529 $147,277 $ 17,979
Intersegment sales...................................... 747 319 1,408
Depreciation and amortization........................... 44,378 11,020 1,327
Pretax operating income (loss).......................... (14,182) 9,130 1,795
Interest expense........................................ 30,016 15,153 1
Interest income......................................... 1,598 1,101 --
Income tax expense (benefit)............................ (6,052) 1,317 661
Capital expenditures.................................... 44,294 14,235 759
Identifiable assets..................................... 1,033,089 522,553 34,311
</Table>
39
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 14--INFORMATION ON INDUSTRY SEGMENTS (CONTINUED)
RECONCILIATION TO COMBINED TOTAL
<Table>
<Caption>
SEGMENT COMBINED
TOTAL ADJUSTMENTS(A) TOTAL
---------- -------------- ----------
Sales to unaffiliated customers......................... $ 703,785 $ -- $ 703,785
Intersegment sales...................................... 2,474 (2,474) --
Depreciation and amortization........................... 56,725 -- 56,725
Pretax operating income (loss).......................... (3,257) -- (3,257)
Interest expense........................................ 45,170 -- 45,170
Interest income......................................... 2,699 -- 2,699
Income tax benefit...................................... (4,074) -- (4,074)
Capital expenditures.................................... 59,288 -- 59,288
Identifiable assets..................................... 1,589,953 -- 1,589,953
</Table>
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 2000
-------------------------------------
(THOUSANDS OF DOLLARS)
INDUSTRY SEGMENTS
<Caption>
ELECTRIC NATURAL GAS OTHER
---------- ----------- ----------
Sales to unaffiliated customers......................... $ 535,654 $129,220 $ 11,179
Intersegment sales...................................... 772 269 1,291
Depreciation and amortization........................... 39,559 8,830 5,734
Pretax operating income (loss).......................... 18,168 (4,405) 334
Interest expense........................................ 26,726 16,077 1,047
Interest income......................................... 12,041 4,984 --
Income tax benefit...................................... (9,399) (9,943) (257)
Capital expenditures.................................... 42,718 7,546 27,603
Identifiable assets..................................... 1,244,530 363,870 76,385
</Table>
RECONCILIATION TO COMBINED TOTAL
<Table>
<Caption>
SEGMENT COMBINED
TOTAL ADJUSTMENTS(A) TOTAL
---------- -------------- ----------
Sales to unaffiliated customers......................... $ 676,053 $ -- $ 676,053
Intersegment sales...................................... 2,332 (2,332) --
Depreciation and amortization........................... 54,123 -- 54,123
Pretax operating income................................. 14,097 -- 14,097
Interest expense........................................ 43,850 (2,478) 41,372
Interest income......................................... 17,025 (2,478) 14,547
Income tax benefit...................................... (19,599) -- (19,599)
Capital expenditures.................................... 77,867 -- 77,867
Identifiable assets..................................... 1,684,785 -- 1,684,785
</Table>
- ------------------------
(a) The amounts indicated include certain eliminations between the business
segments.
40
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 14--INFORMATION ON INDUSTRY SEGMENTS (CONTINUED)
OPERATIONS INFORMATION
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 1999
-------------------------------------
(THOUSANDS OF DOLLARS)
INDUSTRY SEGMENTS
<Caption>
ELECTRIC NATURAL GAS OTHER
---------- ----------- ----------
Sales to unaffiliated customers. $ 545,390 $ 111,417 $ 274
Intersegment sales...................................... 714 202 889
Depreciation and amortization........................... 56,282 9,275 4,137
Pretax operating income................................. 113,740 16,430 2,055
Interest expense........................................ 37,893 15,229 706
Interest income......................................... 3,875 793 (9)
Income tax expense...................................... 13,054 380 461
Capital expenditures.................................... 50,503 13,115 15,957
Identifiable assets..................................... 1,687,511 495,846 40,987
</Table>
RECONCILIATION TO COMBINED TOTAL
<Table>
<Caption>
SEGMENT COMBINED
TOTAL ADJUSTMENTS(A) TOTAL
---------- -------------- ----------
Sales to unaffiliated customers......................... $ 657,081 $ -- $ 657,081
Intersegment sales...................................... 1,805 (1,805) --
Depreciation and amortization........................... 69,694 -- 69,694
Pretax operating income................................. 132,225 -- 132,225
Interest expense........................................ 53,828 (973) 52,855
Interest income......................................... 4,659 (973) 3,686
Income tax expense...................................... 13,895 -- 13,895
Capital expenditures.................................... 79,575 -- 79,575
Identifiable assets..................................... 2,224,344 -- 2,224,344
</Table>
- ------------------------
(a) The amounts indicated include certain eliminations between the business
segments.
NOTE 15--GENERATION ASSETS (UNAUDITED)
As discussed in Note 2, "Deregulation, Regulatory Matters, and 1999 Sale of
Electric Generating Assets," on December 17, 1999, MPC sold substantially all of
our electric generating assets and related
41
<Page>
THE UTILITY OF THE MONTANA POWER COMPANY
NOTES TO THE COMBINED FINANCIAL STATEMENTS
NOTE 15--GENERATION ASSETS (UNAUDITED) (CONTINUED)
contracts. Prior to the sale, the combined statements of income for the year
ended December 31, 1999 include generation amounts. These amounts consist of the
following:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 1999
-----------------
(THOUSANDS OF
DOLLARS)
REVENUES*................................................... $228,811
EXPENSES:
Operations and maintenance................................ 147,451
Selling, general, and administrative...................... 9,021
Taxes other than income taxes............................. 17,306
Depreciation and amortization............................. 19,378
--------
193,156
INCOME FROM OPERATIONS...................................... 35,655
INTEREST EXPENSE AND OTHER INCOME:
Interest.................................................. 7,443
Other income--net......................................... (883)
--------
6,560
--------
INCOME BEFORE INCOME TAXES................................ 29,095
INCOME TAX EXPENSE (BENEFIT)................................ (7,490)
--------
NET INCOME.................................................. $ 36,585
========
</Table>
- ------------------------
* Generation revenues include an allocation of our previously bundled rates.
42