UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
________________________________________
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended March 31, 1999
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _______________
________________________________________
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
________________________________________________________
(Former name, former address and former fiscal year,
if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
On May 11, 1999, the Company had 55,082,630 shares of common stock
outstanding.
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<TABLE>
PART I
ITEM 1 - FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<CAPTION>
For Three Months Ended
March 31, March 31,
1999 1998
Thousands of Dollars
<S> <C>
<C>
REVENUES $ 321,768 $ 294,050
EXPENSES:
Operations 153,560 128,427
Maintenance 19,630 19,782
Selling, general, and administrative 33,143 29,367
Taxes other than income taxes 25,768 25,525
Depreciation, depletion and amortization 27,754
27,086
259,855 230,187
INCOME FROM OPERATIONS 61,913 63,863
INTEREST EXPENSE AND OTHER INCOME:
Interest 13,629 14,504
Distributions on mandatorily redeemable preferred
securities of subsidiary trust 1,373 1,373
Other (income) deductions-net (3,869) (1,729)
11,133 14,148
INCOME TAXES 16,956 13,848
NET INCOME 33,824 35,867
DIVIDENDS ON PREFERRED STOCK 923 923
NET INCOME AVAILABLE FOR COMMON STOCK $ 32,901 $ 34,944
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - BASIC (000) 55,073 54,875
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.60 $ 0.64
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - DILUTED (000) 55,399 54,971
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.59 $ 0.64
The accompanying notes are an integral part of these statements.
</TABLE>
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<TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
<CAPTION>
March 31, December 31,
1999 1998
Thousands of Dollars
<S> <C>
<C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $37,499 and $37,966
plant under construction)
Electric $ 1,847,723 $ 1,841,855
Natural gas 404,384 404,992
2,252,107 2,246,847
Less - accumulated depreciation and depletion 749,031
732,385
1,503,076 1,514,462
NONUTILITY PROPERTY (includes $13,437 and $10,990
property under construction) 880,661 864,981
Less - accumulated depreciation and depletion 308,878
297,933
571,783 567,048
2,074,859 2,081,510
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 25,544 24,268
Reclamation fund 41,987 41,542
Other 85,232 84,256
152,763 150,066
CURRENT ASSETS:
Cash and temporary cash investments 219,746 10,116
Accounts receivable 144,160 170,652
Notes receivable 32,909 29,089
Materials and supplies (principally at average cost) 42,056
42,292
Prepayments and other assets 61,594 57,331
Deferred income taxes 18,758 18,755
519,223 328,235
DEFERRED CHARGES:
Advanced coal royalties 13,749 14,312
Regulatory assets related to income taxes 121,734 121,735
Regulatory assets - other 154,465 154,193
Other deferred charges 79,266 78,044
369,214 368,284
$ 3,116,059 $ 2,928,095
The accompanying notes are an integral part of these statements.
</TABLE>
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<TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
<CAPTION>
March 31, December 31,
1999 1998
Thousands of Dollars
<S> <C>
<C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares authorized;
55,079,362 and 55,060,520 shares issued) $
702,879 $ 702,511
Retained earnings and other shareholders' equity
441,165 430,309
Accumulated other comprehensive income (20,052)
(20,717)
Unallocated stock held by trustee for
Retirement savings plan (22,599)
(23,298)
1,101,393 1,088,805
Preferred stock 57,654 57,654
Company obligated mandatorily redeemable preferred
securities of subsidiary trust, which holds solely,
company junior subordinated debentures 65,000
65,000
Long-term debt 727,729 698,329
1,951,776 1,909,788
CURRENT LIABILITIES:
Short-term borrowing - 69,820
Long-term debt - portion due within one year 41,344 96,292
Dividends payable 22,747 22,765
Income taxes 47,358 24,857
Other taxes 69,124 51,777
Accounts payable 81,951 97,197
Interest accrued 13,701 13,156
Accrued lease payments 7,920 -
Other current liabilities 42,074 40,087
326,219 415,951
DEFERRED CREDITS:
Deferred income taxes 306,952 323,906
Investment tax credit 34,530 35,175
Accrued mining reclamation costs 131,015 129,558
Other deferred credits 365,567 113,717
838,064 602,356
CONTINGENCIES AND COMMITMENTS (Notes 2 and 5)
$ 3,116,059 $ 2,928,095
The accompanying notes are an integral part of these statements.
</TABLE>
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<TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
For Three Months Ended
March 31, March 31,
1999 1998
Thousands of Dollars
<S> <C>
<C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 33,824 $ 35,867
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, and amortization 27,754 27,086
Deferred income taxes (16,954) (2,218)
Noncash earnings from equity basis investments (6,533)
(3,490)
Other - net 3,963 6,128
Changes in other assets and liabilities:
Accounts receivable 26,492 (27,326)
Income taxes payable 22,501 19,439
Deferred revenue and other 251,850 420
Other assets and liabilities 2,901 23,092
Net cash provided by operating activities 345,798
78,998
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (23,764) (28,900)
Sales of property and investments 6,536 11,091
Additional investments (843) (484)
Net cash used by investing activities (18,071)
(18,293)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (22,947) (22,847)
Sales of common stock 321 4,294
Issuance of long-term debt 31,048 2,743
Retirement of long-term debt (56,699) (3,320)
Net change in short-term borrowing (69,820) (32,476)
Net cash used by financing activities (118,097)
(51,606)
CHANGE IN CASH FLOWS 209,630 9,099
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 10,116
16,706
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 219,746 $ 25,805
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Three Months For:
Income taxes, net of refunds $ 113 $ 8,546
Interest 3,197 14,742
The accompanying notes are an integral part of these statements.
</PAGE>
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements of the Company for the
interim periods ended March 31, 1999 and 1998 are unaudited but, in the opinion
of management, reflect all normal recurring accruals necessary for a fair
statement of the results of operations for those interim periods. The results
of operations for the interim periods are not necessarily indicative of the
results to be expected for the full year. These financial statements do not
contain the detail or footnote disclosure concerning accounting policies and
other matters which would be included in full fiscal year financial statements;
therefore, they should be read in conjunction with the Company's audited
financial statements included in the Company's Annual Report on Form 10-K for
the year ended December 31, 1998.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1999 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1 -- DEREGULATION AND ASSET DIVESTITURE, AND OTHER REGULATORY MATTERS:
The electric and natural gas utility businesses are in transition to
competition where energy commodity products and related services are marketed
directly to wholesale and retail customers. The Montana electric and natural
gas restructuring and customer choice laws, passed in 1997, provide for choice
of electricity and natural gas suppliers to all customers no later than July
1, 2002. Through March 1999 approximately 232 natural gas customers,
representing approximately 54 percent of the Utility's pre-choice natural gas
supply load have chosen alternate suppliers. Also through March 1999,
approximately 79 electric customers, representing approximately 24 percent of
the Utility's pre-choice electric load have chosen alternate suppliers.
As required by the electric legislation, the Company filed a
comprehensive transition plan with the Montana Public Service Commission (PSC)
in July 1997. Initial hearings on the filing began in April 1998 and the
issues involved in the restructuring filing were separated into groups. The
PSC rendered a decision in June 1998 on the issues relating to customer choice
for the large industrial group and the pilot programs. Prior to July 1999,
the Company will file a case with the PSC to resolve the remaining (Tier II)
issues. These issues specifically include recovery/treatment of above-market
qualifying facility power-purchase contract costs and regulatory assets
associated with the generation business, and a review of the Company's sale of
its generation assets, including the treatment of sale proceeds in excess of
the book value of the assets. A decision on these issues is expected within
nine months of the filing.
On March 30, 1998, the Company submitted a filing with the Federal
Energy Regulatory Commission (FERC) requesting increased rates for bundled
wholesale electric service to two rural electric cooperatives. This issue,
along with a rate filing for FERC transmission rates, was resolved through a
settlement between the Company, FERC and the intervenors in March 1999. The
settlement results in no change in rates charged for bundled wholesale
electric service, however, one customer retained the right to continue with
its complaint filed with FERC seeking a rate reduction. Transmission rates
were increased as a result of the settlement, which is expected to have a
positive impact on the results of transmission operations.
</PAGE>
<PAGE>
The Company also expects to file a general rate case for bundled natural
gas rates, which could become effective once the two-year rate moratorium ends
in October 1999. A decision on the filing is expected within nine months of
the filing.
NOTE 2 - CONTINGENCIES:
The Company is required by an order of FERC to implement a plan to
mitigate the impact of Kerr Project operations on fish, wildlife, and habitat.
Implementation will require payments of approximately $135,000,000 between
1985 and 2020, the license term. The net present value of the total payments,
assuming a 9.5 percent discount rate, is approximately $57,000,000, an amount
the Company recognized as license costs in plant and long-term debt in the
Consolidated Balance Sheet in 1997. Included in the $135,000,000 is a payment
of approximately $15,600,000 to fund the Fish and Wildlife Implementation
Strategy for the 1985 to 1997 period.
FERC's order is subject to judicial review by the United States Court of
Appeals for the District of Columbia Circuit. Pursuant to a related FERC
order, the Company is not obligated to pay approximately $15,600,000 to fund
the Fish and Wildlife Implementation Strategy for the period from 1985 to 1997
while the order is subject to judicial review.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, a generating capacity of 292 MWs
(Project 2188). The net present value of the cost of environmental mitigation
proposed by FERC's staff in the license proceeding is approximately
$162,000,000. A license order is expected in late 1999 or early 2000.
The Kerr Project and Project 2188 are assets to be sold under the terms
of the definitive Asset Purchase Agreement for the Company's sale of its
generation assets. For further information on the sale of the Company's
interest in the generating facilities see Note 1 - "Deregulation and Asset
Divestiture and Other Regulatory Matters". At closing of the sale, PP&L
Global, Inc. (PP&L Global) will assume the obligation to make payments
required to comply with the license conditions. The Company, however,
retained the obligation to make (i) the $15,600,000 payment for the Fish and
Wildlife Implementation Strategy referred to above and (ii) to the extent not
reimbursed by PP&L Global through the capital and maintenance budget to be
agreed upon by the Company and PP&L Global, other payments regarding "pre-
closing" license compliance expenditures.
Houston Lighting & Power (Reliant Energy), the purchaser of lignite
produced by Northwestern Resources Co. (Northwestern), a Company subsidiary,
settled litigation regarding the terms of the Lignite Supply Agreement (LSA)
between it and Northwestern. The LSA governs the delivery of approximately
9,000,000 tons of lignite per year and is effective until July 29, 2015.
Northwestern realizes revenues of approximately $25,000,000 per year from
management and dedication fees under LSA terms. Under the terms of the
settlement, lignite prices will continue to be set under the pre-settlement
LSA pricing terms until June 30, 2002. Reliant Energy will pay from July 1,
2002 through July 30, 2015, the lesser of a redetermined price set to be
competitive with Powder River Basin Coal supplies, or the price that would
have otherwise been paid under the pre-settlement LSA pricing terms. Reliant
Energy and Northwestern are negotiating terms to amend the LSA and implement
the settlement.
</PAGE>
<PAGE>
The Company and its subsidiaries are party to various other legal
claims, actions, and complaints arising in the ordinary course of business.
Management does not expect disposition of these matters to have a material
adverse effect on the Company's consolidated financial position or its
consolidated results of operations.
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS:
The Company has a formal policy regarding the execution, recording, and
reporting of derivative financial instruments related to the marketing and
trading of electricity, oil, natural gas, and natural gas liquids. The
purpose of the policy is to manage a portion of the price risk associated with
its nonutility producing assets, firm-supply commitments, and natural gas
transportation agreements. The Company uses derivative financial instruments
primarily as hedging instruments to help achieve earnings targets, reduce
earnings volatility, and provide more stabilized cash flows. When
fluctuations in natural gas and crude oil market prices result in value to the
Company with respect to derivative financial instruments into which it has
entered, the Company is exposed to credit risk relating to the nonperformance
by counterparties of their obligations to make payments under the agreements.
Such risk to the Company is mitigated by the fact that the counterparties, or
the parent companies of such counterparties, are investment grade financial
institutions. The Company does not anticipate any material impact to its
financial position, results of operations, or cash flows as a result of
nonperformance by counterparties.
To manage a portion of nonutility price risk, the Company uses a variety
of derivative financial instruments including crude oil and natural gas swap
and option agreements to hedge revenue from anticipated production of crude
oil and natural gas reserves, supply costs, and transportation commitments to
its firm markets. Under swap agreements, the Company receives or makes
payments based on the differential between a specified price and a variable
price of oil or natural gas when the hedged transaction is settled. The
variable price is either a crude oil or natural gas price quoted on the New
York Mercantile Exchange or a quoted natural gas price in Inside FERC's Gas
Market Report or other recognized industry index. These variable prices are
highly correlated with the market prices received by the Company for its
natural gas and crude oil production or paid by the Company for commodity
purchases. Under option agreements, the Company makes or receives monthly
payments at the settlement date based on the differential between the actual
price of oil or natural gas and the price established in the agreement
depending on whether the Company sells or buys the option. At March 31, 1999,
the Company had no derivative financial instruments that qualify as hedges
with respect to crude oil. The Company had swap and option agreements on
approximately 0.34 Bcf of nonutility natural gas, or 2 percent of its expected
production from proved, developed, and producing nonutility natural gas
reserves through October 1999. The Company had swap and option agreements to
hedge approximately 21.8 Bcf of nonutility natural gas, or 52 percent of its
expected delivery obligations under long-term natural gas sales contracts
through December 2000. In addition, the Company had swap and option
agreements to hedge approximately 10.7 Bcf, or 20 percent, of its nonutility
natural gas pipeline transportation obligations under contracts through
December 2000.
The Company accounts for certain derivative financial transactions through
hedge accounting. The Company designates all of its derivative financial
instruments that qualify for hedge accounting as fair value hedges. A fair
value hedge is based on the following criteria:
</PAGE>
<PAGE>
? The hedged item is specifically identified as a recognized asset or a
firm commitment.
? The hedged item is a single asset or a portfolio of similar assets.
? The hedged item presents an exposure to changes in fair value for the
hedged risk that could affect earnings.
? The hedged item is not an asset or liability that is measured at fair
value with changes in fair value attributable to the hedged risk
reported currently in earnings.
Gains or losses from these derivative financial instruments are
reflected in operating revenues on the Consolidated Statement of Income at the
same time as the recognition of the revenue or expense associated with the
underlying hedged item. If the Company determines that any portion of the
underlying hedged item will not be produced or purchased, the unmatched
portion of the instrument is marked-to-market and any gain or loss is
recognized in the Consolidated Statement of Income. If the Company terminates
a hedging instrument prior to the date of the anticipated natural gas or crude
oil production, commodity purchase, or transportation commitment, the gain or
loss from the agreement is deferred in the Consolidated Balance Sheet at the
termination date. At March 31, 1999, the Company had no material deferred
gains or losses related to these transactions.
The Company also has investments in independent power partnerships, some
of which have entered into derivative financial instruments to hedge interest
rate exposure on floating rate debt, foreign currency and natural gas price
fluctuations. At March 31, 1999, the Company believes it would not experience
any materially adverse impacts from the risks inherent in these instruments.
During 1998, the Emerging Issues Task Force (EITF) of the FASB released
Issue 98-10 (EITF 98-10), "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". EITF 98-10 addresses the accounting for
energy contracts and 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 is effective for the fiscal years beginning
after December 15, 1998. The Company adopted EITF as of January 1, 1999 and
accordingly marked all of its "trading activities" contracts to market as of
March 31, 1999 and recognized a corresponding loss that was not material in
the results of operations for the quarter. The cumulative effect on prior
year's financial position, of the adoption of EITF 98-10 was also not
material.
NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST:
Montana Power Capital I (Trust) was established as a wholly owned
business trust of the Company for the purpose of issuing common and preferred
securities (Trust Securities) and holding Junior Subordinated Deferrable
Interest Debentures (Subordinated Debentures) issued by the Company. The
Trust has 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 Subordinated Debentures, 8.45 percent Series due 2036,
issued by the Company. The Trust will use interest payments received on the
Subordinated Debentures it holds to make the quarterly cash distributions on
the QUIPS.
NOTE 5 - COMMITMENTS:
</PAGE>
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The Company has contracts to sell electricity with terms expiring over
the next five years. One such contract includes a fixed-price for a portion
of the deliveries. When the sale of the Company's generation assets is
finalized, and to the extent that this contract is not addressed in the
electric restructuring transition process, the Company will be subject to the
commodity price risks associated with supplying that portion of the contract.
However, due to the uncertainties relating to the other potential resources to
supply the contract, the timing of the sale of the generation assets and the
eventual outcome of the electric restructuring process, the Company cannot
determine at this time the potential effects of this contract on the Company's
future results of operations.
NOTE 6 - LONG-TERM DEBT
On February 1, 1999, the Company used the proceeds from asset backed
securities issued by the MPC Natural Gas Funding Trust to retire $55,000,000
of 7.7 percent First Mortgage Bonds.
NOTE 7 - COMPREHENSIVE INCOME
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income defines comprehensive income as change in equity of a
business enterprise during the period from transactions and other events and
circumstances from nonowner sources. SFAS No. 130 requires that an enterprise
report all components of comprehensive income in the period in which they are
recognized. These components are net income from continuing operations,
discontinued operations, extraordinary items, and cumulative effects of
changes in accounting principle. Other comprehensive income includes foreign
currency translations, adjustments of minimum pension liability, and
unrealized gains or losses on certain investments in debt and equity
securities.
For the three-month periods ended March 31, 1999 and 1998, the Company's
sole item of other comprehensive income were foreign currency translation
adjustments of ($665,000) and $3,900,000, respectively, to retained earnings.
There were no current income tax effects resulting from the adjustments. The
1998 adjustment included both the change in the valuation of the assets of the
Company's Canadian operations, and a change in the rate used to adjust certain
Canadian assets. When the assets were transferred from the Company's Utility
operations to the Nonutility operations, and removed from utility rate base,
they were converted to U.S. dollars using current foreign currency exchange
rates which resulted in a decrease of approximately $5,100,000 in retained
earnings in 1998.
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<TABLE>
NOTE 8 - INFORMATION ON INDUSTRY SEGMENTS
Operations Information:
<CAPTION>
Three Months Ended
March 31, 1999
Thousands of Dollars
UTILITY
Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 116,534 $ 40,345
Intersegment sales 3,689 199
Pretax operating income 29,674 10,140
Capital expenditures 8,024 -
Identifiable assets 1,575,186 392,195
NONUTILITY
<S> <C> <C> <C>
Oil and Independent
Coal* Natural Gas Power**
Sales to unaffiliated customers $ 43,438 $ 68,809 $ 18,234
Intersegment sales 9,904 4,400 238
Pretax operating income 7,746 3,441 667
Capital expenditures 1,634 10,314 246
Identifiable assets 236,726 296,810 110,028
NONUTILITY (continued)
<S> <C> <C>
Tele-
Communications Other
Sales to unaffiliated customers $ 19,775 $ 7,876
Intersegment sales 228 441
Pretax operating income (loss) 5,319 (1,832)
Capital expenditures 5,540 13
Identifiable assets 194,159 66,403
CORPORATE
Capital expenditures $ 408
Identifiable assets 244,552
RECONCILIATION TO CONSOLIDATED
<S> <C> <C> <C>
Segment Consolidated
Total Adjustments*** Total
Sales to unaffiliated customers $ 315,011 - $ 315,011
Intersegment sales 19,100 $ (19,100) -
Pretax operating income 55,156 - 55,156
Capital expenditures 26,179 (2,415) 23,764
Identifiable assets 3,116,059 - 3,116,059
* Sales under one coal contract with a single customer amounted to
$28,016,000.
** The Independent Power segments are dependent on a single customer and two
customers,
respectively, the losses of which would have a material adverse effect on the
segments.
*** Identifiable assets excludes intersegment receivables which are eliminated
for
consolidation. The adjustments include certain eliminations between the
business
segments.
</TABLE>
</PAGE>
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<TABLE>
Operations Information:
<CAPTION>
Three Months Ended
March 31, 1999
Thousands of Dollars
UTILITY
<S> <C> <C>
Electric Natural Gas
Sales to unaffiliated customers $ 116,798 $ 41,044
Intersegment sales 996 130
Pretax operating income 30,655 12,372
Capital expenditures 11,286 -
Identifiable assets 1,616,122 381,663
NONUTILITY
<S> <C> <C> <C>
Oil and Independent
Coal* Natural Gas Power**
Sales to unaffiliated customers $ 43,426 $ 48,627 $ 18,576
Intersegment sales 10,198 4,746 569
Pretax operating income (loss) 7,382 3,474 (1,887)
Capital expenditures 1,009 12,850 142
Identifiable assets 237,388 272,203 142,813
NONUTILITY (continued)
<S> <C> <C>
Tele-
Communications** Other
Sales to unaffiliated customers $ 20,680 $ 1,266
Intersegment sales 251 264
Pretax operating income (loss) 9,493 (1,259)
Capital expenditures 4,729 234
Identifiable assets 119,419 31,027
CORPORATE
Capital expenditures $ 2
Identifiable assets 33,916
RECONCILIATION TO CONSOLIDATED
<S> <C> <C> <C>
Segment Consolidated
Total Adjustments*** Total
Sales to unaffiliated customers $ 290,417 $ 290,417
Intersegment sales 17,154 $ (17,154) -
Pretax operating income 60,230 - 60,230
Capital expenditures 30,252 (1,352) 28,900
Identifiable assets 2,834,551 - 2,834,551
* Sales under one coal contract with a single customer amounted to
$25,104,000.
** The Telecommunications and Independent Power segments are dependent on a
single
customer and two customers, respectively, the losses of which would have a
material
adverse effect on the segments.
*** Identifiable assets excludes intersegment receivables which are eliminated
for
consolidation. The adjustments include certain eliminations between the
business
segments.
</TABLE>
</PAGE>
<PAGE>
NOTE 9 - SHAREHOLDERS' EQUITY
In 1998, the Company's Board of Directors authorized a share repurchase
program over the following five years to repurchase up to 10,000,000 shares, or
18 percent, of the Company's outstanding common stock. As of May 11, 1999, the
Company had 55,082,630 common shares outstanding. The repurchase of common
stock may be made, from time to time, on the open market or in privately
negotiated transactions. The number of shares to be purchased and the timing of
the purchases will be based on the level of cash balances, general business
conditions and other factors, including alternative investment opportunities.
Pursuant to this authorization, the Company entered into a Forward Equity
Acquisition Transaction (FEAT) program with a bank that provides the Company
with an option to acquire up to 2,500,000 shares of its common stock, but not to
exceed $125,000,000. In accordance with this agreement, in early May 1999, the
bank acquired 120,000 shares of Company stock at prices ranging from $63.45 to
$65.25.
The FEAT can be settled from time to time, at the Company's election, on either
a
full physical or net share settlement basis. The amount at which these
agreements
can be settled is dependent principally upon the market price of the Company's
common stock as compared to the forward purchase price per share and the number
of
shares to be settled. The maturity date on the FEAT program is October 31,
2000.
</PAGE>
<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
This discussion should be read in conjunction with the management's
discussion
included in the Company's Annual Report on Form 10-K for the year ended December
31, 1998.
Safe Harbor for Forward-Looking Statements:
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company in this Quarterly Report on Form 10-Q.
Forward-looking
statements include statements concerning plans, objectives, goals, strategies,
future events, or performance and underlying assumptions and other statements,
which
are other than statements of historical facts. Such forward-looking statements
may
be identified, without limitation, by the use of the words "anticipates",
"estimates", "expects", "intends", "believes," and similar expressions. From
time
to time, the Company or one of its subsidiaries individually may publish or
otherwise make available forward-looking statements of this nature. All such
forward-looking statements, whether written or oral, and whether made by or on
behalf of the Company or its subsidiaries, are expressly qualified by these
cautionary statements and any other cautionary statements which may accompany
the
forward-looking statements. In addition, the Company disclaims any obligation
to
update any forward-looking statements to reflect events or circumstances after
the
date hereof.
Forward-looking statements made by the Company are subject to risks and
uncertainties that could cause actual results or events to differ materially
from
those expressed in, or implied by, the forward-looking statements. These
forward-
looking statements include, among others, statements concerning the Company's
revenue and cost trends, cost recovery, cost-reduction strategies and
anticipated
outcomes, pricing strategies, planned capital expenditures, financing needs and
availability, changes in the utility industry, and the impacts of the year 2000
issue. Investors or other users of the forward-looking statements are
cautioned that such statements are not a guarantee of future performance by
the Company and that such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those
expressed in, or implied by, such statements. Some, but not all, of the risks
and uncertainties include
general economic and weather conditions in the areas in which the Company has
operations, competitive factors and the impacts of restructuring in the
electric,
natural gas, and telecommunications industries, sanctity and enforceability of
contracts, market prices, environmental laws and policies, federal and state
regulatory and legislative actions, drilling successes in oil and natural gas
operations, changes in foreign trade and monetary policies, laws and regulations
related to foreign operations, tax rates and policies, rates of interest and
changes
in accounting principles or the application of such principles to the Company.
Results of Operations:
The following discussion presents significant events or trends that have
had an
effect on the operations of the Company or which are expected to have an impact
on
operating results in the future.
</PAGE>
<PAGE>
For the Quarters Ended March 31, 1999 and 1998:
Net Income Per Share of Common Stock (Basic):
The Company reported consolidated net income of $0.60 per share for the
quarter
ended March 31, 1999, compared to first-quarter earnings of $0.64 per share a
year
earlier.
For the quarter, utility earnings were 25 cents a share compared to 34
cents
in the first quarter of 1998, while nonutility earnings were 35 cents a share
compared to 30 cents a year earlier.
Utility earnings were lower than anticipated for the quarter and 28
percent
below last year, principally because of 15 percent warmer weather than normal
for
this year's primary heating months compared to 9 percent warmer weather than
normal
for the same period in 1998. Utility income also was adversely impacted by
lower
than expected wholesale power prices in the Pacific Northwest and an increased
effective income tax rate.
Natural gas utility earnings decreased due to the warmer weather; offset
somewhat by increased customer growth. Increases in electric utility earnings
due
to higher sales of excess generation and more customers were offset by the
warmer
weather and increased electric transmission expenses associated with the higher
off
system sales.
In January 1999, a telecommunications customer exercised its option to prepay
the remaining 12-year initial term of a capacity agreement. The $257,000,000
prepayment is being recognized in revenues over the remaining term of the
agreement,
but because the amount was discounted for early payment, income in the first
quarter
of 1999 was approximately 3 cents per share lower than the same period a year
ago.
The prepayment will result in an annual decrease in telecommunications revenues
of
approximately $24,000,000 in each year compared to 1998.
The prepayment improved first-quarter investment income for the
corporation by
$2,500,000, but reduced Touch America's operating earnings for the same period
by
approximately $5,000,000. Touch America's other long distance, private line,
and
equipment services revenues increased more than 40 percent, but the increase was
reduced by higher operations expenses, especially increased payments to other
carriers, half of which were one time charges.
Operating income from independent power investments increased $6,000,000
in
the first quarter of 1999 compared to the same period a year earlier due to
improved
operations of generating plants in which Continental Energy Services holds an
equity
interest, a fuel contract settlement at one of these plants and lower project
development costs. Earnings also benefited from a tax settlement of
approximately
$1,200,000 with the State of New York. Coal, oil, and gas operations income
remained stable.
Coal earnings increased slightly for the first quarter of 1999 when
compared
to the same period in 1998. A 5 percent increase in volumes along with a
reduction
in depreciation expenses contributed to the business unit's improvement. Lower
coal
prices, resulting from last year's settlement of disputes with buyers, offset
most
of the improvement.
Earnings from nonutility oil and gas operations were flat as increased
natural
gas production and prices received were offset by decreases in oil production
and
prices, and increases in operating expenses.
</PAGE>
<PAGE>
For comparative purposes, the following table shows the breakdown of
consolidated net income per share by principal business segment.
Quarter Ended
March 31, March 31,
1999 1998
Utility operations $ 0.25 $ 0.34
Nonutility operations 0.35 0.30
Consolidated $ 0.60 $ 0.64
</PAGE>
<PAGE>
<TABLE>
UTILITY OPERATIONS
<CAPTION>
For Three Months Ended
March 31, March 31,
1999 1998
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C>
<C>
REVENUES:
Revenues $116,534 $ 116,798
Intersegment revenues 3,690 996
120,224 117,794
EXPENSES:
Power supply 38,687 39,967
Transmission and distribution 11,677 8,584
Selling, general, and administrative 13,753 13,306
Taxes other than income taxes 12,754 12,097
Depreciation and amortization 13,679 13,185
90,550 87,139
INCOME FROM ELECTRIC OPERATIONS 29,674 30,655
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 26,293 26,666
Gas supply cost revenues 14,052 14,378
Intersegment revenues 199 130
40,544 41,174
EXPENSES:
Gas supply costs 14,052 14,378
Other production, gathering, and exploration 793 645
Transmission and distribution 3,636 3,635
Selling, general, and administrative 5,755 4,568
Taxes other than income taxes 3,817 3,372
Depreciation, depletion, and amortization 2,351 2,204
30,404 28,802
INCOME FROM NATURAL GAS OPERATIONS 10,140 12,372
INTEREST EXPENSE AND OTHER INCOME:
Interest 14,438 13,445
Distributions on mandatorily redeemable preferred
securities of subsidiary trust 1,373 1,373
Other (income) deductions - net (1,284) (116)
14,527 14,702
INCOME BEFORE INCOME TAXES 25,287 28,325
INCOME TAXES 10,674 8,456
DIVIDENDS ON PREFERRED STOCK 923 923
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 13,690 $
18,946
</TABLE>
</PAGE>
<PAGE>
UTILITY OPERATIONS:
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Very cold winters increase
demand, while mild weather reduces demand. The weather's effect is measured
using degree-days. A degree-day is the difference between the average daily
actual temperature and a baseline temperature of 65 degrees. Heating degree-
days result when the average daily actual temperature is less than the
baseline. As measured by heating degree days, the temperatures for the first
quarter of 1999 in the Company's service territory were 9 percent warmer than
1998 and 15 percent warmer than the historic average. In addition, winter
weather for the primary heating months of January and February was 15 percent
warmer than normal.
See Note 1 - Deregulation and Asset Divestiture, and Other Regulatory
Matters in the Notes to the Consolidated Financial Statements for a
description of the transition in the electric and natural gas utility business
to competition.
For its regulated operations, the Company follows 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. Changes in regulation or changes in the competitive
environment could result in the Company not meeting the criteria of SFAS
No. 71. If the Company were to discontinue application of SFAS No. 71 for
some or all of its regulated operations, the regulatory assets and liabilities
related to those portions would have to be eliminated from the balance sheet
and included in income in the period when the discontinuation occurred unless
recovery of those costs was provided through rates charged to those customers
in a portion of the business that remains regulated. In conjunction with the
ongoing changes in the electric industry and the sale of its generation
assets, the Company will continue to evaluate the applicability of this
accounting principle to that business. Based upon the Company's anticipated
recovery of its regulatory assets in accordance with the electric
restructuring legislation and the amounts expected to be received from the
sale of the generation assets, the Company believes that the discontinuation
of regulatory accounting for its generation assets will not have a material
impact on the Company's financial position or results of operations.
The Company has existing long-term contracts for the purchase and sale
of electricity that have fixed price components. The Company would become
subject to commodity price risks associated with meeting these obligations to
the extent that these contracts are not addressed in the restructuring docket.
In one such contract discussed in Note 5, the Company has a commitment
to sell electricity, which includes a fixed-price for a portion of the
deliveries. When the sale of the Company's generation assets is finalized,
and to the extent this contract is not addressed in the electric restructuring
transition process, the Company will be subject to the commodity price risks
associated with supplying that portion of the contract. However, due to the
uncertainties relating to the other potential resources to supply the
contract, the timing of sale of the generation assets and the eventual outcome
of the electric restructuring process, the Company is unable at this time to
determine the potential future impacts of this contract on the Company's
results of operations.
</PAGE>
<PAGE>
<TABLE>
Electric Utility:
<CAPTION>
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Quarterly Average)
3/31/99 3/31/98 3/31/99 3/31/98 3/31/99
3/31/98
Revenues:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
<C>
Residential,
commercial and
government $ 75,924 $ 74,488 2 % 1,119 1,131 (1)% 283,489
279,473 1 %
Industrial 19,493 28,567 (32)% 354 656 (46)% 2,304 2,340
(2)%
General business 95,417 103,055 (7)% 1,473 1,787 (18)% 285,793
281,813 1 %
Sales to other
utilities 16,443 9,335 76 % 878 437 101 % 62 84 (26)%
Other 4,674 4,408 6 %
Intersegment 3,690 996 270 % 34 21 62 % 228 231 (1)%
Total $ 120,224 $117,794 2 % 2,385 2,245 6 % 286,083
282,128 1 %
Power Supply Expenses:
Hydroelectric $ 5,460 $ 5,664 (4)% 870 818 6 %
Steam 12,986 11,708 11 % 1,269 1,022 24 %
Purchases
and other 20,241 22,595 (10)% 551 795 (31)%
Total power supply $ 38,687 $ 39,967 (3)% 2,690 2,635 2
%
Cents per kWh $ 1.438 $ 1.517
</TABLE>
Revenues from industrial customers decreased in the first quarter of 1999
due primarily to customers moving toward choice in accordance with the Montana
electric customers choice law passed in 1997. As a result of electric
deregulation, beginning July 1, 1998, electric trading activity, including
buying and selling of electricity in the secondary markets, was conducted as a
nonutility activity. However, sales of electricity generated by the Company,
in excess of the needs for core customers, continue to be reflected in "sales
to other utilities" in the table above.
Sales to other utilities increased as a result of an increase in average
prices and increased steam generation due to increased plant availability.
Intersegment revenues and transmission and distribution expenses
increased as a result of transmitting excess energy sold by the nonutility to
markets outside of the Company's territory.
Purchase power expenses decreased primarily due to the transfer of the
electric trading activity to nonutility operations, partially offset by higher
prices.
Taxes other than income taxes increased primarily due to increased
property taxes resulting from increased property values and additional plant.
</PAGE>
<PAGE>
<TABLE>
Natural Gas Utility:
<CAPTION>
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Quarterly Average)
3/31/99 3/31/98 3/31/99 3/31/98 3/31/99
3/31/98
Revenues:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
<C>
Residential,
commercial and
government $ 34,849 $ 35,880 (3)% 7,820 8,115 (4)% 148,319
145,243 2 %
Industrial 466 642 (27)% 107 151 (29)% 402 399 1 %
Subtotal 35,315 36,522 (3)% 7,927 8,266 (4)% 148,721
145,642 2 %
Gas supply cost
Revenues (GSC) (14,052) (14,378) 2 %
General business
without GSC 21,263 22,144 (4)% 7,927 8,266 (4)% 148,721
145,642 2 %
Sales to other
utilities 288 250 15 % 94 94 0 % 3 3 0 %
Transportation 4,192 3,102 35 % 7,102 6,953 (34)% 20 21 (5)%
Other 550 1,170 (27)%
Total $ 26,293 $ 26,666 (1)% 12,580 15,313
(18)% 148,744 145,666 2 %
</TABLE>
Natural gas revenues, excluding gas supply cost revenues, decreased in
the first quarter of 1999 primarily due to a weather related reduction in
volumes sold. A slight increase in customer growth was partially offset by
decreased rates.
Transportation revenue increased primarily due to a current year
increase in the number of customers that chose their own supplier as a result
of a November 1, 1997 PSC order.
Taxes other than income taxes increased primarily due to increased
property taxes resulting from increased property values and additional plant.
An increase in the natural gas utility selling, general, and
administrative expenses resulted primarily from adjustments to the regulatory
liability relating to MPC Natural Gas Funding Trust (Trust). Expenses of the
Trust are offset by corresponding revenues; therefore the activity does not
affect operating income.
Other Income and Expense:
Interest expense increased in 1999 due to the issuance of long-term debt
associated with the Trust in December 1998 and additional long-term borrowing
with related parties. This was partially offset by a decrease in short-term
borrowing and the retirement of 7.7 percent First Mortgage Bonds, due February
1, 1999.
Income taxes increased in the first quarter 1999 due to a higher
effective tax rate along with an accelerated recognition of tax credits in
1998 as authorized by the PSC.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILTY OPERATIONS
For Three Months Ended
March 31, March 31,
1999 1998
Thousands of Dollars
COAL:
<S> <C>
<C>
REVENUES:
Revenues $ 43,438 $ 43,426
Intersegment revenues 9,904 10,198
53,342 53,624
EXPENSES:
Operations and maintenance 32,332 31,765
Selling, general, and administrative 5,022 5,052
Taxes other than income taxes 6,357 6,689
Depreciation, depletion, and amortization 1,885 2,736
45,596 46,242
INCOME FROM COAL OPERATIONS 7,746 7,382
OIL AND NATURAL GAS:
REVENUES:
Revenues 68,809 48,627
Intersegment revenues 4,400 4,746
73,209 53,373
EXPENSES:
Operations and maintenance 58,951 38,809
Selling, general, and administrative 4,228 4,362
Taxes other than income taxes 1,024 1,351
Depreciation, depletion, and amortization 5,565 5,377
69,768 49,899
INCOME FROM OIL AND NATURAL GAS OPERATIONS 3,441 3,474
INDEPENDENT POWER:
REVENUES:
Revenues 18,234 18,576
Earnings from unconsolidated investments 5,333 1,553
Intersegment revenues 238 569
23,805 20,698
EXPENSES:
Operations and maintenance 15,734 18,673
Selling, general, and administrative 830 974
Taxes other than income taxes 463 466
Depreciation, depletion, and amortization 777 919
17,804 21,032
INCOME (LOSS) FROM INDEPENDENT POWER OPERATIONS $ 6,001 $
(334)
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS (continued)
For Three Months Ended
March 31, March 31,
1999 1998
Thousands of Dollars
TELECOMMUNICATIONS:
<S> <C>
<C>
REVENUES:
Revenues $ 19,775 $ 20,680
Earnings from unconsolidated investments 1,423 2,080
Intersegment revenues 228 251
21,426 23,011
EXPENSES:
Operations and maintenance 8,446 6,187
Selling, general, and administrative 2,782 2,464
Taxes other than income taxes 1,040 1,245
Depreciation, depletion, and amortization 2,415 1,542
14,683 11,438
INCOME FROM TELECOMMUNICATIONS OPERATIONS 6,743 11,573
OTHER OPERATIONS:
REVENUES:
Revenues 7,876 1,266
Intersegment revenues 441 264
8,317 1,530
EXPENSES:
Operations and maintenance 7,431 1,516
Selling, general, and administrative 1,324 (154)
Taxes other than income taxes 313 304
Depreciation, depletion, and amortization 1,081 1,123
10,149 2,789
INCOME (LOSS) FROM OTHER OPERATIONS (1,832) (1,259)
INTEREST EXPENSE AND OTHER INCOME:
Interest 2,104 2,229
Other (income) deductions - net (5,497) (2,783)
(3,393) (554)
INCOME BEFORE INCOME TAXES 25,492 21,390
INCOME TAXES 6,281 5,392
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 19,211 $
15,998
</TABLE>
</PAGE>
<PAGE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations increased slightly compared to the same
period last year. Revenues from the Rosebud mine decreased $1,900,000. Both
volume and price of coal sold to the Colstrip Units decreased by approximately
7 percent. The price reduction was the result of a $2,700,000 refund to a
customer for final pit reclamation funds previously collected. The customer
has agreed to be responsible for a portion of all final pit reclamation
expenses in the future. These decreases were partially offset by sales to a
midwest utility for purposes of conducting test burns. Revenues from the
Jewett mine increased $2,900,000 as a result of a 14 percent increase in tons
sold and an increase in reimbursable mining expenses. These increases were
partially offset by a 2 percent decrease in price.
Coal operation and maintenance expense increases at Jewett caused by
higher production and stripping costs were partially offset by lower costs at
the Rosebud mine due to a $2,700,000 credit to reclamation expenses associated
with the refund discussed above and the decrease in tons sold. Depreciation,
depletion, and amortization decreased as a result of some equipment at the
Rosebud mine becoming fully depreciated in 1998.
Oil and Natural Gas Operations:
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenue and the related percentage
changes in volumes sold and prices received:
Oil -revenue $ ( 1)
-volume (23)%
-price/bbl (32)%
Natural gas -revenue $ 22
-volume 52 %
-price/Mcf 1 %
Miscellaneous $ (1)
Income from oil and natural gas operations remained relatively flat
compared to the first quarter of 1998. Revenues from oil operations decreased
as a result of both lower volumes and prices. Natural gas revenues increased
mainly due to higher volumes resulting from increased marketing and trading
activity. Miscellaneous revenues decreased as a result of lower processing
revenues.
Operation and maintenance expense increased as a result of higher
purchased gas costs associated with the increased marketing activity.
Independent Power Operations:
Earnings from unconsolidated investments for the first quarter 1999
increased $3,800,000 primarily as a result of improved operations at
generating plants in which Continental Energy Services holds an equity
interest and a fuel contract settlement at one of these plants. In addition,
there was a $2,900,000 reduction in operations and maintenance expense related
to the decrease in project development costs resulting from the development of
a domestic investment opportunity. These costs were capitalized in the third
quarter 1998.
</PAGE>
<PAGE>
Telecommunications Operations:
Income from telecommunications operations decreased by approximately
$4,800,000 primarily due to prepayment on a capacity agreement. The amounts
to be received over the remaining 12-year term of this contract were
discounted for early payment and are being recognized in revenues over the
remaining life of the contract. This discounting resulted in revenues for the
first quarter of 1999 being approximately $5,000,000 lower than in 1998. These
decreases were partially offset by revenues of $1,000,000 on two new
contracts. In addition, revenues from equipment services rose by $700,000 and
long distance revenues increased by approximately $1,500,000. Earnings from
unconsolidated investments decreased by $700,000 due to reduced recognition of
dark fiber sales on the portions of the Company's fiber network still under
construction.
Expenses for the first quarter were higher due to increased payments to
other carriers, half of which were one-time charges, and increased maintenance
expense resulting from increased activity on the fiber optic network.
Other Operations:
Revenues and expenses of other operations increased primarily due to
increased electric trading activities of the Montana Power Trading and
Marketing Company (MPT&M). The Company is in the process of selling its
generation assets but has remained in the electric trading business to the
extent necessary to sell excess generation or buy needed electricity until the
sale of the generation assets is complete.
Other Income:
Other (income) and deductions - net increased by $2,700,000 largely due
to income from investments made with the funds received in the
telecommunications prepayment discussed above.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Activities --
Net cash provided by operating activities was $345,798,000 during the
period compared to $78,998,000 in the first quarter 1998. The current year
increase of $266,800,000 was due primarily to a $257,000,000 prepayment
received from a telecommunications customer in January 1999 to prepay the
remaining 12-year initial term of a capacity agreement. The prepayment was
recorded as deferred revenue and will be amortized over the remaining term of
the contract. Tax laws require that the prepayment be reported as income in
the year received, therefore this will result in a 1999 tax payment of
approximately $100,000,000.
Investing Activities --
Net cash used for investing activities was $18,071,000 during the period
compared to $18,293,000 in the first quarter 1998. The current year decrease
of $222,000 was due primarily to the decrease in property sales and
investments in 1999, mostly offset by a decrease in capital expenditures.
Financing Activities --
On February 1, 1999, the Company used the proceeds from asset backed
securities issued by the Montana Power Natural Gas Funding Trust to retire
$55,000,000 of 7.7 percent First Mortgage Bonds.
</PAGE>
<PAGE>
The Company's consolidated borrowing ability under its Revolving Credit
and Term Loan Agreements was $178,600,000, of which $134,000,000 was unused at
March 31, 1999. The Company also has short-term borrowing facilities with
commercial banks that provide both committed and uncommitted lines of credit,
and the ability to sell commercial paper.
For information regarding the Company's authorization to repurchase
common stock, refer to Part 1, "Notes to the Consolidated Financial
Statements - Note 9."
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended March 31, 1999, the Company's ratio of
earnings to fixed charges was 3.29 times. Fixed charges include interest,
distributions on preferred securities of a subsidiary trust, the implicit
interest of the Colstrip Unit 4 rentals and one-third of all other rental
payments.
YEAR 2000 COMPLIANCE:
The Year 2000 issue, known as Y2K, relates to the ability of systems,
including computer hardware, software, and embedded microprocessors, to
properly interpret date information relating to the year 2000. Many existing
systems, including some of the Company's systems, use only the last two digits
to refer to a year. Therefore, these systems may not properly recognize a
year that begins with "20" instead of "19". If not corrected, these systems
could fail or create erroneous results.
The Company has a corporate-wide strategy to address Y2K issues. An
Executive Steering Committee was established to coordinate and oversee
implementation of the strategy in the business units. The strategy includes a
three-step process and a contingency plan. The first step involves
inventorying critical information technology (IT) systems and non-information
(non-IT) systems including third party computer hardware and software, and
embedded electronic microprocessors. During the second step, the Company
conducts certain analyses to determine the system's Y2K readiness. The third
step consists of replacing/repairing and testing the systems to ensure the
availability and integrity of the systems. Simultaneous with those three
steps, the Company is developing a contingency plan to address unanticipated
failure of the systems.
Inventorying of the critical IT systems is complete. This involves
computer systems within the Company's main business office, such as accounting
systems, human resource systems, materials management systems, and work
management systems. Analysis of the inventory is also complete. Of the IT
systems inventoried, over 75 percent have already been deemed ready based on
testing or representations from the manufacturers. The Company is working to
have all of its critical systems Y2K ready by July 1, 1999. Currently, the
Company believes that of the systems inventoried, two critical IT systems, the
Customer Information System, which provides utility customer billing and field
operations support, and Interval Meter Programming and Data Collection
Software (which are needed for the Customer Billing Process) are not Y2K
compliant. The Company is pursuing a billing outsourcing solution that is
expected to be in place by August 1, 1999. Y2K compliant versions of the
Meter Programming and Data Collection Software have been announced and are
expected to be installed and ready by August 1, 1999. In the event this or
any other critical system fails in spite of efforts to be ready, contingency
plans are being developed.
Inventorying of critical non-IT systems is 94 percent completed.
Analysis of the inventory is 88 percent completed. Approximately 86 percent
of the systems that have been inventoried have been deemed Y2K ready based on
testing or representations from the manufacturers. The Company is working to
have all of its non-IT critical systems Y2K ready by July 1, 1999. Among the
</PAGE>
<PAGE>
Company's critical non-IT systems that will not be ready by that date are the
Energy Management System, which provides system control and data acquisition
for the Company's electric transmission system, and continuous emission
monitoring systems, which monitor stack gas emissions at the Corette and
Colstrip Plants. A Y2K solution for the energy management system is expected
to be implemented by August 1, 1999, and for the emission monitors by
September 1, 1999. Contingency plans are being developed in the event systems
fail in spite of the Company's efforts to be ready.
The Year 2000 issue may also impact other entities with which the
Company transacts business or with which the Company's electric and natural
gas systems are interconnected. Each of the business units has been
contacting suppliers, vendors, and key customers to assess their Year 2000
readiness. Currently, the Company has not been advised that Y2K impacts to
vendors, customers, or suppliers' systems will significantly impact its
operations. In addition, because of the interconnected nature of electric
systems, the North American Electric Reliability Council (NERC) is
facilitating the preparations of electric systems in North America for
operation into the year 2000. As part of its Year 2000 program, NERC monitors
the monthly progress of industry efforts to prepare critical systems for the
year 2000. NERC held a national drill on April 9, 1999 to assess industry
preparation. The Company participated in the drill and deemed its performance
successful. NERC plans another drill in September 1999 in which the Company
plans to participate.
The Company has not established a formal process to track either
external or internal Y2K expenditures. Many of the measures that will
mitigate Y2K impacts coincide with normal operations and maintenance, so are
not accounted for separately as Y2K expenditures. For example, the capital
upgrade to the energy management system, which is necessary in any event to
provide additional functionality, will also result in a Y2K benefit and cost
$460,000. An additional $36,000 to test custom software associated with the
energy management system and the upgrade software is explicitly accounted for
as a Y2K expense. Likewise, the Company is implementing a new method of
customer billing which will cost $3,100,000 and although it will address the
Y2K issue, in any case, the new method was planned to satisfy deregulation
requirements. In addition, the central information services department,
estimates that through 1998 it spent approximately $1,100,000 to address the
Y2K issue and anticipates spending another $1,400,000 in 1999. Although it is
not currently possible to estimate the overall cost of required modifications,
the Company presently believes that the ultimate cost of this work will not
have a material effect on the Company's current financial position, liquidity,
or results of operations.
Except as described above, the Company expects all necessary
modifications and testing of its critical IT and critical non-IT systems to be
completed by July 1, 1999. Also, as previously discussed, contingency plans
will be in place. The most reasonably likely worst case Y2K scenario
envisioned by the Company is that some customers could experience
interruptions in service.
The above information is a Year 2000 Readiness Disclosure pursuant to
the Federal Year 2000 Information and Readiness Disclosure Act.
NEW ACCOUNTING PRONOUNCEMENTS:
In June 1998, the Financial Accounting Standards Board (FASB) issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities".
SFAS No. 133 requires that all derivative instruments be recorded on an
entity's balance sheet at fair value. The statement also expands the
definition of a derivative. Changes in the fair value of the derivatives are
recognized each period either in current earnings or as a component of
comprehensive income, depending on whether the derivative is designated as
</PAGE>
<PAGE>
part of a hedge transaction, and if so, what type of hedge transaction. The
statement distinguishes between fair-value hedges, defined as hedges of the
Company's assets, liabilities, or firm commitments, and cash-flow hedges,
defined as hedges of future cash flows related to a variable rate asset or
liability or a forecasted transaction. Recognition of changes in the fair
value of a hedge, determined to be a fair-value hedge, will generally be
offset in the income statement by the recognition of the change in the fair
value of the hedged item. Recognition of changes in the fair value of a cash-
flow hedge will be reported as a component of comprehensive income. The gains
or losses on the derivative instruments that are reported in comprehensive
income will be reclassified into current earnings in the periods in which the
earnings are impacted by the variability of the cash flows of the hedged item.
The ineffective portion of all hedges will be recognized in current earnings.
The new statement is effective for all fiscal quarters of all fiscal
years beginning after June 15, 1999. The Company has not yet determined the
impact that the adoption of the new standard will have on its earnings or
financial position.
During 1998, EITF of the FASB released Issue 98-10 (EITF 98-10),
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities". EITF 98-10 addresses the accounting for energy contracts and
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 is effective for the fiscal years beginning after December 15,
1998. The Company adopted EITF as of January 1, 1999 and accordingly marked
all of its "trading activities" contracts to market as of March 31, 1999 and
recognized a corresponding loss that was not material in the results of
operations for the quarter. The cumulative effect on prior year's financial
position, of the adoption of EITF 98-10 was also not material.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
The Company is exposed to the market risks associated with fluctuations
in commodity prices, interest rates, and changes in foreign currency
translation. The Company's Risk Management Committee approves the risk-related
activities in which the Company participates, the types of instruments that
may be used, and recommends to the Company's Audit Committee of the Board of
Directors specific limits for trading activity.
Trading Instruments:
The Company's value-at-risk for natural gas physical and financial
transactions (VaR) is based on J.P. Morgan's RiskMetrics T approach (i.e.
variance/co-variance), which uses historical estimates of volatility and
correlation and values optionality using delta equivalents. Because actual
future changes in markets (prices, volatilities, and correlations) may be
inconsistent with historical observations, the Company's VaR may not
accurately reflect the potential for future adverse changes in fair values.
The Company's VaR is based on a forward 24-month time period and assumes a
one-day holding period and a 95 percent confidence level. As of March 31,
1999, the Company's VaR calculation for these natural gas physical and
financial transactions was less than $2,000,000. At March 31, 1999, the
Company held only immaterial financial derivative contracts relating to oil or
natural gas liquids.
Other Financial Instruments:
Since December 31, 1998, there has been no material change in the
Company's other financial instruments or the corresponding market risks
associated with these instruments.
</PAGE>
<PAGE>
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
For information regarding the Kerr Project environmental remediation,
Project 2188 relicensing and the Reliant Energy Lignite Supply Agreement
dispute, refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 2."
ITEM 2. Changes in Securities and Use of Proceeds:
On March 12, 1999 the Company announced that it had amended that certain
Rights Agreement dated as of June 6, 1989, between the Company and First
Chicago Trust Company of New York (the Agreement).
The amendment, which was authorized by the Board of Directors of the
Company at a meeting held on January 26, 1999 (i) extends the Agreement
through June 6, 2009; (ii) changes the Purchase Price of each one-hundredth of
a Preferred Share to $200 and (iii) excepts certain inadvertent owners from
the definition of "Acquiring Person" under the Agreement.
On March 12, 1999, the Company filed Forms 8-A/A and 8-K, including the
amendment as an exhibit thereto, with the Securities and Exchange Commission.
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
March 31, 1999.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K
DATE SUBJECT
January 26, 1999 Item 5 Other Events. Discussion of Fourth
Quarter Net Income.
Item 7 Exhibits. Preliminary Consolidated
Statements of Income for the Quarters
Ended March 31, 1999 and 1998 and for the
Twelve Months Ended March 31, 1999 and
1998. Preliminary Utility Operations
Schedule of Revenues and Expenses for the
Quarters Ended March 31, 1999 and 1998
and for the Twelve Months Ended March 31,
1999 and 1998. Preliminary Nonutility
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1999 and 1998 and for the Twelve Months
Ended December 31, 1999 and 1998.
March 2, 1999 Item 5 Other Events. The Company Amends
Rights Agreement.
</PAGE>
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE MONTANA POWER COMPANY
(Registrant)
By /s/ J. P. Pederson
J. P. Pederson
Vice President and Chief
Financial and Information
Officer
Dated: May 17, 1999
</PAGE>
<PAGE>
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
March 31,1999
Net Income $ 152,601
Income Taxes 81,281
$ 233,882
Fixed Charges:
Interest $ 65,290
Amortization of Debt Discount,
Expense, and Premium 1,547
Rentals 35,118
$ 101,955
Earnings Before Income Taxes
and Fixed Charges $ 335,837
Ratio of Earning to Fixed Charges 3.29 x
</PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 3/31/99, the Consolidated Income Statement and the
Consolidated Statement of Cash Flows for the three months ended 3/31/99 and is
qualified in it entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,503,076
<OTHER-PROPERTY-AND-INVEST> 724,546
<TOTAL-CURRENT-ASSETS> 519,223
<TOTAL-DEFERRED-CHARGES> 369,214
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,116,059
<COMMON> 702,879
<CAPITAL-SURPLUS-PAID-IN> 2,133
<RETAINED-EARNINGS> 396,381
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,101,393
65,000
57,654
<LONG-TERM-DEBT-NET> 727,301
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 40,954
0
<CAPITAL-LEASE-OBLIGATIONS> 428
<LEASES-CURRENT> 390
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,122,939
<TOT-CAPITALIZATION-AND-LIAB> 3,116,059
<GROSS-OPERATING-REVENUE> 321,768
<INCOME-TAX-EXPENSE> 16,956
<OTHER-OPERATING-EXPENSES> 259,855
<TOTAL-OPERATING-EXPENSES> 276,811
<OPERATING-INCOME-LOSS> 44,957
<OTHER-INCOME-NET> 3,869
<INCOME-BEFORE-INTEREST-EXPEN> 48,826
<TOTAL-INTEREST-EXPENSE> 15,002
<NET-INCOME> 33,824
923
<EARNINGS-AVAILABLE-FOR-COMM> 32,901
<COMMON-STOCK-DIVIDENDS> 22,032
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 345,798
<EPS-PRIMARY> 0.60
<EPS-DILUTED> 0.59
</TABLE>
