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 September 30, 1996
-- 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 November 8, 1996, the Company had 54,630,994 shares of common stock
outstanding.
<TABLE>
<CAPTION>
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Nine Months Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
REVENUES $ 678,397 $ 683,347
EXPENSES:
Operations 279,711 309,386
Maintenance 47,019 52,922
Selling, general and administrative 75,029 75,505
Taxes other than income taxes 64,561 69,640
Depreciation, depletion and amortization 65,138 66,379
531,458 573,832
INCOME FROM OPERATIONS 146,939 109,515
INTEREST EXPENSE AND OTHER INCOME:
Interest 36,438 32,635
Other (income) deductions-net (4,146) (6,580)
32,292 26,055
INCOME TAXES 41,817 25,407
NET INCOME 72,830 58,053
DIVIDENDS ON PREFERRED STOCK 5,420 5,420
NET INCOME AVAILABLE FOR COMMON STOCK $ 67,410 $ 52,633
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,634 53,986
NET INCOME PER SHARE OF COMMON STOCK $ 1.23 $ 0.97
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Quarter Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
REVENUES $ 216,073 $ 217,407
EXPENSES:
Operations 89,058 100,268
Maintenance 18,360 16,900
Selling, general and administrative 24,580 24,337
Taxes other than income taxes 21,747 24,580
Depreciation, depletion and amortization 23,032 21,955
176,777 188,040
INCOME FROM OPERATIONS 39,296 29,367
INTEREST EXPENSE AND OTHER INCOME:
Interest 12,803 11,012
Other (income) deductions-net (1,738) (3,622)
11,065 7,390
INCOME TAXES 10,002 5,825
NET INCOME 18,229 16,152
DIVIDENDS ON PREFERRED STOCK 1,807 1,807
NET INCOME AVAILABLE FOR COMMON STOCK $ 16,422 $ 14,345
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,632 54,243
NET INCOME PER SHARE OF COMMON STOCK $ 0.30 $ 0.26
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
September 30, December 31,
1996 1995
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $67,955 and $57,095
plant under construction)
Electric $ 1,755,004 $ 1,713,133
Natural gas 510,766 492,431
2,265,770 2,205,564
Less - accumulated depreciation and depletion 703,619 663,215
1,562,151 1,542,349
NON-UTILITY PROPERTY (includes $31,904 and $15,887
property under construction) 653,314 631,901
Less - accumulated depreciation and depletion 254,261 252,613
399,053 379,288
1,961,204 1,921,637
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 56,428 57,013
Reclamation fund 42,295
Other 48,531 46,966
147,254 103,979
CURRENT ASSETS:
Cash and temporary cash investments 20,634 15,541
Accounts receivable 99,568 152,386
Materials and supplies (principally at average cost) 40,380 42,194
Prepayments and other assets 51,938 46,172
Deferred income taxes 15,828 15,899
228,348 272,192
DEFERRED CHARGES:
Advanced coal royalties 20,262 20,175
Regulatory assets related to income taxes 148,359 148,350
Regulatory assets - other 68,269 68,637
Other deferred charges 55,465 51,121
292,355 288,283
$ 2,629,161 $ 2,586,091
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
September 30, December 31,
1996 1995
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,632,075 and
54,614,481 shares issued) $ 691,952 $ 691,043
Retained earnings and other shareholders' equity 286,893 285,000
Unallocated stock held by trustee for retirement
savings plan (28,930) (30,565)
949,915 945,478
Preferred stock 101,416 101,416
Long-term debt 628,866 616,574
1,680,197 1,663,468
CURRENT LIABILITIES:
Short-term borrowing 119,828 96,348
Long-term debt - portion due within one year 23,590 24,804
Dividends payable 23,640 23,668
Income taxes 9,024 9,937
Other taxes 55,467 43,302
Accounts payable 50,736 63,920
Interest accrued 14,656 12,341
Other current liabilities 53,532 63,488
350,473 337,808
DEFERRED CREDITS:
Deferred income taxes 325,906 320,736
Investment tax credit 45,713 47,001
Accrued mining reclamation costs 127,566 122,008
Other deferred credits 99,306 95,070
598,491 584,815
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,629,161 $ 2,586,091
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Nine Months Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 72,830 $ 58,053
Noncash charges (credits) to net income:
Depreciation and depletion 65,138 66,379
Mining reclamation costs expensed 12,808 13,181
Earnings from unconsolidated investments (8,497) (796)
Deferred income taxes. 3,937 5,563
Amortization of loss on long-term sales
of power (1,717) (2,448)
Other - net 20,444 16,921
Changes in other assets and liabilities (12,561) 8,538
Accounts receivable 52,818 48,066
Materials and supplies 1,814 281
Accounts payable (13,184) 873
Payment of mining reclamation costs (7,250) (9,027)
Net Cash Flows from Operating Activities 186,580 205,584
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (108,015) (138,849)
Sales of property 6,187 5,014
Reclamation funding (42,295)
Additional investments (1,871) (6,292)
Net Cash Flows from Investing Activities (145,994) (140,127)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock 813 17,314
Issuance of long-term debt 18,812 30,880
Retirement of long-term debt (7,591) (2,547)
Short-term debt 23,481 (45,633)
Dividends on common and preferred stock (71,008) (70,037)
Net Cash Flows from Financing Activities (35,493) (70,023)
Change in Cash Flows 5,093 (4,566)
Cash and cash equivalents at beginning of period 15,541 21,564
Cash and cash equivalents at end of period $ 20,634 $ 16,998
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Nine Months For:
Income taxes $ 38,793 $ 31,662
Interest 34,670 32,180
The accompanying notes are an integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying financial statements of the Company for the interim
periods ended September 30, 1996 and 1995 are unaudited but, in the opinion of
management, reflect all adjustments, consisting only of 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, 1995.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1996 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1. CONTINGENCIES AND COMMITMENTS:
In 1990, pursuant to a Federal Energy Regulatory Commission (FERC)
license obligation, the Company proposed a plan to protect fish, wildlife and
habitat affected by the operation of the Kerr Project (Project), which would
cost the Company $15,600,000 initially and, thereafter, $965,000 annually. The
United States Department of Interior (Department) has proposed an alternative
to the plan which the Company estimates would cost approximately $45,000,000
initially and, thereafter, $1,300,000 annually. An Environmental Impact
Statement prepared by the FERC staff finds that the Department's alternative
is preferable from an environmental perspective to the Company's plan, but
would cost significantly more. In addition to requiring expenditures for
environmental mitigation, the alternative proposed by the Department would
also change the operation of the Project from a peaking to a baseload
operation. Together, these factors may cause the operation of the Project to
be uneconomic based on current energy price forecasts. In an attempt to reduce
these costs and assure continued access to low cost power from the Project,
the Company has offered an early transfer of the license to its joint-
licensee, the Confederated Salish and Kootenai Tribes. The Company does not
know when this matter will be resolved or what the resolution will be.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. The net present value of relicensing, including physical
improvements and non-operational (environmental) mitigation, is estimated at
$151,000,000. In addition, operational mitigation is expected to decrease
project capability by 26 megawatts. The FERC staff is expected to issue a
draft environmental impact statement in early 1997.
The Company has brought an action against Puget Sound Power & Light
Company (Puget) in the U.S. Court for the District of Montana seeking a
determination that the Company is in compliance with an agreement to sell
Puget 94 megawatts of power annually to the year 2010. This action arose out
of an allegation by Puget that the Company had breached the agreement by
failing to provide firm contractual rights to a transmission path for the
power, thereby entitling Puget to terminate the agreement. Should it be
determined that Puget is entitled to terminate the agreement, the Company
would be obligated to reimburse Puget for approximately $40,000,000, excluding
interest, as the termination amount calculated under the contract. In
addition, the Company's future revenues would be reduced by the difference, if
any, between sales at prices under the agreement, approximately $30,000,000
per year, and prices it might receive from alternative sales. Puget has also
alleged that it is entitled to reimbursement for the excess of the cost of
power purchased under the agreement after February 1995, over the cost which
Puget alleges it would have paid for such power elsewhere. The Company may be
required to write down assets related to the agreement by approximately
$26,000,000, before taxes. The Company believes that Puget's intention is to
reduce its purchase power costs, since the price of power under the agreement
is in excess of current market rates. While confident of its position, the
Company cannot be certain of the decision in this proceeding. Trial is
scheduled to begin in Butte, Montana on February 24, 1997.
Western Energy Company (Western) was a party in an arbitration initiated
by the non-operating owners of the Colstrip Units 3 & 4 (i.e., Puget,
Washington Water Power Company, Portland General Electric Company and
PacifiCorp -- collectively, the "Buyers") to resolve a variety of disputes
arising under the contracts with Western for the supply and transportation of
coal for these Units. The arbitrator's decision on May 6, 1996, which was
favorable to Western, did not materially affect Western Energy's financial
position or results of operations.
Continental Energy Services, Inc., a wholly owned subsidiary of the
Company, is a general partner in a partnership (the Partnership) formed to
construct and own a 248 megawatt power plant at Frederickson, Washington. The
Partnership contracted to sell the output of this plant to the Bonneville
Power Administration (BPA) over a 20-year period. In May of 1995, BPA
informed the Partnership that it would not purchase the power. BPA alleged
that its purposes for entering into the power purchase contract have been
frustrated and, consequently, it is excused from performance. The Partnership
halted construction of the plant and sued BPA, seeking damages, including lost
future profits. This matter has been referred to binding arbitration by the
United States Court of Federal Claims. The arbitration hearing is scheduled
to begin in February 1997. This dispute will not have a materially adverse
affect on the Company's consolidated financial position or its consolidated
results of operation.
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 2. RATE MATTERS:
Effective July 1, 1996, the Montana Public Service Commission (MPSC)
approved a rate plan for the Electric Utility, affirming a settlement
negotiated with the Montana Consumer Counsel and the Large Customer Group,
which was designed to increase revenues 4.2 percent or $14,800,000 annually.
This increase includes $5,800,000 which had previously been approved on an
interim basis, effective March 1, 1996. The plan also includes revenue
increases of 2.4 percent or approximately $8,800,000 on January 1, 1997 and
2.4 percent or approximately $9,000,000 on January 1, 1998. The MPSC's final
order was based on an 11 percent return on common equity. Actual earnings in
excess of 11.4 percent return on common equity will be shared on a 50 percent
basis between ratepayers and shareholders. In the event that the Company's
electric year-end return on equity falls below 10.2 percent and subject to
Internal Revenue Service approval, additional amounts of Accumulated Deferred
Investment Tax Credit (ADITC) will be flowed through to shareholders. The
amount of ADITC to be flowed through, if any, will be limited to a cumulative
amount of $7,000,000 for the years 1996 through 1998.
The rate order also included the approval of a natural gas revenue
increase which was designed to increase revenues 5.3 percent or $6,700,000
annually, effective July 1, 1996. This increase includes $3,100,000 which had
been included in rates on an interim basis, effective March 1, 1996. The
increase was based on an 11.25 percent equity return.
On July 29, 1996, the Company filed a natural gas rate case requesting
an increase in natural gas revenues of $4,800,000 or 3.8 percent annually to
recover increased costs of service and to facilitate the Gas Utility's
restructuring plan. The plan proposes a lower threshold in transportation
eligibility, thereby increasing the number of customers eligible to choose
their own suppliers. Within five years, all customers would have this choice.
The plan requests the recovery of all Gas Utility investment. A hearing on the
filing has been scheduled for February 18, 1997. The Company cannot predict
when a decision will be rendered.
The Company is preparing a similar electric restructuring plan, which is
expected to be filed with the MPSC prior to year end 1996.
NOTE 3. FINANCIAL INSTRUMENTS:
To manage price risk, swap and collar agreements are used to hedge
anticipated production and sales of oil and non-regulated natural gas. Under
swap agreements, the Company receives or makes payments based on the
differential between a specified price and the market price of oil or natural
gas when the hedged production is sold. Under collar agreements, the Company
makes or receives monthly payments when the actual price of oil exceeds the
ceiling or drops below the floor established in the agreement. At
September 30, 1996, the Company had swap agreements to hedge approximately
88,450 barrels of oil, 39 percent of its expected production through November
1996. In addition, the Company had swap agreements to hedge approximately
900 Mmcf of non-regulated natural gas, 22 percent of its delivery obligations
under long-term natural gas sales contracts through February 1997. At
September 30, 1996, the Company had no material gains or losses from financial
instrument transactions.
Continental Energy Services, Inc. has investments in independent power
partnerships, some of which have entered into derivative financial instruments
to hedge against interest rate exposure on floating rate debt and foreign
currency and gas price fluctuations. The Company believes it will not
experience any materially adverse impacts from the risks inherent in these
instruments.
NOTE 4. MANDATORILY REDEEMABLE PREFERRED SECURITIES OF MONTANA POWER
CAPITAL I:
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). On November 6, 1996, the Trust publicly issued
2,600,000 8.45% Cumulative Quarterly Income Preferred Securities, Series A
(QUIPS), representing preferred beneficial interests in the assets held by the
Trust, indirectly resulting in net proceeds to the Company of $ 62,600,000.
Holders of the QUIPS are entitled to receive quarterly distributions at an
annual rate of 8.45% of the liquidation preference value of $25 per security.
The Company is the owner of all the common trust securities, which constitute
3 percent of the aggregate liquidation amount of all the Trust Securities. The
sole asset of the Trust is $ 67,000,000 of Junior Subordinated Deferrable
Interest Debentures, 8.45% Series due 2036 (Subordinated Debentures), issued
by the Company, interest on which is deductible by the Company for income tax
purposes. The Trust will use interest payments received on the Subordinated
Debentures it holds to make the quarterly cash distributions on the QUIPS.
The QUIPS are subject to mandatory redemption upon repayment of the
Subordinated Debentures at maturity or redemption. The Company has the option
at any time on or after November 6, 2001, to redeem the Subordinated
Debentures, in whole or in part. The Company also has the option, upon the
occurrence of certain events, (i) to redeem the Subordinated Debentures, in
whole but not in part, which would result in the redemption of all the Trust
Securities, or (ii) to terminate the Trust and cause the pro rata distribution
of the Subordinated Debentures to the holders of the Trust Securities.
In addition to the Company's obligations under the Subordinated
Debentures, the Company has guaranteed, on a subordinated basis, payment of
distributions on the Trust Securities, to the extent the Trust has funds
available to pay such distributions, and has agreed to pay all of the expenses
of the Trust (such additional obligations collectively, the Back-up
Undertakings). Considered together with the Subordinated Debentures, the Back-
up Undertakings constitute a full and unconditional guarantee by the Company
of the Trust's obligations under the QUIPS.
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, 1995.
RESULTS OF OPERATIONS:
The following discussion presents significant events or trends which have
had an effect on the operations of the Company or which are expected to have an
impact on operating results in the future. The information also contains
forward-looking statements. Actual results and events may differ significantly
from those discussed in the forward-looking statements.
Nine Months Ended September 30, 1996 and 1995:
Net Income Per Share of Common Stock:
Consolidated net income for the nine months ended September 30, 1996 was
$67,400,000, or $1.23 per share compared with $52,600,000, or 97 cents per
share for the same period a year ago. Increased rates, 10% colder weather,
continued customer growth and reduced power supply expenses contributed to an
increase in Utility earnings. This increase was larger than the 13 cents per
share positive impact recorded in 1995 for a coal contract arbitration
decision. The 24 cents per share increase in Non-Utility earnings was due
primarily to growth in earnings from independent power investments and the
absence of losses at the Colorado mine and the coal arbitration decision
recorded in 1995. The increase was partially offset by decreased coal sales at
the Rosebud mine resulting from the expiration of a Midwestern coal contract
and reduced generation at the Colstrip units. A more detailed discussion of
the individual operations follows.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Nine Months Ended
September 30,
1996 1995
Utility Operations $ 0.68 $ 0.66
Non-Utility Operations 0.55 0.31
Consolidated $ 1.23 $ 0.97
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Nine Months Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 305,013 $ 296,402
Intersegment revenues 4,526 4,437
309,539 300,839
EXPENSES:
Power supply 99,726 102,706
Transmission and distribution 23,368 20,612
Selling, general and administrative 32,005 31,204
Taxes other than income taxes 34,878 34,807
Depreciation and amortization 35,814 31,878
225,791 221,207
INCOME FROM ELECTRIC OPERATIONS 83,748 79,632
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 70,413 61,694
Gas supply cost revenues 15,469 15,306
Intersegment revenues 463 658
86,345 77,658
EXPENSES:
Gas supply costs 15,469 15,306
Other production, gathering and exploration 6,921 7,139
Transmission and distribution 8,911 8,183
Selling, general and administrative 12,494 13,035
Taxes other than income taxes 11,379 10,898
Depreciation, depletion and amortization 8,995 8,093
64,169 62,654
INCOME FROM GAS OPERATIONS 22,176 15,004
INTEREST EXPENSE AND OTHER INCOME:
Interest 35,091 33,076
Other (income) deductions - net (1,602) (4,232)
33,489 28,844
INCOME BEFORE INCOME TAXES 72,435 65,792
INCOME TAXES 29,960 24,806
UTILITY NET INCOME $ 42,475 $ 40,986
</TABLE>
UTILITY OPERATIONS:
The Company earns most of its revenue in the first and fourth quarters of
the year. Weather can significantly affect revenues and net income, and should
be considered when analyzing trends. The Company's sales increase as a result
of colder weather in the winter months. As measured by heating degree days,
the 1996 temperature through September in the Company's service territory was
nine percent colder than normal and 10 percent colder than the same period in
1995.
The Company's electric wholesale revenues and power purchase expenses
are influenced by weather, streamflow conditions, and the wholesale power
market in the Northwest and California. The surplus of hydroelectric power
that existed in 1995 has continued into 1996 and is expected to continue
through the end of the year. However, market prices have increased to levels
where the Company expects to operate its thermal plants at or near full load
for the rest of 1996.
Electric Utility:
Excluding the impact of the coal arbitration decision recorded during
1995, income from electric operations benefited from increased tariff rates,
colder weather, continued customer growth and reduced power supply expenses.
Revenues:
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of electric revenues and the related
percentage changes in volumes sold and prices received:
General business - revenue $ 7
- volume (3)%
- price/kWh 6%
Other utilities - revenue $ 2
- volume 21%
- price/kWh (13)%
Total operating revenues increased three percent or $8,700,000.
Residential and commercial customer revenues were up $15,500,000 or 10 percent,
primarily as a result of a six percent increase in volumes sold due to colder
weather and two percent customer growth, along with increased tariff rates. See
Note 2 to the Consolidated Financial Statements for further discussion of
rates. Partially offsetting the increase was a decrease of $9,000,000 in
revenues from the industrial class principally due to a large retail customer
closing operations in December 1995. The customer was served under an
interruptible economic retention rate that was lower than the industrial tariff
rate.
Wholesale energy sales improved by approximately $2,000,000 or five
percent over last year primarily due to increased volumes sold offset by lower
regional energy prices. The increase was also offset by the expiration of two
firm sales contracts; one in late 1995 and the other in early 1996.
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (operation, fuel for electric generation and maintenance) for
the year-to-date September 30, 1996 and 1995.
1996 1995
Sources MWH
Hydroelectric 3,176,820 2,505,284
Steam 2,933,701 3,495,353
Purchases and other 1,854,389 1,766,996
Total Power Supply 7,964,910 7,767,633
Thousands of Dollars
Hydroelectric $ 14,604 $ 14,172
Steam 33,477 30,373
Purchases and other 51,645 58,161
Total Power Supply Expenses $ 99,726 $ 102,706
Cents Per Kilowatt-Hour 1.252 1.322
Excluding the impact of the coal contract arbitration decision that
reduced 1995 steam expenses $11,300,000, power supply expenses decreased
$14,300,000. Better streamflow conditions caused increases in Utility and
regional low-cost hydroelectric generation resulting in displacement of higher
cost thermal generation. Purchase power costs declined due to the expiration
of two higher-priced firm contracts. The decrease was partially offset by
increased lower-cost purchases of non-firm power for resale. Improved
productivity and shorter maintenance periods at the Colstrip units and a
$3,600,000 credit from a party who delivers energy to the Company's customers
also reduced power supply costs. Increased payments of $7,300,000 to
independent power producers partially offset these decreases.
Depreciation expense increased as a result of additional property in
service and a change in the MPSC approved depreciation rate. See Liquidity and
Capital Resources for further discussion.
Natural Gas Utility:
Income from natural gas operations increased primarily due to increased
volumes sold as the result of colder weather, customer growth and higher
tariffs.
Revenues:
The following table shows the change from the previous year, in millions
of dollars, in the full requirement customer classification of natural gas
revenues and the related percentage changes in volumes sold and prices
received:
Full requirement customers -revenue $ 8
-volume 12%
-price/Mcf 2%
Natural gas revenues (other than gas supply cost revenues) increased as a
result of increased volumes sold due to 10% colder weather, a 4.1 percent
increase in residential and commercial customers and higher tariff rates. See
Note 2 to the Consolidated Financial Statements for further discussion of
rates.
Depreciation expense increased for the same reasons mentioned in the
Electric Utility discussion.
Interest Expense and Other Income:
The increase in interest expense is primarily the result of additional
borrowings and a decrease in the amount capitalized on construction projects.
The decrease in other income resulted principally from the non-recurring
receipt of approximately $2,000,000 in interest income in 1995 under the coal
contract arbitration decision and a decrease in the amount capitalized on
construction projects.
Income Taxes:
Income taxes increased due to higher before tax net income and a higher
effective income tax rate due to regulatory accounting related to deferred
income taxes on depreciation.
<TABLE>
<CAPTION>
NON-UTILITY OPERATIONS
Nine Months Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 113,650 $ 157,211
Intersegment revenues 21,949 15,015
135,599 172,226
EXPENSES:
Operations and maintenance 82,683 120,315
Selling, general and administrative 16,166 21,307
Taxes other than income taxes 14,295 20,210
Depreciation, depletion and amortization 3,914 9,319
117,058 171,151
INCOME FROM COAL OPERATIONS 18,541 1,075
OIL AND NATURAL GAS:
REVENUES:
Revenues 87,153 72,841
Intersegment revenues 192 333
87,345 73,174
EXPENSES:
Operations and maintenance 53,372 43,142
Selling, general and administrative 7,479 6,811
Taxes other than income taxes 2,374 1,986
Depreciation, depletion and amortization 12,826 13,610
76,051 65,549
INCOME FROM OIL AND NATURAL GAS OPERATIONS 11,294 7,625
INDEPENDENT POWER:
REVENUES:
Revenues 56,773 59,481
Earnings from unconsolidated investments 8,991 1,079
Intersegment revenues 734 709
66,498 61,269
EXPENSES:
Operations and maintenance 47,861 50,556
Selling, general and administrative 3,805 2,465
Taxes other than income taxes 1,362 1,494
Depreciation, depletion and amortization 2,409 2,218
55,437 56,733
INCOME FROM INDEPENDENT POWER OPERATIONS $ 11,061 $ 4,53
NON-UTILITY OPERATIONS (continued)
Nine Months Ended
September 30,
1996 1995
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 19,169 $ 16,694
Intersegment revenues 296 246
19,465 16,940
EXPENSES:
Operations and maintenance 12,969 11,414
Selling, general and administrative 4,012 3,424
Taxes other than income taxes 272 245
Depreciation, depletion and amortization 673 585
17,926 15,668
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 1,539 1,272
OTHER NON-UTILITY:
REVENUES:
Revenues 931 1,926
Intersegment revenues 578 502
1,509 2,428
EXPENSES:
Operations and maintenance 869 1,193
Selling, general and administrative 1,553 187
Depreciation, depletion and amortization 507 676
2,929 2,056
INCOME (LOSS) FROM OTHER NON-UTILITY (1,420) 372
INTEREST EXPENSE AND OTHER INCOME:
Interest 3,508 3,779
Other (income) deductions - net (4,704) (6,567)
(1,196) (2,788)
INCOME BEFORE INCOME TAXES 42,211 17,668
INCOME TAXES 11,856 601
NON-UTILITY NET INCOME $ 30,355 $ 17,067
</TABLE>
NON-UTILITY OPERATIONS:
Coal:
Income from coal operations for the nine months ended increased as a
result of the non-recurring charges recorded during 1995 for the Colstrip 1 &
2 arbitration decision and the operating losses incurred at Golden Eagle Mine
in Colorado. Accruals for the permanent closure and write down to net salvage
value of the Golden Eagle Mine were recorded effective October 1995. The
increase was partially offset by lower sales to Colstrip Units 3 & 4, the
expiration of a Midwestern contract and decreased miscellaneous coal sales.
Revenues:
Excluding a non-recurring charge of approximately $20,700,000 recorded in
1995, as a result of the Colstrip Units 1 & 2 arbitration decision, revenues,
including intersegment revenues, decreased by $57,300,000. Rosebud Mine
revenues from Colstrip Units 3 & 4 decreased $13,600,000 due to a 39 percent
decline in volumes sold as a result of these Units being taken off line during
the period due to the availability of low-cost hydroelectric generation in the
region. The Company expects that these Units will be operated at or near full
load for the remainder of 1996. Rosebud Mine revenues also decreased
$13,600,000 due to the expiration of a Midwestern contract at the end of 1995
and approximately $10,800,000 due primarily to decreased short-term coal
sales, lower transportation fees and the switching of fuel supplier by the
Corette Plant for early compliance with air quality standards. The closure of
the Golden Eagle Mine also resulted in a $16,300,000 decrease in revenues.
Although volumes increased 4 percent, Jewett Mine revenues decreased
$2,700,000 principally as a result of a reduction in reimbursable mining
expenses and the mix of tons of lignite mined from Northwestern Resources'
leases and the customer's leases.
Expenses:
The closure of the Golden Eagle Mine resulted in a $22,900,000 decrease
in operation and maintenance, a $4,200,000 decrease in selling, general and
administrative, a $2,200,000 decrease in taxes other than income taxes and a
$2,400,000 decrease in depreciation and depletion. Despite a reduction in
1995 royalty expense and production taxes of approximately $7,000,000
resulting from the arbitration decision, the decrease in volumes sold in 1996
at the Rosebud Mine reduced operation and maintenance expenses by $13,200,000,
taxes other than income taxes by $2,800,000 and depreciation and depletion by
$2,300,000. Operation and maintenance expense at the Jewett Mine decreased
$1,700,000 due to reduced surface damage settlements and reduced royalties
resulting from the mix of tons mined. Expenses also decreased $2,400,000
primarily due to a reduction in taxes other than income taxes resulting from
an audit of Texas sales taxes, decreased leasehold abandonments and lower
selling, general and administrative expenses.
Oil and Natural Gas:
Income from oil and natural gas operations improved principally as a
result of increased volumes of natural gas sold and higher prices.
Revenues:
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 (6)%
-price/bbl 10%
Natural gas -revenue $ 13
-volume 13%
-price/Mcf 9%
Natural gas revenues for the nine months ended increased $13,200,000 due
to higher volumes sold in Canada resulting from intensified marketing efforts
and higher prices on gas sold in the U.S. The price increase in the U.S.
resulted primarily from an increase in prices on spot market sales as well as
a scheduled escalation in the price of gas sold under long-term co-generation
supply contracts. Higher oil prices in both the U.S. and Canada more than
offset the decrease in oil revenues resulting from a natural decline in
production from Canadian wells and the conversion of six U.S. oil wells to
waterflood injection wells. Production from a waterflood project is expected
to increase during the fourth quarter 1996.
Expenses:
Operating expenses increased primarily due to higher prices paid for the
gas in the U.S. and the increase in natural gas volumes purchased for resale.
Independent Power:
Net income from independent power operations increased primarily from
continued growth in earnings from investments in operating projects and the
absence of a non-recurring loss due to the withdrawal from a power investment
in the second quarter 1995. Also contributing to the improvement is a decrease
in operation and maintenance expense at the Colstrip Unit.
Revenues:
Revenues improved $7,900,000 primarily due to a $6,000,000 increase from
continued growth in earnings from investments in operating projects and a
$1,900,000 non-recurring loss recognized during second quarter 1995 as the
result of a withdrawal from a power investment. The increase was partially
offset by a decrease of $1,900,000 due to reduced volumes sold under long
term power sales agreements. In addition, 1995 revenues included $800,000
received under a transmission agreement which is absent from the 1996
revenues.
Expenses:
Operation and maintenance expense decreased $2,700,000, primarily due to
reductions of $2,100,000 in fuel expense and $600,000 in other plant operating
expenses. The decreases reflecting the displacement of higher-cost thermal
generation with lower-cost hydroelectric generation and lower transmission
expense, were partially offset by increases in power project development
expense and selling, general and administrative expense.
Telecommunications:
Earnings from telecommunications operations improved primarily as a
result of increased long-distance usage resulting from marketing efforts and
expansion into new service territories.
Quarter Ended September 30, 1996 and 1995:
Net Income Per Share of Common Stock:
Net income for the quarter ended September 30, 1996 was 30 cents per
share compared with 26 cents per share for the third quarter 1995. Non-Utility
earnings increased primarily due to the October 1995 closure of the Golden
Eagle coal mine in Colorado and the improved financial performance at the
Jewett Mine. The increase was partially offset by decreased coal sales at the
Rosebud Mine resulting from the expiration of a Midwestern coal contract and
reduced generation at the Colstrip units. Non-Utility earnings also benefited
from continued growth from existing independent power investments. A more
detailed discussion of the individual operations follows.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Quarter Ended
September 30,
1996 1995
Utility Operations $ 0.07 $ 0.08
Non-Utility Operations 0.23 0.18
Consolidated $ 0.30 $ 0.26
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Quarter Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 99,716 $ 94,593
Intersegment revenues 1,011 1,209
100,727 95,802
EXPENSES:
Power supply 32,981 34,549
Transmission and distribution 8,347 7,478
Selling, general and administrative 9,950 9,822
Taxes other than income taxes 11,459 11,532
Depreciation and amortization 12,719 10,627
75,456 74,008
INCOME FROM ELECTRIC OPERATIONS 25,271 21,794
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 13,212 12,408
Gas supply cost revenues 1,489 1,920
Intersegment revenues 105 118
14,806 14,446
EXPENSES:
Gas supply costs 1,489 1,920
Other production, gathering and exploration 2,230 1,949
Transmission and distribution 3,004 2,673
Selling, general and administrative 3,812 4,162
Taxes other than income taxes 3,658 3,626
Depreciation, depletion and amortization 3,135 2,692
17,328 17,022
INCOME (LOSS) FROM GAS OPERATIONS (2,522) (2,576)
INTEREST EXPENSE AND OTHER INCOME:
Interest 12,040 11,178
Other (income) deductions - net (141) (1,455)
11,899 9,723
INCOME BEFORE INCOME TAXES 10,850 9,495
INCOME TAXES 5,206 3,244
UTILITY NET INCOME $ 5,644 $ 6,251
</TABLE>
UTILITY OPERATIONS:
Electric Utility:
Income from electric operations increased primarily due to increased
operating revenues from residential, commercial and wholesale market classes
and reduced power supply expenses.
Revenues:
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of electric revenues and the related
percentage changes in volumes sold and prices received:
General business - revenue $ 3
- volume (2)%
- price/kWh 6%
Other utilities - revenue $ 2
- volume 38%
- price/kWh (16)%
Customer growth, increased tariff rates and air conditioning loads for
residential and commercial customers had a positive effect on revenue of
approximately $5,700,000 during the period. Industrial revenues decreased
$2,800,000, however, as the result of a large retail customer closing
operations in December 1995, as mentioned previously in the nine months ended
discussion.
Sales to other utilities increased for the reasons mentioned in the nine
months ended discussion.
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (operation, fuel for electric generation and maintenance) for
the quarter ended September 30, 1996 and 1995.
1996 1995
Sources MWH
Hydroelectric 932,622 884,600
Steam 1,229,635 1,296,196
Purchases and other 530,638 406,288
Total Power Supply 2,692,895 2,587,084
Thousands of Dollars
Hydroelectric $ 5,060 $ 4,907
Steam 12,556 12,968
Purchases and other 15,365 16,674
Total Power Supply Expenses $ 32,981 $ 34,549
Cents Per Kilowatt-Hour 1.225 1.335
Excluding a $1,200,000 credit received in the third quarter from the 1995
coal contract arbitration decision and $1,300,000 in related legal fees, total
power supply expenses decreased $1,400,000. Higher-priced steam generation was
displaced with low-cost wholesale hydroelectric power. Purchase power costs
declined due to the expiration of two higher-priced firm contracts. The
decrease was partially offset by increased lower-cost purchases of non-firm
power for resale and a $2,000,000 increase in payments to independent power
producers.
Depreciation expense for the period increased for the same reason
mentioned in the nine months ended discussion.
Natural Gas Utility:
Income from natural gas operations remained unchanged for the period.
Despite increased rates and customer growth, volumes sold during the summer
months are relatively small and, therefore, do not have a significant impact on
income.
Interest Expense and Other Income, and Income Taxes:
The increases in interest expense and income taxes and the decrease in
other income are for the same reasons mentioned in the nine months ended
discussion.
<TABLE>
<CAPTION>
NON-UTILITY OPERATIONS
Quarter Ended
September 30,
1996 1995
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 43,941 $ 55,095
Intersegment revenues 8,916 8,501
52,857 63,596
EXPENSES:
Operations and maintenance 29,853 40,599
Selling, general and administrative 5,611 6,743
Taxes other than income taxes 5,453 8,157
Depreciation, depletion and amortization 1,693 3,072
42,610 58,571
INCOME FROM COAL OPERATIONS 10,247 5,025
OIL AND NATURAL GAS:
REVENUES:
Revenues 28,684 25,363
Intersegment revenues 26 162
28,710 25,525
EXPENSES:
Operations and maintenance 17,921 15,419
Selling, general and administrative 2,547 2,261
Taxes other than income taxes 616 672
Depreciation, depletion and amortization 4,238 4,378
25,322 22,730
INCOME FROM OIL AND NATURAL GAS OPERATIONS 3,388 2,795
INDEPENDENT POWER:
REVENUES:
Revenues 18,773 20,170
Earnings (loss) from unconsolidated investments 3,132 1,354
Intersegment revenues 313 93
22,218 21,617
EXPENSES:
Operations and maintenance 16,375 17,332
Selling, general and administrative 1,939 1,093
Taxes other than income taxes 480 511
Depreciation, depletion and amortization 841 740
19,635 19,676
INCOME FROM INDEPENDENT POWER OPERATIONS $ 2,583 $ 1,941
NON-UTILITY OPERATIONS (continued)
Quarter Ended
September 30,
1996 1995
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 6,505 $ 5,954
Intersegment revenues 119 77
6,624 6,031
EXPENSES:
Operations and maintenance 4,470 4,117
Selling, general and administrative 1,289 1,148
Taxes other than income taxes 80 82
Depreciation, depletion and amortization 238 208
6,077 5,555
INCOME FROM TELECOMMUNICATIONS
OPERATIONS 547 476
OTHER NON-UTILITY:
REVENUES:
Revenues 348 344
Intersegment revenues 169 142
517 486
EXPENSES:
Operations and maintenance 314 248
Selling, general and administrative 253 87
Depreciation, depletion and amortization 168 238
735 573
INCOME (LOSS) FROM OTHER NON-UTILITY (218) (87)
INTEREST EXPENSE AND OTHER INCOME:
Interest 1,528 1,044
Other (income) deductions - net (2,361) (3,376)
(833) (2,332)
INCOME BEFORE INCOME TAXES 17,380 12,482
INCOME TAXES 4,795 2,581
NON-UTILITY NET INCOME $ 12,585 $ 9,901
</TABLE>
NON-UTILITY OPERATIONS:
Coal:
Income from coal operations for the quarter increased as a result of an
additional adjustment associated with the arbitration decision recorded in the
1995 period and the operating losses incurred at Golden Eagle Mine. The
increase was moderated primarily by the expiration of a Midwestern contract
and decreased miscellaneous coal sales.
Revenues:
Revenues for the quarter, including intersegment revenues, decreased by
$12,500,000, excluding the additional charge of approximately $1,800,000
resulting from the 1995 arbitration decision. The closure of the Golden Eagle
Mine also resulted in a $5,500,000 decrease in revenues. Revenues from the
Rosebud Mine decreased $3,700,000 due to the expiration of a Midwestern
contract. Rosebud Mine revenues also decreased $3,800,000 primarily to
decreased volumes of short-term coal sales, lower sales to Colstrip Units 3 &
4 due to unscheduled plant maintenance and the switching of fuel supplier by
the Corette Plant. Jewett Mine revenues increased $500,000 principally due to
an increase in tons sold.
Expenses:
The decrease in volumes sold at the Rosebud Mine and the closure of the
Golden Eagle Mine reduced operating expenses by $4,900,000 and $9,300,000,
respectively. Expenses also decreased $1,800,000 primarily due to reduced
royalties resulting from the mix of tons of lignite mined from Northwestern
Resources' leases and the customer's leases at the Jewett Mine.
Oil and Natural Gas:
Income from the oil and natural gas operations improved primarily due
to increased natural gas sales in Canada and increased oil production in the
U.S.
Revenues:
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 18%
-price/bbl 3%
Natural gas -revenue $ 2
-volume 8%
-price/Mcf 1%
The increase in natural gas revenues resulted primarily from higher
prices on sales in the U.S. and increased volumes of gas sold in Canada as
mentioned in the nine months ended discussion. The increase in oil revenues
results primarily from increased production from the acquisition of an
additional interest in production properties.
Expenses:
Operating expenses increased for the reasons mentioned in the nine
months ended discussion.
Independent Power:
Net income from independent power operations for the third quarter
increased primarily due to the reasons mentioned in the nine months ended
discussion.
Revenues:
Revenues from independent power operations increased $1,800,000
primarily from earnings from investments in operating projects. This increase
was partially offset by $1,200,000 lower revenues from long-term power sales
agreements.
Expenses:
The decline in operation and maintenance expense resulting primarily
from decreased transmission expenses was offset by an increase in selling,
general and administrative expense due primarily to higher legal costs and a
reduction in 1995 expense resulting from insurance proceeds.
LIQUIDITY AND CAPITAL RESOURCES:
The Company's wholly owned subsidiary, Touch America, Inc., is investing
$62,000,000 to expand its fiber optic network. Of this amount, $11,000,000 was
invested in previous years, $30,000,000 will be invested in 1996, and the
remainder will be invested in 1997 and 1998. These amounts reflect increases
of $15,000,000 for 1996, $7,000,000 for 1997 and $4,000,000 for 1998 over
amounts previously reported for Entech's capital budget projections (See Item
7, "Management's Discussion and Analysis of Financial Condition and Results of
Operations, Liquidity and Capital Resources" in the Company's Annual Report on
Form 10-K for the year ended December 31, 1995). The expansion will allow
access to markets extending from Seattle, Washington to St. Paul, Minnesota
and from Denver, Colorado to the Canadian Border, increasing the population of
the Company's market area from one to twelve million people. The expanded
network will provide partial service by the end of 1996 with full service
expected by mid-1997. Since the return on this investment is dependent upon
such future uncertainties as demand for service, competition and technological
change, it cannot be accurately estimated. However, the Company anticipates
that, because of existing long-term commitments for capacity on the expanded
network, its long-term return on this investment will exceed the 11 percent
allowed on the Company's regulated electric business.
The Company submitted its latest depreciation study as part of its rate
request filed with the MPSC on September 21, 1995. The MPSC approved and
included in rates the settlement of the depreciation study, effective July 1,
1996. The provision for utility depreciation will changed from approximately
2.7 percent of the depreciable utility plant to approximately 3.0 percent,
resulting in an increase in annual depreciation expense of approximately
$5,900,000.
During the third quarter of 1996, the Company borrowed $25,000,000
against its Non-Utility Revolving Credit Agreement to fund the external mine
reclamation fund required by the coal contract arbitration decision.
In early November 1996, the Company sold to the public, through a
subsidiary trust, Montana Power Capital I, $65,000,000 of 8.45% Cumulative
Quarterly Income Preferred Securities, Series A maturing on December 31, 2036.
The proceeds from the sale were used to purchase from the Company a like
amount of its Subordinated Debentures. Approximately $31,000,000 of the
proceeds from the purchase will be used to redeem in December all 1,200,000
outstanding shares of the Company's Preferred Stock, $2.15 Series, at $25.25
per share, plus accumulated dividends. The balance of the proceeds will be
used for general corporate purposes including the repurchase and retirement of
139,200 shares of the $6.875 Series Preferred Stock.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended September 30, 1996, the Company's ratio of
earnings to fixed charges was 2.29 times. Excluding the effects of the
implementation of Statement of Financial Accounting Standards No. 121 and the
writedown of a coal mining investment, effective October 1, 1995, the ratio of
earnings to fixed charges would have been 3.16 times. Fixed charges include
interest, the implicit interest of the Colstrip Unit 4 rentals and one-third of
all other rental payments.
UTILITY INDUSTRY CHANGES:
FERC issued its final open access rules, Order 888, on April 24, 1996.
Highlights of the final rules are:
1. Require public utilities to file a single open access tariff that
offers specific transmission services.
2. Permit transmitting utilities to seek to recover legitimate, prudent,
stranded investments that were incurred with a reasonable expectation
that the utility would continue to serve a particular customer.
3. Require public utilities to implement a transmission information
system. Utilities must obtain information about their transmission
the same way competitors do -- through the information system.
4. Do not require divestiture of assets but require utilities to
separate their transmission and generation functions from each other.
5. Do not require utilities to create an independent system transmission
operator (ISO) but establish principles concerning how an ISO should
be constructed.
The Company has taken the necessary steps to comply with all aspects of
the final ruling.
The Company has joined eight other Pacific Northwest electric utilities
in a memorandum of understanding to create an independent grid operator called
`IndeGo' for the utilities' high-voltage transmission lines. The grid operator
would be independent of the utilities, as required by the FERC.
PART II
Other Information
ITEM 1. Legal Proceedings.
Puget Sound Power and Light Power Sales Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Colstrip Units 3 and 4 Coal Arbitration
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Frederickson Litigation
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Basin Electric Power Cooperative Agreement Dispute
In 1994, the Company entered into an agreement to purchase 98 megawatts
of seasonal capacity from Basin Electric Power Cooperative (Basin), delivery
of which was to begin in November 1996. On October 31, 1996, the Company
notified Basin of the Company's rescission of the agreement as a consequence
of Basin's refusal to provide electricity at the delivery points the Company
had requested under the terms of the agreement. On November 5, 1996, Basin
sued the Company in the Federal District Court for the Southwestern District
of North Dakota. Basin seeks specific performance, a stay of the litigation
and an order compelling the Company to arbitrate the dispute. While confident
of its position, the Company cannot be certain of the decision in this
proceeding. This dispute is not expected to have a materially adverse affect
on the Company's financial position or results of operations.
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits
Exhibit 3(b)(1) Amendments to By-laws
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
September 30, 1996.
Exhibit 27 Financial Data Schedule
Exhibits and Reports on Form 8-K (continued)
(b) Reports on Form 8-K
DATE SUBJECT
July 24, 1996 Item 5. Other Events. Discussion of
Second Quarter Net Income.
Item 7. Exhibits. Consolidated Statements
of Income for the Quarters Ended June 30,
1996 and 1995, for the Six Months Ended
June 30, 1996 and 1995 and for the Twelve
Months Ended June 30, 1996 and 1995,
Utility Operations Schedule of Revenues
and Expenses for the Quarters Ended June
30, 1996 and 1995, for the Six Months
Ended June 30, 1996 and 1995 and for the
Twelve Months Ended June 30, 1996 and 1995
and Non-Utility Operations Schedule of
Revenues and Expenses for the Quarters
Ended June 30, 1996 and 1995, for the Six
Months Ended June 30, 1996 and 1995 and
for the Twelve Months Ended June 30, 1996
and 1995.
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)
/s/ J. P. Pederson
J. P. Pederson
Vice President and Chief Financial
and Information Officer
Date: November 14, 1996
EXHIBIT INDEX
Exhibit 3(b)(1)
Amendments to By-laws
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended September 30, 1996
Exhibit 27
Financial Data Schedule
- -20-
- -32-
Exhibit 3(b)(1)
BYLAWS
OF
THE MONTANA POWER COMPANY
Adopted on : August 22, 1995
As Amended on : August 27, 1996
THE MONTANA POWER COMPANY
AMENDED BYLAWS
Article Amendment Date of Amendment
11 The affairs of the Corporation shall be managed by August 27,
1996
a Board of fifteen (15) Directors. The Directors
shall be divided into three groups, each as nearly
equal in number as possible. Each group of
Directors shall stand for election upon
expiration of their terms. Directors shall hold
office for a term of three (3) years or until a
successor is duly elected and qualified.
THE MONTANA POWER COMPANY
CERTIFICATION OF RESOLUTION
I, R. M. Ralph, Assistant Secretary of The Montana Power Company,
a corporation, hereby certify that the following is a full, true and
correct copy of Resolution duly adopted by the Board of Directors of The
Montana Power Company at a meeting duly called and held August 27, 1996
and that said Resolution is in full force and effect as of the date of
this certificate.
RESOLVED, that effective August 27, 1996, the first sentence of
Section 11 of the Bylaws of The Montana Power Company is hereby amended to
reduce the number of Directors to fifteen (15) as follows:
SECTION 11. The affairs of the Corporation shall be managed by
a Board of fifteen (15) Directors.
IN WITNESS WHEREOF, I have hereunto set my hand and the Seal of said
Corporation this 11th day of November, 1996.
/s/R. M. Ralph, Assistant
Secretary
(SEAL)
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
September 30,1996
Net Income $ 72,594
,
Income Taxes 37,983
$ 110,577
Fixed Charges:
Interest $ 49,468
Amortization of Debt Discount,
Expense and Premium 1,570
Rentals 34,585
$ 85,623
Earnings Before Income Taxes
and Fixed Charges $196,200
Ratio of Earning to Fixed Charges 2.29 x
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY INFORMATION EXTRACTED FROM THE CONSOLIDATED
BALANCE SHEET AT 9/30/96, THE CONSOLIDATED INCOME STATEMENT AND CONSOLIDATED
STATEMENT OF CASH FLOWS FOR THE NINE MONTHS ENDED 9/30/96 AND IS QUALIFIED IN
ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-31-1996
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,562,151
<OTHER-PROPERTY-AND-INVEST> 546,307
<TOTAL-CURRENT-ASSETS> 228,348
<TOTAL-DEFERRED-CHARGES> 292,355
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,629,161
<COMMON> 691,952
<CAPITAL-SURPLUS-PAID-IN> 2,224
<RETAINED-EARNINGS> 255,739
<TOTAL-COMMON-STOCKHOLDERS-EQ> 949,915
0
101,416
<LONG-TERM-DEBT-NET> 623,581
<SHORT-TERM-NOTES> 119,828
<LONG-TERM-NOTES-PAYABLE> 3,480
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 22,873
0
<CAPITAL-LEASE-OBLIGATIONS> 1,805
<LEASES-CURRENT> 717
<OTHER-ITEMS-CAPITAL-AND-LIAB> 805,546
<TOT-CAPITALIZATION-AND-LIAB> 2,629,161
<GROSS-OPERATING-REVENUE> 678,397
<INCOME-TAX-EXPENSE> 41,817
<OTHER-OPERATING-EXPENSES> 531,458
<TOTAL-OPERATING-EXPENSES> 573,275
<OPERATING-INCOME-LOSS> 105,122
<OTHER-INCOME-NET> 4,146
<INCOME-BEFORE-INTEREST-EXPEN> 109,268
<TOTAL-INTEREST-EXPENSE> 36,438
<NET-INCOME> 72,830
5,420
<EARNINGS-AVAILABLE-FOR-COMM> 67,410
<COMMON-STOCK-DIVIDENDS> 65,579
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 186,580
<EPS-PRIMARY> 1.23
<EPS-DILUTED> 1.23
</TABLE>
